a.gene collins - geochemistry of oil field waters

Developments in Petroleum Science, 1

GEOCHEMISTRY OF OILFIELD WATERS

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Developments in Petroleum Science, 1

GEOCHEMISTRY OF OILFIELD WATERS

A. GENE COLLINS

Bartlesville Energy Research Center Bureau of Mines United States Department of the Interior Bartlesville, Oklahoma, U.S.A.

ELSEVIER SCIENTIFIC PUBLISHING COMPANY

Amsterdam - Oxford - New York 1975

ELSEVIER SCIENTIFIC PUBLISHING COMPANY 335 Jan van Galenstraat P.O. Box 211, Amsterdam, The Netherlands

AMERICAN ELSEVIER PUBLISHING COMPANY, INC. 52 Vanderbilt Avenue New York, New York 10017

Library of Congress Card Number: 73-89149

ISBN 0-444-41183-6

With 132 illustrations and 87 tables

Copyright 0 1975 by Elsevier Scientific Publishing Company, Amsterdam All rights reserved. No part of this publication may be reproduced, stored in a retrieva system, or transmitted, in any form or by any means, electronic, mechanical, photo copying, or otherwise without the prior written permission of the publisher, Elseviei Scientific Publishing Company, Jan van Galenstraat 335, Amsterdam

Printed in The Netherlands

PREFACE

The purpose of this book is to provide information relevant to the analytical chemistry and geochemistry of oilfield waters. The book attempts to recognize the importance of subsurface oilfield waters as they are related to origin, migration, accumulation, and maturation of oil and gas and thus their relationship t o exploration for and production of oil and gas. One chapter presents a simplistic introduction to the origin of oilfield waters. Because oilfield waters can constitute an environmental pollution hazard, the book describes and comments on methods of their disposal or of recovering valuable constituents from them.

The numerous references indicate that the book relies heavily upon the work of others. The reader will vastly expand his knowledge of the subject by consulting these references.

The writer appreciates the understanding and thoughtfulness of his Wife, Barbara, and children, Sandy and Mike, during the preparation of part of this book at our home. He acknowledges With appreciation the criticisms, opin- ions, and suggestions of various portions of the book by O.C. Baptist, W.H. Caraway, P.H. Dickey, G.L. Gates, R.V. Huff, P.H. Jones, and C.C. Linville. M.E. Crocker and Ms. C.A. Pearson, did an invaluable service of proof-reading and index preparation. He extends appreciation to Ms. D.J. Forbes, Ms. M.G. Goff, and Ms. J. Haimson for typing the manuscript; to D.W. Anderson, Ms. E.S. Baldwin, J.A. Chidester, G.E. Fletcher, R.M. Horn, and W.A. McClung for preparing the figures; and to authors, book publishers, companies, and technical journals who granted permission to use various illustrations.

Permission to publish this manuscript was granted by the Director of the United States Bureau of Mines. Bureau of Mines officials who generously helped obtain this permission were: J.S. Ball, R.T. Johansen, and J.W. Watkins.

Finally inasmuch as it is the writer’s belief that this book is not perfect, he takes this opportunity to solicit constructive criticism from its readers.

A. GENE COLLINS Bartlesville Energy Research Center

U.S. Bureau of Mines Bartlesville, Oklahoma

CONTENTS

Preface . . . . . . . . . . . . . . . . . . . . . . . . . . V

Chapter 1 . Introduction . . . . . . . . . . . . . . . . . . . . 1 References . . . . . . . . . . . . . . . . . . . . . . . . . 5

Chapter 2 . Sampling subsurface oilfield waters . . . . . . . . . . . . . 7 Drill-stem test . . . . . . . . . . . . . . . . . . . . . . . 8 Sample containing dissolved gases . . . . . . . . . . . . . . . . . 12 Sampling at the flow line . . . . . . . . . . . . . . . . . . . . 13 Sampling at the wellhead . . . . . . . . . . . . . . . . . . . . 14

Sample for stable-isotope analysis . . . . . . . . . . . . . . . . . 15 Sample containers . . . . . . . . . . . . . . . . . . . . . . 16 Tabulation of sample description . . . . . . . . . . . . . . . . . 17 References . . . . . . . . . . . . . . . . . . . . . . . . . 17

Sample for determining unstable properties or species . . . . . . . . . . . 14

Chapter 3 . Analysis of oilfield waters for some physical properties and inorganic chemical constituents . . . . . . . . . . . . . . . . . 19

Quality control . . . . . . . . . . . . . . . . . . . . . . . 19 Preliminary sample treatment . . . . . . . . . . . . . . . . . . . 22 Reporting the analytical results . . . . . . . . . . . . . . . . . . 25 Synthetic brine . . . . . . . . . . . . . . . . . . . . . . . 27 Determination of pH . . . . . . . . . . . . . . . . . . . . . 27 Determination of Eh . . . . . . . . . . . . . . . . . . . . . 29 Suspended solids . . . . . . . . . . . . . . . . . . . . . . . 31 Resistivity . . . . . . . . . . . . . . . . . . . . . . . . . 32 Specific gravity . . . . . . . . . . . . . . . . . . . . . . . 35 TITRIMETRIC METHODS . . . . . . . . . . . . . . . . . . . 37 Acidity. alkalinity. and borate boron . . . . . . . . . . . . . . . . 37 Calcium and magnesium . . . . . . . . Ammonium nitrogen . . . . . . . . . Chloride . . . . . . . . . . . . . . Bromide and iodide . . . . . . . . . . Oxygen . . . . . . . . . . . . . . Carbon dioxide . . . . . . . . . . . Sulfide . . . . . . . . . . . . . . Sulfur compounds . . . . . . . . . . FLAME SPECTROPHOTOMETRIC .METHODS Lithium . . . . . . . . . . . . . . Sodium . . . . . . . . . . . . . . Potassium . . . . . . . . . . . . . Rubidium and cesium . . . . . . . . . Manganese . . . . . . . . . . . . . Strontium . . . . . . . . . . . . . Barium . . . . . . . . . . . . . .

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VIII CONTENTS

ATOMIC ABSORPTION METHODS . . . . . . . . . . . . . . . . 65 Interferences . . . . . . . . . . . . . . . . . . . . . . . . 66 Burners and solvents . . . . . . . . . . . . . . . . . . . . . . 66 Lithium . . . . . . . . . . . . . . . . . . . . . . . . . . . 68 Sodium . . . . . . . . . . . . . . . . . . . . . . . . . . 68 Potassium . . . . . . . . . . . . . . . . . . . . . . . . . 70 Magnesium (1) . . . . . . . . . . . . . . . . . . . . . . . . 71 Calcium (1) . . . . . . . . . . . . . . . . . . . . . . . . . . 72 Magnesium (2) . . . . . . . . . . . . . . . . . . . . . . . . 74 Calcium (2) . . . . . . . . . . . . . . . . . . . . . . . . . 75 Strontium . . . . . . . . . . . . . . . . . . . . . . . . . 76 Barium . . . . . . . . . . . . . . . . . . . . . . . . . . 77 Manganese . . . . . . . . . . . . . . . . . . . . . . . . . 78 Iron . . . . . . . . . . . . . . . . . . . . . . . . . . . 79 Copper . . . . . . . . . . . . . . . . . . . . . . . . . . 80 Zinc . . . . . . . . . . . . . . . . . . . . . . . . . . . 80 Lead(1) . . . . . . . . . . . . . . . . . . . . . . . . . . 81 Lead(2) . . . . . . . . . . . . . . . . . . . . . . . . . : 82 EMISSION SPECTROSCOPY . . . . . . . . . . . . . . . . . . . 83 Barium, boron, iron, manganese, and strontium . . . . . . . . . . . . . 83 Beryllium . . . . . . . . . . . . . . . . . . . . . . . . . 89 Aluminum . . . . . . . . . . . . . . . . . . . . . . . . . 90 MASS SPECTROMETRIC METHODS FOR STABLE ISOTOPES . . . . . . . 91 Deuterium . . . . . . . . . . . . . . . . . . . . . . . . . 91 Oxygen-18 . . . . . . . . . . . . . . . . . . . . . . . . . 91 COLORIMETRIC METHODS . . . . . . . . . . . . . . . . . . 92 Interferences . . . . . . . . . . . . . . . . . . . . . . . . 93 Iron . . . . . . . . . . . . . . . . . . . . . . . . . . . 94 Copper . . . . . . . . . . . . . . . . . . . . . . . . . . 96 Nickel . . . . . . . . . . . . . . . . . . . . . . . . . . 98 Lead . . . . . . . . . . . . . . . . . . . . . . . . . . . 99 Zinc . . . . . . . . . . . . . . . . . . . . . . . . . . . 101 Cadmium . . . . . . . . . . . . . . . . . . . . . . . . . 103 Phosphate . . . . . . . . . . . . . . . . . . . . . . . . . 105 Silica . . . . . . . . . . . . . . . . . . . . . . . . . . . 107 Nitrate nitrogen . . . . . . . . . . . . . . . . . . . . . . . 107 Arsenic . . . . . . . . . . . . . . . . . . . . . . . . . . 108 Fluoride . . . . . . . . . . . . . . . . . . . . . . . . . . 109 Iodide . . . . . . . . . . . . . . . . . . . . . . . . . . 110 Selenium . . . . . . . . . . . . . . . . . . . . . . . . . 111 Barium . . . . . . . . . . . . . . . . . . . . . . . . . . 114 GRAVIMETRIC METHODS . . . . . . . . . . . . . . . . . . . 114 Sulfate . . . . . . . . . . . . . . . . . . . . . . . . . . 114 Barium . . . . . . . . . . . . . . . . . . . . . . . . . . 115 OTHER METHODS . . . . . . . . . . . . . . . . . . . . . . 116 Sodium . . . . . . . . . . . . . . . . . . . . . . . . . . 116 Dissolved solids . . . . . . . . . . . . . . . . . . . . . . . 117 Spent acid . . . . . . . . . . . . . . . . . . . . . . . . . 118 Acetic acid solutions . . . . . . . . . . . . . . . . . . . . . . 120 References . . . . . . . . . . . . . . . . . . . . . . . . . 121

Chapter 4 . Interpretation of chemical analysis of oilfield waters . . . . . . . 125 Calculating probable compounds . . . . . . . . . . . . . . . . . 125

CONTENTS IX

Determining a sought compound . . . . . . . . . . . . . . . . . 127 Graphic plots . . . . . . . . . . . . . . . . . . . . . . . . 128 References . . . . . . . . . . . . . . . . . . . . . . . . . 132

Chapter 5 . Significance of some inorganic constituents and physical properties of oilfield waters . . . . . . . . . . . . . . . . . . . . . 133

Lithium . . . . . . . . . . . . . . . . . . . . . . . . . . 133 Sodium . . . . . . . . . . . . . . . . . . . . . . . . . . 136 Potassium . . . . . . . . . . . . . . . . . . . . . . . . . 138 Rubidium . . . . . . . . . . . . . . . . . . . . . . . . . 140 Cesium . . . . . . . . . . . . . . . . . . . . . . . . . . 141 Beryllium . . . . . . . . . . . . . . . . . . . . . . . . . 141 Magnesium . . . . . . . . . . . . . . . . . . . . . . . . . 142 Calcium . . . . . . . . . . . . . . . . . . . . . . . . . . 143 Strontium . . . . . . . . . . . . . . . . . . . . . . . . . 145 Barium . . . . . . . . . . . . . . . . . . . . . . . . . . 147 Manganese . . . . . . . . . . . . . . . . . . . . . . . . . 149 Iron . . . . . . . . . . . . . . . . . . . . . . . . . . . 149 Copper . . . . . . . . . . . . . . . . . . . . . . . . . . 150 Zinc . . . . . . . . . . . . . . . . . . . . . . . . . . . 151 Mercury . . . . . . . . . . . . . . . . . . . . . . . . . . 151 Lead . . . . . . . . . . . . . . . . . . . . . . . . . . . 152 Cadmium . . . . . . . . . . . . . . . . . . . . . . . . . 152 Boron . . . . . . . . . . . . . . . . . . . . . . . . . . 153 Aluminum . . . . . . . . . . . . . . . . . . . . . . . . . 155 Silica . . . . . . . . . . . . . . . . . . . . . . . . . . . 156 Ammonium nitrogen . . . . . . . . . . . . . . . . . . . . . 157 Phosphorus . . . . . . . . . . . . . . . . . . . . . . . . . 158 Arsenic . . . . . . . . . . . . . . . . . . . . . . . . . . 158 Oxygen . . . . . . . . . . . . . . . . . . . . . . . . . . 158 Sulfur . . . . . . . . . . . . . . . . . . . . . . . . . . 159 Selenium . . . . . . . . . . . . . . . . . . . . . . . . . 160 Fluorine . . . . . . . . . . . . . . . . . . . . . . . . . . 161 Chlorine . . . . . . . . . . . . . . . . . . . . . . . . . . 161 Bromine . . . . . . . . . . . . . . . . . . . . . . . . . . 162 Iodine . . . . . . . . . . . . . . . . . . . . . . . . . . 164 Significance of some physical properties . . . . . . . . . . . . . . . 166 References . . . . . . . . . . . . . . . . . . . . . . . . . 174

Chapter 6 . Organic constituents in saline waters . . . . . . . . . . . . . 177 Nitrogen-free organic compounds . . . . . . . . . . . . . . . . . 178 Hydrocarbons containing nitrogen . . . . . . . . . . . . . . . . . 182 Fatty acids . . . . . . . . . . . . . . . . . . . . . . . . . 183 Naphthenic and humic acids . . . . . . . . . . . . . . . . . . . 185 Determination of oil in water . . . . . . . . . . . . . . . . . . . 186 Organic acids in oilfield brines . . . . . . . . . . . . . . . . . . 188 References . . . . . . . . . . . . . . . . . . . . . . . . . 188

Chapter 7 . Origin of oilfield waters . . . . . . . . . . . . . . . . . 193 Definitions of some water terms . . . . . . . . . . . . . . . . . . 194 Sedimentary rocks . . . . . . . . . . . . . . . . . . . . . . 195 Composition of oilfield waters . . . . . . . . . . . . . . . . . . 213 Research studies related to the originof oilfield brines . . . . . . . . . . 219

X CONTENTS

Conclusions . . . . . . . . . . . . . . . . . . . . . . . . 245 References . . . . . . . . . . . . . . . . . . . . . . . . . 246

Chapter 8 . Classification of oilfield waters Palmer’s classification . . . . . . . Sulin’s classification . . . . . . . . Modification of Sulin’s system by Bojarski Chebotarev’s classification . . . . . . Schoeller’s system . . . . . . . . Oilfield brine analyses . . . . . . . Application of the classification systems . Discussion . . . . . . . . . . . Conclusions . . . . . . . . . . References . . . . . . . . . . .

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253 254 257 260 262 267 272 274 289 291 291

Chapter 9 . Some effects of water upon the generation. migration. accumulation. and alteration of petroleum . . . . . . . . . . . . . . . . . 293

Compaction . . . . . . . . . . . . . . . . . . . . . . . . 294 Generation and migration . . . . . . . . . . . . . . . . . . . . 295 Accumulation . . . . . . . . . . . . . . . . . . . . . . . . 298 Alteration . . . . . . . . . . . . . . . . . . . . . . . . . 299 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . 304 References . . . . . . . . . . . . . . . . . . . . . . . . . 304

Chapter 10 . Geochemical methods of exploration for petroleum and natural gas . . 307 Introduction . . . . . . . . . . . . . . . . . . . . . . . . 307 Hydrogeochemical research and methods . . . . . . . . . . . . . . . 313 Reviews . . . . . . . . . . . . . . . . . . . . . . . . . . 322 Case history of the Delaware sand (Bell Canyon formation). Texas. by Visher (1961) 322 Formation water maps of others areas . . . . . . . . . . . . . . . . 330 Concluding remarks . . . . . . . . . . . . . . . . . . . . . . 335 References . . . . . . . . . . . . . . . . . . . . . . . . . 337

Chapter 11 . Geopressured reservoirs . . . . . . . . . . . . . . . . 343 Geopressure . . . . . . . . . . . . . . . . . . . . . . . . 343 Origin of abnormal pressures . . . . . . . . . . . . . . . . . . . 344 Abnormal pressures in the Gulf Coast area . . . . . . . . . . . . . . 346 Detection of abnormal pressures . . . . . . . . . . . . . . . . . . 362 References . . . . . . . . . . . . . . . . . . . . . . . . . 364

Chapter 12 . Compatibility of oilfield waters . . . . . . . . . . . . . . 367 Wellbore and formation damage . . . . . . . . . . . . . . . . . . 368 Solubility of calciumcompounds invarioussaltsolutions . . . . . . . . . 370 Solubilities of the sulfates of barium and strontium in saline solutions . . . . . 372 Experimental determination of some solubilities of the sulfates of barium and strontium . . . . . . . . . . . . . . . . . . . . . . . . . 372

373 Brine stabilization . . . . . . . . . . . . . . . . . . . . . . 380 Mixing of subsurface waters . . . . . . . . . . . . . . . . . . . 382 References . . . . . . . . . . . . . . . . . . . . . . . . . 386

Resultsand discussion of the experimental investigation . . . . . . . . . .

Chapter 13 . Valuable minerals in oilfield waters . . . . . . . . . . . . . 389 Recovery of iodine and bromine from oilfield brines . . . . . . . . . . . 390

CONTENTS XI

Minerals recovered from saline waters . . . . . . . . . . . . . . . . . 392 Fresh-water production . . . . . . . . . . . . . . . . . . . . . 401 Preliminary economic evaluation . . . . . . . . . . . . . . . . . 402 Disposal brines . . . . . . . . . . . . . . . . . . . . . . . 411 Worth and value estimates . . . . . . . . . . . . . . . . . . . . 411 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . 417 References . . . . . . . . . . . . . . . . . . . . . . . . . 417

Chapter 14 .Subsurface disposal . . . . . . . . . . . . . . . . . . History of brine disposal operations . . . . . . . . . . . . . . . . 419 Subsurface injection . . . . . . . . . . . . . . . . . . . . . . 420

Economics and oilfield brine disposal . . . . . . . . . . . . . . . . 422 Injection well versus disposal well . . . . . . . . . . . . . . . . . 424 Acceptable geologic areas . . . . . . . . . . . . . . . . . . . . 425 Suitable disposal zones . . . . . . . . . . . . . . . . . . . . . 426 Evaluation of the disposal zone . . . . . . . . . . . . . . . . . . 427 Considerations during drilling and well completion . . . . . . . . . . . . 432 Fluid travel . . . . . . . . . . . . . . . . . . . . . . . . . 433 Hazards of underground waste disposal . . . . . . . . . . . . . . . 434 State regulations and tax incentives . . . . . . . . . . . . . . . . . 434 Costs of disposal systems . . . . . . . . . . . . . . . . . . . . 437 Conclusions . . . . . . . . . . . . . . . . . . . . . . . . 438 References . . . . . . . . . . . . . . . . . . . . . . . . . 438

419

Present-day technology in subsurface disposal . . . . . . . . . . . . . 421

Chapter 15 . Solubilities of some silicate minerals in saline waters Composition and structure of minerals studied . . . . . . Silicate solubilities a t 25°C and 1 atm . . . . . . . . . Experimental equipment . . . . . . . . . . . . . Experimental method . . . . . . . . . . . . . . Fundamental equations . . . . . . . . . . . . . . Experimental dataandempirical equations . . . . . . . Summary and conclusions . . . . . . . . . . . . . References . . . . . . . . . . . . . . . . . .

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Chapter 16 . Environmental impact of oil- and gas-well drilling. production and associated waste disposal practices . . . . . . . . . . . . . 461

Drilling . . . . . . . . . . . . . . . . . . . . . . . . . . 461 Production . . . . . . . . . . . . . . . . . . . . . . . . . 467 Disposal . . . . . . . . . . . . . . . . . . . . . . . . . . 471 References . . . . . . . . . . . . . . . . . . . . . . . . . 474

Reference Index . . . . . . . . . . . . . . . . . . . . . . . 477 Subject Index * 485 . . . . . . . . . . . . . . . . . . . . . . .

Chapter 1. INTRODUCTION

Petroleum, known to exist long before an oil well was drilled, first found limited use as a medicine, lubricant, and waterproofing agent. The American Indians knew of several oil and gas springs and gave this information to the early American settlers. Early settlements were commonly located close to salt licks which supplied salt to the population. Often these salt springs were contaminated with petroleum, and many of the early efforts to acquire more salt by digging wells were rewarded by finding unwanted increased amounts of oil and gas associated with the saline waters. In the Appalachians: many saline water springs occurred along the crests of anticlines (Rogers and Rogers, 1843).

In 1855 it was found that distillation of petroleum produced a light oil similar to coal oil, which was better than whale oil as an illuminant (Howell, 1934, p.2). This knowledge spurred the search for saline waters which contained oil. Colonel Edward Drake, utilizing the methods of the salt producers, drilled a well on Oil Creek, near Titusville, Pennsylvania, in 1859. He struck oil at a depth of 21 m, and this first oil well produced about 35 barrels of oil per day (Dickey, 1959).

The early oil producers did not realize the significance of the oil and saline waters occurring together. In fact, it was not until 1938 that the existence of interstitial water in oil reservoirs was generally recognized (Schilthuis, 1938). Torrey (1966) was convinced as early as 1928 that dispersed interstitial water existed in oil reservoirs, but his belief was rejected by his colleagues because most of the producing oil wells did not produce any water upon completion. Occurrences of mixtures of oil and gas with water were recognized by Griswold and Munn (1907), but they believed that there was a definite separation of the oil and water, and that oil, gas, and water mixtures did not occur in the sand before a well tapped the reservoir.

It was not until 1928 that the first commercial laboratory for the analysis of rock cores was established (Torrey, 1966); the first core tested was from the Bradford Third Sand (from the Bradford field, McKean County, Pennsyl- vania). The percent saturation and percent porosity of this core were plotted versus depth to construct a graphic representation of the oil and water saturation. The soluble mineral salts that were extracted from the core led Torrey to suspect that water was indigenous to the oil productive sand. Shortly thereafter a test well was drilled near Custer City, Pennsylvania, which encountered higher than average oil saturation in the lower part of the Bradford Sand. This high oil saturation resulted from the action of an un-

2 INTRODUCTION

suspected flood, the existence of which was not known when the location for the test well had been selected. The upper part of the sand was not cored. Toward the end of the cutting of the first core with a Baker cable tool core barrel, oil began to come into the hole so fast that it was not necessary to add water for the cutting of the second section of the sand. The lower 1 m of the Bradford Sand therefore was cut with oil in a hole free from water. Two samples from this section were preserved in sealed containers for saturation tests, and both of them, when analyzed, had a water content of approximately 20% of pore volume. This well made about 10 barrels of oil per day and no water after being shot with nitroglycerine. Thus, the evidence developed by the core analysis and the productivity test after completion provided a satisfactory indication of the existence of immobile water, indigenous to the Bradford Sand oil reservoir, which was held in its pore system and which could not be produced by conventional pumping methods (Torrey, 1966).

Fettke (1938) was the first to report the presence of water in an oil- producing sand. However, he thought that it might have been introduced by the drilling process.

I t was recognized by Munn (1920) that moving underground water might be the primary cause of migration and accumulation of oil and gas. However, this theory had little experimental data to back it until Mills (1920) conducted several laboratory experiments on the effect of moving water and gas on water-oil-as-sand and water-oil-sand systems. Mills concluded that “the up-dip migration of oil and gas under the propulsive force of their buoyancy in water, as well as the migration of oil, either up or down dip, caused by hydraulic currents, are among the primary factors influencing both the accumulation and the recovery of oil and gas.” This theory was seriously questioned and completely rejected by many of his con- temporaries.

Rich (1923) postulated that “hydraulic currents, rather than buoyancy, are effective in causing accumulation of oil or its retention.” He did not believe that the hydraulic accumulation and flushing of oil required a rapid movement of water, but rather that the oil was an integral constituent of the rock fluids and that it could be carried along with them whether the movement was very slow or relatively rapid.

The effect of water displacing oil during production was not recognized in the early days of the petroleum industry in Pennsylvania. Laws were passed, a

however, to prevent operators from injecting water into the oil reservoir sands through unplugged wells. In spite of these laws, some operators at Bradford surreptitiously opened the well casing opposite shallow groundwater sands in order to start a waterflood in the oil sands. Effects of artificial waterfloods were noted in the Bradford field, McKean County, Pennsylvania, in 1907, and became evident about 5 years later in the nearby oilfields of New York (Torrey, 1950). Volumetric calculations of the oil-reservoir volume which were made for engineering studies of these waterflood opera-

INTRODUCTION 3

tions proved that interstitial water was generally present in the oil sands. Publications by Garrison (1935) and Schilthuis (1938) give detailed information concerning the distribution of water and oil in porous rocks, and of the origin and occurrence of “connate” water with information concerning the relationship of water saturation to formation permeability.

The word “connate” was first used by Lane and Gordon (1908) to mean interstitial water that was deposited with the sediments. The processes of rock compaction and mineral diagenesis result in the expulsion of large amounts of water from sediments and movement out of the deposit through the more permeable rocks. I t is therefore highly unlikely that the water now in any pore is the same as that which was there when the particles that surround it were deposited. White (1957) redefined connate water as “fossil” water; it has been out of contact with the atmosphere for an appreciable part of a geologic time period. Connate water is thus distinguished from meteoric water which has entered the rocks in geologically recent times, and from juvenile water which has come from deep in the earth’s crust and has never been in contact with the atmosphere.

Meanwhile petroleum engineers and geologists had learned that waters associated with petroleum could be identified with regard to the reservoir in which they occurred by a knowledge of their chemical characteristics. Com- monly the waters from different strata differ considerably in their dissolved chemical constituents, making the identification of a water from a particular strata easy. However, in some areas the concentrations of dissolved constituents in waters from different strata do not differ significantly, and the identification of such waters is difficult or impossible.

The amount of water produced with the oil often increases as the amount of oil produced decreases. If this is edge water, nothing can be done about it. If it is bottom water, the well can be plugged back. However, it often is intrusive water from a shallow sand gaining access to the well from a leaky casing or faulty completion and this can be repaired.

Enormous quantities of water are produced with the oil in some fields, and it is necessary to separate the oil from the water. Most of the oil can be removed by settling. Often, however, an oil-in-water emulsion forms which is very difficult to break. In such cases, the oil is heated and various surfaceactive chemicals are added to induce separation.

In the early days, the water was dumped on the ground where it seeped below the land surface. Until about 1930, the oilfield waters were disposed into local drainage, frequently killing fish and even surface vegetation. After 1930, it became common practice to evaporate the water in earthen pits or to inject it into the producing sand or another deep aquifer. The primary concern in such disposal practice is to remove all oil and basic sediment from the waters before pumping them into injection wells, to prevent clogging of the pore spaces in the formation receiving the waste water. Chemical compatibility of waste water and host aquifer water must also be assured.

Waters produced with petroleum are growing in importance. In years past,

4 INTRODUCTION

these waters were considered waste and had to be disposed of in some manner. Injection of these waters into the petroleum reservoir rock serves three purposes: (1) it produces additional petroleum (secondary recovery); (2) it utilizes a potential pollutant; and (3) in some areas it controls land subsidence.

The volume of water produced with petroleum in the United States is very large. In 1970, daily production was about 3.78 trillion liters of water with about 1.51 trillion liters of oil. In older fields, the production is frequently 95% water and 5% petroleum. . Waterflooding in petroleum production is expanding rapidly, and in 1970 one-third to one-half of the production in the United States came from fields into which water was injected. The volume of injected water has grown each year. In many fields the volume of petroleum produced by secondary recovery by waterflooding is equal to the volume recovered by primary met hods.

To inject these waters into reservoir rocks, suspended solids and oil must be removed from the waters to prevent plugging of the porous formations. Water injection systems require separators, filters, and, in some areas, deoxygenating equipment utilizing chemical and physical control methods to minimize corrosion and plugging in the injection system.

In waterflooding most petroleum reservoirs, the volume of produced water is not sufficient to efficiently recover the additional petroleum. There. fore, supplemental water must be added t o the petroleum reservoir. The use of waters from other sources requires that the blending of the produced water with supplemental water must yield a chemically stable mixture so that plugging solids will not be formed. For example, a produced water containing considerable calcium should not be mixed with a water containing considerable carbonate because calcium carbonate may precipitate and prevent injection of the flood water. The design and successful operation of a secondary recovery waterflood requires a thorough knowledge of the composition of the waters used.

Chemical analyses of waters produced with oil are useful in oil production problems, such as identifying the source of intrusive water, planning waterflood and salt-water disposal projects, and treating to prevent corrosion problems in primary and secondary recovery. Electrical well-log interpreta tion requires a knowledge of the dissolved solids concentration and composi tion of the interstitial water. Such information also is useful in correlationof stratigraphic units and of the aquifers within these units, and in studiesof the movement of subsurface waters. It is impossible to understandthe processes that accumulate petroleum or other minerals without insight in to the nature of these waters.

REFERENCES 5

References

Dickey, P.A., 1959. The first oil well. J. Pet. Technol., 11:14-26. Fettke, C.R., 1938. Bradford oil field, Pennsylvania, and New York. Pa. Geol. Surv.,

Fourth Ser., Bull., M21:l-454. Garrison, A.D., 1935. Selective wetting of reservoir rock and its relation to oil produc-

tion. In: Drilling and Production Practice. American Petroleum Institute, New York, N.Y., pp.130-140.

Griswold, W.T. and Munn, M.J., 1907. Geology of oil and gas fields in Steubenville, Burgettstown and Claysville Quadrangles, Ohio, West Virginia and Pennsylvania. U.S. Geol. Sum. Bull., No.318, 196 pp.

Howell, J.V., 1934. Historical development of the structural theory of accumulation of oil and gas. In: W.E. Wrather and F.H. Lahee (Editors), Problems of Petroleum Geology. American Association of Petroleum Geologists, Tulsa, Okla., pp.1-23.

Lane, A.C. and Gordon, W.C., 1908. Mine waters and their field assay. Bull. Geol. SOC. Am. , 19:501-512.

Mills, R. van A., 1920. Experimental studies of subsurface relationships in oil and gas fields. Econ. Geol., 15:398-421.

Munn, M.J., 1920. The anticlinal and hydraulic theories of oil and gas accumulation. Econ. Geol., 4:509-529.

Rich, J.L., 1923. Further notes on the hydraulic theory of oil migration and accumulation. Bull. Am. Assoc. Pet. Geol., 7:213-225.

Rogers, W.B. and Rogers H.D., 1843. On the connection of thermal springs in Virginia with anticlinal axes and faults. Am. Geol. Rep., 1313.323-347.

Schilthuis, R.J., 1938. Connate water in oil and gas sands. In: Petroleum Development and Technology, AIME, pp.199-214.

Torrey, P.D., 1950. A review of secondary recovery of oil in the United States. In: Secondary Recovery of Oil in the United States. American Petroleum Institute, New York, N.Y., pp.3-29.

Torrey, P.D., 1966. The discovery of interstitial water. Prod. Monthly, 30:8-12. White, D.E., 1957. Magmatic, connate, and metamorphic water. Bull. Geol. SOC. Am. ,

68:1659-1682.

Chapter 2. SAMPLING SUBSURFACE OILFIELD WATERS

Subsurface waters associated with petroleum are subjected to forces that promote mixing and homogeneity, but the assumption cannot be made that they are so well mixed that no attention to sampling technique is required. Localized conditions within an aquifer are commonly such that a given subsurface body of water may not be of uniform composition. The composition of subsurface water commonly changes with depth, and also laterally in the same aquifer. Changes may be brought about by the intrusion of other waters, and by discharge from and recharge to the aquifer. It is thus difficult to obtain a representative sample of a given subsurface body of water because any one sample is a very small part of the total mass, which may vary widely in composition. To develop a comprehensive picture of the composition characteristics of the total mass, it is generally necessary to obtain and analyze many samples. Also, the samples may change with time as gases come out of solution and supersaturated solutions approach saturation.

The sampling sites should be selected, if possible, to fit into a comprehensive network to cover an oil-productive geologic basin. Considerations in selecting sampling sites are as follows:

(1) Which sites will better fit into an overall plan to evaluate the chemistry of the waters on a broad basis?

(2) Which sites will yield the better information for correlation with data obtained from other sites?

(3) Which sites are more representative of the total chemistry of brines from a given area?

The value of the sample is directly proportional to the facts known about its source; therefore, sites should be selected for which the greater source knowledge is available.

For surveillance purposes, samples can be collected from the same site at sufficiently frequent intervals that no important change in quality will occur between sampling times. Change in composition may result from changes in rate of water movement, pumpage rates, or infiltration of other water. Changes that can occur in petroleum-associated water are illustrated in Table 2.1.

Well 1 shows the sort of change that commonly occurs. The water from well 2 did not change between 1947 and 1957, within the accuracy of the analytical determination. Water from well 3 changed drastically, suggesting the intrusion of water from a different source.

8 SAMPLING SUBSURFACE OILFIELD WATERS

TABLE 2.1

Changes in the composition of petroleum-associated waters (mg/l)

Constituent Well 1

1947 1957

Well 2 Well 3

1947 1957 1956 1959

Sodium and potassium Magnesium Calcium Bicarbonate Sulfate Chloride

29,062 1,100 5,900

34 14

58,500

25,000 1,200 5,500

12 50

51,800

46,038 45,924 1,491 856 2,011 2,200 30 2 14,200 14,400 60 10

24 12 600 1,800 3 52 200 0

102,100 102,800 2,000 300

Total dissolved solids 94,610 83,562 164,376 165,388 4,381 2,968

~- _. -

There is a tendency for some petroleum-associated waters to become more dilute as the oil reservoir is produced. Such dilution may result from the movement of dilute water from adjacent compacting clay beds into the petroleum reservoir as pressure declines with the continued removal of oil and brine (Wallace, 1969).

The composition of petroleum-associated water varies with the position within the geologic structure from which it is obtained. For example, if the water table is tilted, the more dilute water probably will be on the structurally high side. In some cases the salinity will increase upstructure to a maximum at the point of oil-water contact. Usually this is caused by infiltrating meteoric waters.

Few of the samples collected by drill-stem test are truly representative formation-water samples. During drilling, the pressure in the well bore is intentionally maintained higher than that in the formations. Filtrate from the drilling mud seeps into the permeable strata, and this filtrate is the first liquid to enter the test tool.

The most truly representative formation-water sample usually is obtained after the oil well has produced for a period of time and all extraneous fluids adjacent to the wellbore have been flushed out. Samples taken immediately after the well is completed may be contaminated with drilling muds, with drilling fluids, and/or with well completion fluids, such as filtrate from cement, tracing fluids, and acids, which contain many different chemicals.

Drill-stem test

The drill-stem test, if properly made, can provide a reliable formation water sample. Mud filtrate will be the first fluid to enter the drill-stem test tool, and it will be found at the top of the fluid column immediately below

DRILL-STEM TEST 9

tester

Multiple closed i pressure sample

F l o w s t r e a m pressure recorde

Ver t ica l and rot

Locked down

Blanked o f f pressure record

RUNNING IN HOLE

Fig. 2.1. Multiple closed-in-pressure subsurface sampler. (Courtesy of the Halliburton Company.)


Droin Y O I V 4 Oroln

Floottnq plston h ' S A M P L E U N I T , '

for l o w p e r m o b i l i t i e s Rubber doughnut Sample

Mud -

Dump chamber v o l v e ( l o c k s open)

L " J-

MECHANICAL U N I T F I M - A SAMPLE U N I T

RECORDED TESTER S P POSITION

Tester positioning depth m E SURFACE CONTROL

I N 0 I C A T I D N S

action

SAMPLING PRESSURE

Pod set

Tool open

In i t ia l shut-in ? prss1ure

Sampling pressure

F ina l shul- in pressure

Hydroltotic 3 head

RECORDED LOG

Fig. 2.2. Formation interval tester. (Courtesy of Schlumberger Well Services Company.)

DRILL-STEM TEST 11

the oil. At some point down the column a representative formation-water sample can be found. The point is variable and will be influenced by rock characteristics, mud pressure, type of mud, and duration of the test. I t is best to sample the water after each stand of pipe is removed. Normally, the total dissolved solids content will increase downwards and become constant when pure formation water is obtained, if the concentration continues to increase all the way to the bottom, no representative sample can be obtained. A test that flows water will give even higher assurance of an uncontaminated sample. If only one drill-stem test water sample is taken for analysis, it should be taken just above the tool, as this is the last water to enter the tool and is least likely to show contamination.

Fig. 2.1 and 2.2 illustrate two drill-stem test tools with their various components. Fig. 2.1 illfistrates a Halliburton Company tool; Fig. 2.2 illustrates a Schlumberger Well Services Company tool. Other companies supply equally adequate tools, and reference to specific brands throughout this test is made for identification only and does not imply endorsement by the US. Bureau of Mines. The drill-stem test can provide pressure head and head decline and buildup data useful in permeability calculation (Brede- hoeft, 1965) and other information for the determination of additional reservoir conditions, such as the gas/oil ratio and reservoir depletion (McAlister et al., 1965). A stratigraphic interval of interest is isolated in the drilled hole by use of packers attached to the drill string. Opening the tester valve in the test string allows the formation fluid to enter the drill pipe. Pressures are recorded by gages in the bottom of the test tool.

To insure that a representative sample is obtained, the pH, resistivity, and chloride content of samples taken at intervals down the drill pipe can be determined. Usually a transition zone will be found below which apparently uncontaminated formation water will be located. The pH, resistivity, and chloride content will vary above the transition zone, and they will become constant below it. The sample taken for analysis in the laboratory can yield positive evidence of contamination, if present. The two most indicative tests are pH and the color of a filtered sample. If the filtered sample remains tan or brown and the color cannot be removed even with pressure filtration, it probably is contaminated with drilling-mud filtrate. A sample can be placed on a white-spot plate for color evaluation. For positive identification of the presence of mud filtrate, a sample of the drilling mud used in drilling the well can be obtained and allowed to react with distilled water, the reacted water .is analyzed to determine the mud-contributed ions, and the suspected contaminated sample is analyzed to determine if it contains these ions.

Analyses of water obtained from a drill-stem test of Smackover Limestone water in Rains County, Texas, show how errors can be caused by improper sampling of drill-stem test water. Analyses of top, middle, and bottom samples taken from a 15-m fluid recovery are shown in Table 2.11. These data show an increase in salinity with depth in the drill pipe, indicating that the first water was contaminated by mud filtrate (Noad, 1962). The middle


TABLE 2.11

Drill-stem test recovery of Smackover Limestone water

Constituent Concentration (mg/l)

middle bottom - top

Sodium 29,600 Calcium 8,100 Magnesium 600 Bicarbonate 500 Sulfate 2,000 Chloride 59,900 Total dissolved solids 101,000

43,500 71,800 13,100 22,400

900 1,400 500 400

1,300 500 91,800 154,000

151,000 251,000

sample is approximately half mud filtrate and half formation water. The bottom sample is the most representative of Smackover water.

No single procedure is universally applicable for obtaining a sample of oilfield water. For example, information may be desired concerning the dissolved gas or hydrocarbons in the water, or the reduced species present - such as ferrous or manganous compounds. Sampling procedures applicable to the desired information must be used.

Sample containing dissolved gases

Knowledge of certain dissolved hydrocarbon gases is used in exploration. Methane is quite soluble in water, but samples must be collected in a sampler that keeps the subsurface pressure on the sample until it is opened in the laboratory. The testing tool is kept open until the head of water in the drill pipe is equalized with the formation pressure or until water flows at the surface. The pressure equalization may require 4 or more hours. However, a surface recording subsurface pressure gage can be lowered into the drill pipe to determine when the pressure has equalized. After equalization of pressure, formation-water samples can be obtained by lowering a subsurface sampler into the drill pipe (Buckley et al.,1958). Zarrella et al. (1967) determined the content of dissolved benzene. For this it is not necessary to use a subsurface sampler; the samples are caught in buckets on opening the pipe string, and immediately transferred from the buckets to new narrow-necked glass or metal containers.

A preferred method of obtaining a sample for subsequent gas analysis is to catch the aqueous sample in a metal container of about one-quart capacity. This sample is immediately transferred to another metal sample container. The second container should be filled completely to the top, then the sides of the can are lightly squeezed to allow for fluid expansion, and the lid is sealed tightly. A foil-lined (not plastic) lid should be used. If possible, the

SAMPLING AT THE FLOW LINE 13

sample should be analyzed immediately. If this is not possible, cool or freeze the sample.

Sampling at the flow line

Another method of obtaining a sample for analyses for dissolved gases is to place a sampling device in a flow line. Fig. 2.3 illustrates such a device.

I container

Valve - Pipe line

Va lve f Rubber - tube

Fig. 2.3. Flow-line sampler.

The device is connected to the flow line, and water is allowed to flow into and through the container, which is held above the flow line, until 10 or more volumes of water have flowed through. The lower valve on the sample container is closed and the container removed. If any bubbles are present in the sample, the sample is discarded and a new one is obtained.


Sampling at the wellhead

It is common practice in the oil industry to obtain a sample of formation water from a sampling valve at the wellhead. A plastic or rubber tube can be used to transfer the sample from the sample valve into the container. The source and sample container should be flushed to remove any foreign material before a sample is taken. After flushing the system, the end of the tube is placed in the bottom of the container, and several volumes of fluid are displaced before the tube is slowly removed from the container and the container is sealed. Fig. 2.4 illustrates a method of obtaining a sample at the wellhead. An extension of this method is to place the sample container in a larger container, insert the tube to the bottom of the sample container, allow the brine to overflow both containers, withdraw the tube, and cap the sample under the fluid.

At pumping wellheads the brine will surge out in heads and will be mixed with oil. In such situations a larger container equipped with a valve at the bottom can be used as a surge tank or an oil-water separator, or both. To use this device, place the sample tube in the bottom of the large container, open the wellhead valve, rinse the large container with the well fluid, allow the large container to fill, and withdraw a sample through the valve at the bottom of the large container. This method will serve to obtain samples that are relatively oil-free.

We1 l h e a d

O i l and water

Fig. 2.4. Schematic of method of obtaining a sample at the wellhead.

Sample for determining unstable properties or species

The pH, Eh, and various species of elements are unstable and will change with changes in pressure and temperature, and when the formation water is exposed to the atmosphere. The pH of the sample will change because of the oxidation of reduced species, because of release of dissolved gases, and because of hydrolysis reactions such as:

H + H + c03-* + HCO,-+ H,CO,

SAMPLE FOR STABLE-ISOTOPE ANALYSIS 15

Because the pH of the formation water sample will change, the pH should be determined using a flowing sample. A pH/Eh flow sampling chamber (Collins, 1964) is shown in Fig. 2.5. The Eh determination is difficult and for corroboration it should be checked using a knowledge of the dissolved Fe+* /Fe+3 ratio of the water.

Ther mocompensator Ther mocompensator

Fig. 2.5. Flow chamber for use in determining pH and Eh at the wellhead.

Ferrous iron will oxidize to ferric and should be determined immediately after collecting a fresh sample. Some of the other dissolved constituents that should be determined immediately after securing a fresh sample are oxygen, hydrogen sulfide, thiosulfate, and manganous manganese.

Sample for stable-isotope analysis

A sample that is t o be analyzed for stable isotopes should be collected with care. If possible, such a sample should be taken at reservoir temperatures and pressures to minimize any isotope fractionation. However, because this usually is impossible, caution should be exercised to insure that a representative sample is collected at the prevailing wellhead temperature and pressure.

The sample should be collected at the wellhead. If this proves impossible,


it may be feasible to collect the sample from a nonheated separator or heater; samples are not to be taken of water that has been heated or treated with any chemicals. Glass sample bottles (about 100 ml usually is sufficient) should be used, and the sample should overflow the bottle. The bottle should be closed with a cap equipped with a plastic insert, and the top should be sealed with wax to minimize exchange reactions with air.

Sample containers

Various factors influence the type of sample container that is selected. Containers that are used include polyethylene, other plastics, hard rubber, metal cans, and borosilicate glass. Glass will absorb various ions such as iron and manganese, and may contribute boron or silica to the aqueous sample. Plastic and hard rubber containers are not suitable if the sample is to be analyzed to determine its organic content. A metal container is used by some laboratories if the sample is to be analyzed for dissolved hydrocarbons such as benzene.

TABLE 2.111

Description needed for each petroleum-associated water sample

Sample number Field Farm or lease Well No. in the of Section Township Range __ County State - Operator __ Sample obtained by -_____ Address ~ Representing ~

Sample obtained from (lead line, separatory flow tank, etc.) Completion date of well Elevation of well ___ Name of productive zone from which sample is produced - Sand - Shale Lime ~ Other Name of productive formation well passes through Depths: Top of formation

__ --

Operator’s address (main office) - -___ Date ~

Names of formations

Bottom of formation Top of producing zone Bottom of producing zone Total depth drilled Present depth

Bottom hole pressure and date of pressure Bottom hole temperature Date of last workover b e any chemicals If yes,

added to treat well? -what? Well production Initial Present Casing service record: Oil, barrelslday - Water, barrels/day Gas, cubic feetlday _______

Method of production (primary or secondary)

Remarks: (such as casing leaks, communication, or other pays in same well, lease, or field)

TABULATION OF SAMPLE DESCRIPTION 17

The type of container selected is dependent upon the planned use of the analytical'data. Probably the more satisfactory container, if the sample is to be stored for some time before analysis, is the polyethylene bottle. All polyethylenes are not satisfactory because some contain relatively high amounts of metals contributed by catalysts in their manufacture. The approximate metal content of the plastic can be determined using a qualitative emission spectrographic technique. If the sample is transported during freezing temperatures, the plastic container is less likely to break than glass.

The practice of obtaining two samples and acidifying one sample so that the heavy metals will stay in solution works better if the plastic container is used. Some of the heavy metals are adsorbed by glass even if the sample is acidified.

Tabulation of sample description

The sample is of little value if detailed information concerning it is not available. Information such as that in Table 2.111 should be obtained for each sample of petroleum-associated water, and for certain types of studies, additional information may be needed.

References

Bredehoeft, J.D., 1965. The drill-stem test: the petroleum industry's deep-well pumping test. Ground Water, 3:15-23.

Buckley, S.E., Hocott, C.R. and Taggart, Jr., M.S., 1958. Distribution of dissolved hydrocarbons in subsurface waters. In: L.C. Weeks (Editor), Habitat of Oil. American Association Petroleum Geologists, Tulsa, Okla., pp.850-882.

Collins, A.G., 1964. Eh and pH of oilfield waters. Prod. Monthly, 28:ll-12. McAlister, J.A., Nutter, B.P. and Lebourg, M., 1965. A new system of tools for better

control and interpretation of drill-stem tests. J. Pet. Technol., 17 :207-214. Noad, D.F., 1962. Water analysis data, interpretation and applications. J. Can. Pet.

TechnoL , 1 :82-89. Wallace, W.E., 1969. Water production from abnormally pressured gas reservoirs in South

Louisiana, J. Pet. Technol., 21 :969-982. Zarrella, W.M., Mousseau, R.J., Coggeshall, N.E., Norris, M.S. and Schrayer, G.T., 1967.

Analysis and significance of hydrocarbons in subsurface brines. Geochim. Cosmochim. Acta, 31 :1155-1166.

Chapter 3. ANALYSIS OF OILFIELD WATERS FOR SOME PHYSICAL

ENTS PROPERTIES AND INORGANIC CHEMICAL CONSTITU-

Water analyses are used by the petroleum industry in studies related to subsurface formation identification, pollution problems, water compatibili- ties, corrosion, water-quality control, waterflooding, and exploration. Efforts to standardize methods applicable to analyzing oilfield waters have been made by the American Petroleum Institute (1968), and currently similar efforts are being made by the American Society for Testing and Materials.

The methods discussed in this chapter include wet chemical procedures for calcium, magnesium, barium, carbon dioxide, sulfide, sulfur compounds, selenium, oxygen, spent acid, fluoride, chloride, bromide, and iodide. In- strumental methods are described for pH, Eh, specific gravity, resistivity, suspended solids, acidity, alkalinity, oxygen isotopes, ammonium nitrogen, phosphate, boron, arsenic, copper, nickel, lead, manganese, zinc, cadmium, and silica. Also described are emission and atomic absorption methods for lithium, sodium, potassium, rubidium, cesium, magnesium, calcium, barium, manganese, zinc, copper, iron, and lead; and emission spectroscopic methods for aluminum, beryllium, boron, iron, manganese, and strontium. ._

The methods used to analyze oilfield waters should be capable of producing precise and accurate results. Methods applicable to analyzing fresh waters may or may not be directly applicable to a petroleum-associated water, but in general such a method will need modification or complete redevelopment because the petroleum-associated water contains a more complex and concentrated array of dissolved salts than the fresh water.

Quality control

Data provided by the analytical laboratory are used in decision-making, and the data must describe precisely and accurately the characteristics or concentrations of the constituents in the sample. Usually an approximate or incorrect result is less valuable than no result because it leads to faulty interpretations.

The analyst needs t o be aware of his responsibility to provide results that reliably describe the sample. Further, he should know that the procedures that he uses, his professional competence, and his reported values may be used or challenged. To meet any challenge his results must be adequately

20 ANALYSIS OF OILFIELD WATERS

documented. The value of research investigations which use oilfield brine analyses depends upon the validity of the laboratory results.

A program to insure the reliability of analytical data is mandatory because of the importance of the laboratory results and the actions that they produce. An established routine control program applied to analytical tests is necessary to assure the precision and accuracy of the final results. The use of spiked samples can measure quality, while the use of analytical-grade reagents is a control measure. Quality control varies with the type of as*- sis. For example, the frequent standardization of the titrant used in a titration is an element of quality control, while instrument calibration in an instrumental method is also a quality control function.

The specific methodology employed should be carefully documented regardless of the method used; thus the data user or reviewer can apply the associated precision and accuracy when interpreting the laboratory data.

Choosing an analytical method

Widespread use of an analytical method indicates that it probably is reliable and will produce valid results. Use of a little-known procedure forces the data user to accept the judgment of the analyst.

The following criteria are useful in selecting analytical methods: (1) The desired constituent should be measured with sufficient precision

and accuracy in the presence of the interferences normally found in oilfield waters.

(2) The method must utilize the skills and equipment available in the oilfield water laboratory.

(3) The method should be sufficiently tested and used by several laboratories to establish its validity.

Precision

Precision is the reproducibility among replicate observations, and in quality control it is determined on actual water samples containing interfering constituents. Several methods to determine precision are available and the following is representative:

(1) Study four separate concentration levels, including a low concentration near the sensitivity level of the method, two intermediate concentrations, and a concentration near the upper limit of application of the method.

(2) Make seven replicate determinations at each of the concentrations tested.

(3) To allow for changes in conditions, the precision study should use at least 2 hours of normal laboratory operation.

(4) To permit the maximum interferences in sequential operation, the samples should be run in the following order: high, low, intermediate, intermediate. Repeat this series seven times to obtain the desired replication.

QTJALITY CONTROL 21

TABLE 3.1

Precision data on oilfield brine samples for boron

Sample ___ ~~

Concentrations of boron found (mg/l)

-- . -

Average Standard deviation

Taylor

10.1 10.1 10.2 10.3 10.1 10.2 10.2

10.2 0.1

Eagle Ford

15.2 15.3 15.1 15.2 15.3 15.2 15.1

Paluxy

20.1 20.1 20.3 20.2 20.3 20.3 20.1

____ - -

15.2 20.2 0.1 0.1

Douglas

30.3 30.2 30.1 30.1 30.3 30.2 30.1

30.2 0.2

(5) The precision statement includes a range of standard deviations over the t A e d range of concentrations. Thus, four standard deviations are obtained over a range of four concentrations, but the statement contains only the extremes of standard deviations and concentrations studied. An example of data generated from such an approach is shown in Table 3.1.

Using the data of Table 3.1 the precision statement would read: “In a single ldboratory, using oilfield water samples containing concentrations of 10.2 and 30.2 mg B/1, the standard deviation was kO.1.”

Accuracy

The degree of difference between observed and actual values is accuracy. The accuracy of a method can be determined as follows:

(1) Add known amounts of the constituent to be determined to actual samples at concentration levels where the precision of the method is adequate. The added amount should double the concentration of the low- concentration sample and bring the concentration of an intermediate sample to about 75% of the upper limit of application of the method.

(2) Make seven replicate determinations at each concentration. (3) Report the accuracy as the percent recovery found in the spiked

sample, where the percent at each concentration is the mean of the seven replicate tests.

Table 3.11 illustrates the application of this approach, where two of the samples used in the precision study, Table 3.1, were used. An appropriate accuracy statement is: “In a single laboratory, using oilfield water samples containing concentrations of 20.2 and 35.3 mg B/1, recoveries were 100.0% and 100.3%, respectively.”


TABLE 3.11

Accuracy data on oilfield brine samples for boron

Sample Concentrations of boron found (mg/l)

Taylor Paluxy (added 10 mg/l boron) (added 15 mg/l boron)

Average

Percent recovery

20.2 20.2 20.1 20.1 20.3 20.3 20.4

20.2

20-2 ] x 100 = 100.0 [ 10.2 + 10

35.5 35.4 35.2 35.2 35.3 35.2 35.1

35.3

35.3 [ 20.2 + 15

] x 100 = 100.3

The precision and accuracy data are valuable in determining that the analyst and the method are capable of generating valid data. Once this is proven, the data can be used to evaluate systematic performance. This can be done by using spiked samples about 10% of the time to determine that the accuracy is favorable, and evaluating replicate samples to determine that the precision is favorable.

Preliminary sample treatment

The following determinations should be made in the field immediately after sampling:

(1) temperature (in "C), (2) pH, (3) dissolved oxygen, (4) resistivity, ( 5 ) acidity, (6) alkalinity, (7) sulfide, and (8) carbon dioxide.

If possible, the oilfield water sample should be filtered immediately after sampling in the field. A preferred method-is to use pressure filtration through a 0.45-micrometer (pm) membrane filter. A liter of filtrate usually is sufficient and the following determinations can be made on aliquots: (1) iodide, (2) bromide, (3) chloride, (4) selenium, ( 5 ) sulfate, (6) nitrogen, (7) phosphate, (8) silica, (9) boron, (10) potassium, (11) sodium, and (12) lithium.

If a field-filtered sample cannot be provided, a laboratory-filtered sample may be substituted with slightly less confidence in the reported data.

PRELIMINARY SAMPLE TREATMENT 23

Standard solutions

Examples of standardization procedures are given for some of the methods. The concentrations of standard solutions are indicated as the weight of a given element equivalent to, or contained in, 1 ml of solution. The strength of acids and bases are given in terms of molarities or normali- ties.

Accuracy of measurements

In the instructions for making the analysis and preparing the solutions, significant figures are utilized to define the accuracy of weights and measures.

Required accuracy for measurement of volume in the analysis and preparation of reagents is also shown. Standard solutions are prepared in and measured from volumetric glassware.

Reagent chemicals and solutions

All of the chemicals used in the analytical procedures should conform to the specifications of the Committee on Analytical Reagents of the American Chemical Society. Chemicals not listed by this organization can be tested according to procedures given by Rosin (1955). Primary standard chemicals can be obtained from the National Bureau of Standards or from companies marketing chemicals of the same purity.

Water used to dilute samples or to prepare chemical solutions should first be demineralized by passage through mixed cation-anion exchange resins or by distillation. Its specific conductance a t 25°C must not exceed 1.5 pmho/ cm, and it should be stored in polyethylene bottles.

Carbon-dioxide-free water may be prepared by boiling and cooling demineralized water immediately before use. Its pH should be between 6.2 and 7.2.

Ammonia-free water should be prepared by passing distilled water through a mixed-bed ion-exchange resin.

Sampling

A field-filtered acidified sample also should be taken. It is pressured filtered using a 0.45-pm membrane filter and then the filtrate is immediately acidified to a pH of 3.0 or less with reagent-grade HCl. The acidified sample is used for the following determinations: (1) aluminum, (2) arsenic, (3) barium, (4) cadmium, (5) calcium, (6) copper, (7) iron, (8) lead, (9) magnesium, (10) manganese (11) nickel, (12) strontium, and (13) zinc.


TABLE 3.111

Units in which water analyses may be reported

milligrams per liter = mg/l

part per million = ppm

ppm = specific gravity of the water

1 grain per U.S. gallon = 17.12 mg/l

1 grain per Imperial gallon = 14.3 mg/l

1 ppm = 0.012 milligram atom per liter milligrams per liter

To convert compounds expressed as parts per million to ions expressed,as parts per million (where compound is A, Bm):

,(atomic weight A) ppm ion A = ppm compound A, Bm molecular weight A, B, ,(atomic weight B) ppm ion B = ppm compound A, Bm molecular weight A, B,

To convert parts per million to equivalents per million (epm): Example: sample contains 28.3 ppm Ca” , what is the concentration of calcium in epm?

Solution; atomic weight Ca = 40.08; valence = 2; equivalent weight =

40.08 = 20.04; then: 2

28 3 20.04

28.3 ppm Ca+’ = - = 1.41 epm Ca+’

Titrim e tric analysis

milliequivalent weight 106

ml of sample used

(ml x N of standard solution) x of determined ion = mg/l of determined ion

Gravimetric analysis

atomic weight of determined element ..._. - ,ht of precipitate 106 (grams of preninitnta\ Y

= me/l determined molecular weig .,.F.’U”’, ,. ml of sample used _.- ~

...

element

%O = parts per thousand or g/kg

Chlorinity (CZ) = mass in grams of silver required to precipitate the halogens in 328.5233 g of sea water

Salinity (S) = total amount of solid material, in grams contained in 1 kg of sea water when all of the bromide and iodide have been replaced by the equivalent amount of chloride, when all of the carbonate is converted to oxide and when all the organic matter is completely oxidized

%o S = 1.805 x %o Cl + 0.03

REPORTING THE ANALYTICAL RESULTS 25

Reporting the analytical results

A study conducted by the American Petroleum Institute (1968) indicated that some laboratories reported the results of oilfield water analysis as parts per million (ppm) or as milligrams per liter (mg/l) without regard to the specific gravity of the sample. For example, a sample with a specific gravity of 1.200 containing 12,000 mg/l of calcium does not contain 12,000 ppm of calcium but contains 12,000/1.200 = 10,000 pprn of calcium. Such an error obviously is more serious in reporting the analytical results for a brine than in reporting the results for a fresh water. The unit ppm means parts per million by weight, while the unit mg/l means milligrams per liter or weight per unit volume; therefore, they are not interchangeable until the volume is changed to a unit weight. Table 3.111 indicates the relation between various units of measurement.

Because the American Petroleum Institute now recommends that oilfield- water analysis be reported in units of mg/l, other associations will no doubt recommend the same uniform practice. Such standardization implements studies concerned with the chemistry and geochemistry of waters.

Sign i f ican t figures

The term significant figure (Ballinger et al., 1972) is used rather loosely to describe some judgment of the number of reportable digits in a result. Often the judgment is not soundly based and meaningful digits are lost or meaning- less digits are accepted.

Proper use of significant figures gives an indication of the reliability of the analytical method used. The following definitions and rules are suggested for retention of significant figures.

A number is an expression of quantity. A figure or digit is any of the characters 0, 1, 2, 3, 4, 5, 6, 7, 8, 9, which, alone or in combination, serves to express a number. A significant figure is a digit that denotes the amount of the quantity in the place in which it stands.

Reported values should contain only significant figures. A value is made up of significant figures when it contains all digits known to be true and one last digit in doubt. For example, if a value is reported as 18.8 mg/l, the “18” must be a firm value while the “0.8” is somewhat uncertain and may be “0.7” or “0.9”.

The number zero may or may not be a significant figure: (a) Final zeros after a decimal point are always significant figures. For

example, 9.8 g to the nearest milligram is reported as 9.800 g. (b) Zeros before a decimal point with other preceding digits are signifi-

cant. With no other preceding digit, a zero before the decimal point is not significant.

(c) If there are no digits preceding a decimal point, the zeros after the


decimal point but preceding other digits are not significant. These zeros only indicate the pbsition of the decimal point.

(d) Final zeros in a whole number may or may not be significant. A good measure of the significance of one or more zeros before or after

another digit is to determine whether the zeros can be dropped by expressing the number in exponential form. If they can, the zeros are not significant. For example, no zeros can be dropped when expressing a weight of 100.08 g in exponential form; therefore, the zeros are significant. However, a weight of 0.0008 g can be expressed in exponential form as 8 x g, and the zeros are not significant. Significant figures reflect the limits of the particular method of analysis. It must be decided beforehand whether this number of significant digits is sufficient for interpretation purposes. If not, there is little that can be done within the limits of normal laboratory operations to improve these values. If more significant figures are needed, a further improve- ment in method or selection of another method will be required to produce an increase in significant figures.

Once the number of significant figures is established for a type of analysis, data resulting from such analyses are reduced according to set rules for rounding off.

R o unding-o f f numbers

Rounding off of numbers is a necessary operation in all analytical areas. I t is automatically applied by the limits of measurement of every instrument and all glassware. However, it is often applied in chemical calculations in- correctly by blind rule or prematurely, and in these instances can seriously affect the final results. Rounding off should normally be applied only as follows.

Round ing-o f f rules (a) If the figure following those to be retained is less than 5, the figure is

dropped, and the retained figures are kept unchanged. As an example, 11.443 is rounded off to 11.44.

(b) If the figure following those to be retained is greater than 5, the figure is dropped, and the last retained figure is raised by 1. As an example, 11.446 is rounded off to 11.45.

(c) When the figure following those to be retained is 5, and there are no figures other than zeros beyond the 5, the figure is dropped, and the last place figure retained is increased by 1 if it is an odd number, or it is kept unchanged if an even number. As an example, 11.435 is rounded off t o 11.44, while 11.425 is rounded off to 11.42.

Rounding-off single arithmetic operations (a) Addition: when adding a series of numbers, the sum should be

rounded off to the same number of decimal places as the addend with the

SYNTHETIC BRINE 27

smallest number of places. However, the operation is completed with all decimal places intact, and rounding off is done afterward. As an example, 11.1 + 11.12 + 11.13 = 33.35, and the sum is rounded off to 33.4.

(b) Subtraction : when subtracting one number from another, rounding off should be completed before the subtraction operation, to avoid invalidation of the whole operation.

(c) Multiplication: when two numbers of unequal digits are to be multiplied, all digits are carried through the operation; then the product is rounded off to the number of significant digits of the less accurate number.

(d) Division: when two numbers of unequal digits are to be divided, the division is carried out on the two numbers using all digits. Then the quotient is rounded off to the number of digits of the less accurate of the divisor or dividend.

(e) Powers and roots: when a number contains n significant digits, its root can be relied on-for n digits, but its power can rarely be relied on for n digits.

Synthetic brine

Synthetic brine solutions are used in many of the analytical procedures for analyzing oilfield waters (American Petroleum Institute, 1968). Such solutions are a necessity in the development of analytical methods to study the effects of possible interfering ions. Often these synthetic solutions are used as an integral part of the analytical technique (Collins, 1967). Prepara- tion of a fairly stable synthetic brine involves saturating distilled water with carbon dioxide by bubbling carbon dioxide through it, followed by adding the bicarbonate and sulfate compounds to one portion of the C02 -saturated water, adding the alkali chlorides to one portion, and adding the alkaline earth chlorides to one portion. The alkali chloride solution is mixed with the bicarbonate-sulfate solution, and to this mixture the alkaline earth chloride solution is added. Carbon dioxide is bubbled through the synthetic brine to mix it, and the synthetic brine container is sealed immediately after removing the carbon dioxide source.

Determination of pH

The pH of the water can be determined with a pH meter which utilizes the principle of measuring the electrical potential between an indicator electrode and a reference electrode (Potter, 1956, p.56). pH meters measure the electrical potential between two suitable electrodes immersed in the solution to be tested. The reference electrode assumes a constant potential, and the indicating electrode assumes a potential dependent on the pH of the solution. Electrode potential is the difference in poteptial between the electrode and the solution in which it is immersed. The calomel electrode, which is a widely used reference electrode in water analysis, consists of a mercury- calomel rod immersed in a saturated solution of potassium chloride; this


electrode has a potential of +0.246 V. Electrical connection with the sample is provided through porous fibers sealed into the immersion end. A hydrogen-ion-selective glass electrode is normally used as an indicating electrode. The glass electrode has several features that recommend it for pH measurements. Among the most important are that it is not affected by oxidizing or reducing substances in the sample and that it can be used to measure the pH of turbid samples and/or colloidal suspensions. The basic design is a silver-silver chloride or mercury-mercurous chloride electrode immersed in a solution of known pH and the whole completely sealed in glass.

The mechanism by which the glass membrane responds to hydrogen-ion activity involves absorption of hydrogen ions on both sides of the membrane proportionally to the activity of the hydrogen ions in solution. The cell for measuring the pH of a solution is of the following type:

solution of glass solution of Ago :AgC1 1 I known pH; membrane; unknown pH

glass electrode I 1 Hgo :HgC1

The voltage of the glass electrode is a logarithmic function of the difference in hydrogen-ion activity of the solutions on either side of the glass membrane. To measure this voltage an electron-tube voltmeter is used because the resistance of the glass membrane is so great.

The pH should be determined at the time of sampling. A device similar to that shown in Fig. 2.5, can be used, or the electrodes can be placed in a container and then a stream of the sample allowed to flow from the oil- water separator (Fig. 2.4.) into the container while the pH is measured. If accurate results are desired, at least two pH buffer solutions should be used to calibrate the pH meter and electrodes before determining the pH. Because

TABLE 3.IV

pH buffer solutions (pH values of NBS standards from 0-30°C)

Temperature 0.5M Potassium acid 0.05M 0.025M 0.01M potassium tartrate (sat. at potassium acid potassium dihydrogen sodium tetroxalate 25OC) phthalate phosphate + 0.025M tetra-

("C)

sodium dihydrogen borate phosphate

0 1.67 - 4.01 6.98 9.46 10 1.67 - 4.00 6.92 9.33 15 1.67 - 4.00 6.90 9.27 20 1.68 - 4.00 6.88 9.22 25 1.68 3.56 4.01 6.86 9.18 30 1.69 3.55 4.01 6.85 9.14

DETERMINATION OF Eh 29

TABLE 3.V

Performance characteristics of typical pH meters

Normal scale Expanded scale

0-14 pH (+ 1,400 mV) 0.1 pH (10 mV) f 0.05 pH (5 5 mV) f 0.02 pH (+ 2 mV)

~~~

Range Smallest scale division Accuracy Reproducibility Temperature compensation O-IOO~C (manual or

1 pH (* 100 mV) 0.005 pH (0.5 mV) f 0.002 pH (+ 2% of reading) f 0.002 pH (+ 0.2 mV)

automatic) Input impedance > 1014 > 1013 -

the pH probably will fall between 5 and 7, the standard pH buffer solutions used could be for pH 5 and pH 7.

Standard buffer solutions, covering a range of pH, may be purchased from almost any chemical supply house and are satisfactory for routine use. Table 3.IV gives a list of NBS buffers (easily made in the laboratory) and the resulting pH at several different temperatures.

An idea of the effect of temperature on pH may be obtained by observing temperature versus pH of various buffers shown in Table 3.IV. Theoretically, the potential response of the electrode system changes 0.20 mV per pH unit per degree Celsius. Since all pH meters measure potential but read out in pH, a variable compensation is used. A rough rule of thumb is that temperature compensation is about 0.05 pH unit per 5' increase in temperature. Perfor- mance data of a conventional and an expanded scale pH meter are shown in Table 3.V.

Determination of Eh

The Eh, called the oxidation-reduction potential or the redox potential, is a measure of the relative intensity of oxidizing or reducing conditions in a chemical system. It is expressed in volts, and at equilibrium it is related to the proportions of oxidized and reduced species present. Standard equations of chemical thermodynamics express the relationships (Collins, 1964).

Eo is the standard potential of a redox system when unit activities of participating substances are present under standard conditions. Eo is related to standard free energy change in a reaction by the equation:

A P = -nfEo

where n is the number of unit negative charges (electrons) shown in the redox reaction and f is the Faraday constant in units that give a potential in volts (94,484 absolute coulombs). Standard free energy values are given in texts such as that of Latimer (1952).


When the system is not under standard conditions, the redox potential is expressed by the Nernst equation:

R T oxidized species) nf (reduced species) E h = E o + - log

where R is the gas constant (1.987 calories per degree mole) and T is the temperature in degrees Kelvin. Geochemical literature and biochemical literature such as that of Pourbaix (1949) use increasing positive potential values to represent increasing oxidizing systems, and decreasing potential values to represent reducing systems. The sign of Eh used in this manner is opposite to standard American practice in electrochemistry.

Reagents. An Eh standard' which can be used is a solution of M/300 K3Fe(CN)6 and M/300 KqFe(CN), in M/10 KC1 (Zobell, 1946). The Eh of this mixture is 0.430 V at 25'C.

Equipment. A pH meter equipped with a thermometer, a glass electrode, a calomel electrode, a platinum electrode and a thermocompensating electrode.

Eh flowchamber, a design similar to Fig. 2.5 can be used.

Procedure. Buff the platinum electrode lightly with a fine abrasive cloth and wipe it carefully with a dry soft tissue. Install the glass electrode, the calomel electrode, the platinum electrode, the thermocompensator, and the thermometer in the flowchamber. Standardize the instrument using the Eh standard.

Connect a line to the wellhead or waterline and install an oil-water separator if oil and water both are present. Connect the flowchamber to the waterline, allowing the water to flow into the bottom and out the top. Make certain that all air bubbles are excluded at the top.

Take at least three readings of the Eh (in mV), and the temperature at 10-minute intervals. These readings should agree; if they do not, continue making readings until three successive readings do agree. Make certain the water is continually flowing, that there are no air bubbles in the flowchamber, and that the solution is being stirred. I t may be necessary to remove and rebuff the platinum electrode.

Calculation. Because a thermocompensator is used in determining the pH, a temperature correction need not be made. However, if a thermocompensator is not used, a temperature correction should be made.

The Eh value is obtained by algebraically adding the measured voltage E and the voltage of the constant voltage reference electrode, which in this case is the saturated calomel electrode. The potential of the saturated calomel electrode at 25OC is 0.242 V. Therefore, if the millivolt reading of the sample is +300:

SUSPENDED SOLIDS 31

Eh = E + voltage of reference electrode E h = +300+242=+542

However, if the millivolt reading is -300, then:

E = +0.242 - 7.6 x ( t - 24)

Note: the calculations for Eh are correct only if the temperature of the brine is 25OC at the time of measurement. If the temperature is not 25"C, a correction should be made. For example, the potential of the saturated calomel electrode is 0.246 V at 20°C and 0.238 V at 30°C. The following formula can be used to obtain the correct potential:

E = +0.242 - 7.6 x ( t - 24)

where t is in degrees Celsius.

Suspended solids

Various inorganic and organic materials are found in petroleum-associated water. Knowledge of the composition of such material is useful in determining the source of the material and what treatments can be used to remove it or prevent it from recurring. Such material may be particles of oxides of the metals from well casings, pumps, or precipitates caused by oxidation of the formerly reduced species, such as iron or manganese. Other suspended solids may be silt, sand, and clay.

An estimation of the amount of material in suspension can be accomplished by using a turbidimeter (Rainwater and Thatcher, 1960). This is done by comparing the intensity of light passing through the solution with the Tyndall effect produced by lateral illumination of the solution with the same source of light.

Turbidimeter

Instruments for the measurement of turbidity employ principles of design related to transmission or reflectance of light. The lack of a primary standard for turbidity, however, has resulted in a complete absence of uniformity among the available instruments. Further, the Jackson candle turbidimeter, which does not depend upon the use of a primary standard, is a primitive instrument, subject to many interferences, and the measurements generally are not reproducible.

Recently developed turbidimeters often use for calibration a suspension of formazin permanently embedded in a cylinder of Lucite. These instruments produce reproducible readings up to 40 Jackson candle units (JCU), and samples containing turbidities in excess of 40 JCU should be diluted to

32 ANALYSIS O F OILFIELD WATERS

values below this level and the results multiplied by the correct dilution factor.

To obtain maximum accuracy and precision the following precautions should be observed:

(a) Protect the Lucite standard from scratches, nicks, and fingerprints. (b) While calibrating the instrument, use a constant orientation of the

(c) Use a homogeneous sample in the sample cuvette; do not take readings

(d) Dilute samples containing. excess tubidity to some value below 40

Lucite standard.

until finely dispersed bubbles have disappeared.

JCU; take reading, and multiply results by correct dilution factor.

Suspended solids analysis

To determine the composition of the suspended solids they can be removed by filtration using a 0.45-pm membrane or less porous filter. The filtered solids can then be subjected to chemical analysis. To determine the exact composition of the solids may require the filtration of a large sample in order to procure enough solid material. The heavy-metal content can be determined by subjecting a portion of the sample to an emission spectrometric analysis; X-ray diffraction can be used to determine which, if any, clays are present; extraction with organic solvents followed by infrared mass spectrometric, chromatographic, and gas chromatographic analysis will give an indication of organic compounds present; thermogravimetric analysis will provide clues; wet chemical analysis can be used to determine many of the anions; and X-ray fluorescence can be used to determine some of the anions.

Resistivity

The resistivity of petroleum-associated waters is used in electric log interpretations (Wyllie, 1963), and for such use the values must be adjusted to the formation temperature. This can be done by referring to curves such as those shown in Fig.3.1, which gives resistivity values for sodium chloride solutions. The resistivity of a formation water will not be exactly the same as that of a pure sodium chloride solution of equal dissolved solid (DS) content, but for practical purposes the assumption that the resistivities are approximately equal is satisfactory.

I t is possible to calculate the resistivity from water-mineral analysis by using methods such as those developed by Dunlap and Hawthorne (1951) or Jones (1944). The calculated values are less accurate and usually lower than the directly measured resistivities. The direct-measurement method is essentially the electrical resistance of a cube of oilfield water. In well-logging practice, the edge of the cube considered is 1 m in length. Therefore, resistivity of an oilfield water is expressed in ohm-meters (am) .

Temperature has a profound effect on resistivity; therefore, all resistivities

RESISTIVITY 33

RESISTIVITY. .hm-n.ttrl

Fig. 3.1. Plots of resistivity of aqueous solutions containing various concentrations of sodium chloride.

should be determined at a known constant temperature. The sample should be freshly filtered and free of oil. Nonionized silica and other materials in suspension in an oilfield water can affect the resistivity determination, but in general such interferences can be ignored. Cell polarization can be trouble- some with highly mineralized waters and will vary directly with the current that flows between the electrodes and inversely with the frequency of the current. High input voltage to the bridge or low cell resistance (highly mineralized waters) increases the likelihood of polarization. Cell resistance can be increased by increasing the cell constant.

Reagents. The necessary reagents are standard potassium chloride solutions of l.OOON, O.lOOON, and 0.01OON (use only certified reagent-grade KC1 that has been oven-dried to constant weight at 110OC); chromic-sulfuric acid cleaning solution; platinizing solution (dissolve 3 g of chloroplatinic acid and 0.02 g of lead acetate in 100 ml of water); and a 10% aqueous sulfuric acid solution.

Equipment. The necessary resistivity measurement equipment includes a Wheatstone bridge; resistivity cells, either dip or pipet type, with platinum


electrodes; water bath, complete with stirrer, thermostat, and thermometer, with 0.loC graduations; source of alternating current, 25- to 60-cycle a.c. galvanometer, and an appropriate isolating transformer.

Selection of the cell constant is limited by the accuracy and sensitivity of the bridge when measuring very high and very low resistivities. Also, current frequency should not be excessively high since a.c. resistance is a complex function of frequency; e.g., at frequencies necessary to avoid polarization, the differences between a.c. resistance and d.c. resistance may be appreciable unless the cell has been carefully designed to minimize this difference. In essence, the ideal single apparatus for measurement of resistivity throughout a wide range necessarily incorporates compromises between low input voitage, high cell constant, high current frequency, and accuracy and sensitivity of the bridge.

Cell preparation

To prepare the cell, clean it with chromic-sulfuric acid solution and rinse thoroughly with water. Immerse the cell or fill it, depending upon whether a dip or pipet cell is used, in the platinizing solution. Connect the electrodes of the cell to three dry cells (1-1/2 V each) in parallel through a limiting resistance of approximately 1,000 52. Reverse the direction of the current once a minute for 6 minutes or until the shiny platinum surface is covered with a dense black coating. Repeat the electrolytic process using 10% sulfuric acid solution to remove chlorine. Remove the electrodes, rinse with distilled water, and store in distilled water.

Note: new cells should be cleaned and platinized before use. They should be cleaned and replatinized whenever the readings become erratic or when the platinum black flakes off.

Cell resistance

To determine the cell resistance using the standard potassium chloride solutions, adjust the temperature of each potassium chloride solution to exactly 25OC and obtain a reading in ohms for each solution with the cell.

Calculate the cell constant using the following formula:

C = R K C l x specific conductance of standard KC1 solution

where R K C l = reading obtained in ohms for standard KC1 solution.

as follows (Hodgman et al., 1962, p. 2690): Note: the specific conductivities of the standard KC1 solutions a t 25°C are

1.OON KCl = 0.11173 mho/cm 0.1ON KC1 = 0.012886 mho/cm 0.01N KCl = 0.0014114 mho/cm

SPECIFIC GRAVITY 35

Method of determination

Procedure. To determine the resistivity of the petroleum-associated water, filter the sample to remove oil and transfer the sample to the cell or cell container and place it in a water bath. Allow sample sufficient time to adjust to bat!i temperature, and measure resistance of sample and record the temperature to nearest 0.1Oc.

Calculation. The resistivity calculation is dependent upon the type of cell and bridge used, but in general the following formula will apply:

D2 V R, = - 4LXT where R, = resistivity of water, a m ; V = difference in potential between potential-measuring electrodes, V; I = current flowing through the cell, A; D = inside diameter of potential-measuring electrodes, m; and L = distance between potential-measuring electrodes, m.

Because D and L are constant for any one cell and I is held constant for most waters, these values can be combined into a single constant, K , and the following simplified equation used :

R, = KV

Calculated resistivity

The resistivity of petroleum-associated waters often is calculated using the laboratory analysis (Dunlap and Hawthorne, 1951). The concentrations of the ionic constituents are used in the calculation method.

Dunlap and Hawthorne (1951) caution users of their calculation method that the sulfate factor 0.50 may give unreliable results if the water contains appreciable concentrations. of sulfate. If the sulfate concentration exceeds 2,500 mg/l, a factor of 0.40 will give a better calculated resistivity value.

Specific gravity

Specific gravity is the ratio of the weight of a given volume of material to the weight of an equal volume of some other material used as a standard (Mellon, 1956, p.306), and pure water is the usual standard for liquids and solids. Depending upon the accuracy desired, the specific gravity of a petroleum-associated water can be determined with a pycnometer, specific gravity balance, or hydrometer. Because any oil in or on the sample will interfere with the specific gravity determination, the sample should be filtered.

TABLE 3.W

Approximate relation of specific gravity (Sp. gr.) to mg/l of dissolved solids (DS) -

Sp. gr. DS Sp.gr. DS

1 .ooo 1.001 1.002 1.003 1.004 1.005 1.006 1.007 1.008 1.009 1.010 1.011 1.012 1.013 1.014 1.015 1.016 1.017 1.018 1.019 1.020 1.021 1.022 1.023 1.024 1.025 1.026 1.027 1.028 1.029 1.030 1.031 1.032 1.033 1.034 1.035 1.036 1.037

0 1,400 2,800 4,200 5,600 7,000 8,300 9,700

11,100 12,400 13,700 15,200 16,600 17,800 19,100 20,500 21,900 23,200 24,500 25,900 27,300 28,500 29,800 31,000 32,400 33,900 35,100 36,400 37,700 39,100 40,400 41,700 43,000 44,300 45,600 46,900 48,300 49,500

1.038 1.039 1.040 1.041 1.042 1.043 1.044 1.045 1.046 1.047 1.048 1.049 1.050 1.051 1.052 1.053 1.054 1.055 1.056 1.057 1.058 1.059 1.060 1.061 1.062 1.063 1.064 1.065 1.066 1.067 1.068 1.069 1.070 1.07 1 1.072 1.073 1.074 1.075

'50,800 52,000 53,300 54,600 55,900 57,100 58,300 59,600 60,900 62,100 63,400 64,600 65,900 67,100 68,400 69,600 70,900 72,000 73,300 73,600 75,800 77,100 78,200 79,400 80,600 81.800 83,100 84,300 85,600 86,700 87,800 89,100 90,300 91,500 92,700 93,900 95,100 96,200

Sp.gr. DS Sp. gr. DS Sp.gr. DS Sp. gr. DS

1.076 1.077 1.078 1.079 1.080 1.081 1.082 1.083 1.084 1.085 1.086 1.087 1.088 1.089 1.090 1.091 1.092 1.093 1.094 1.095 1.096 1.097 1.098 1.099 1.100 1.101 1.102 1.103 1.104 1.105 1 .I06 1.107 1.108 1.109 1.110 1.111 1.112 1.113

97,400 98,700 99,800

101,000 102,200 103,400 104,600 105,800 106,900

109,300 110,400 111,600 11 2,800 114,000 115,100 116,200 117,400 118,600 119,600

108,100

120,800 122,000 123,100 124,400 125,500 126,700 127,800 128.800 130,000 131,100 132,300 133,400 134,500 135,600 136,800 137,900 139,100 140.1 00

1.114 1.115 1.116 1.117 1.118 1.119 1.120 1.121 1.122 1.123 1.124 1.125 1.126 1.127 1.128 1.1 29 1.130 1.131 1.132 1.133 1.134 1.135 1.136 1.137 1.138 1.139 1.140 1.141 1.142 1.183 1.144 1.145 1.146 1.147 1.148 1.149 1.150 1.151

141,200 142,300 143,400 144,500 145,600 146,700 147,900 148,900 15 0.00 0 151,100 152,100 153,200 154,400 155,500 156,600 157,700 158,800 159,900 161,000 162,000 163,100 164,100 165,200 166,200 167,300 168,400 169,400 170,400 17 1,500 172,500 173,600 174,700 175.7 00 176,800 177,900 178,900 180,000 181,100

1.152 1.153 1.154 1.155 1.156 1.157 1.158 1.159 1.160 1.161 1.162 1.163 1.164 1.165 1.166 1.167 1.168 1.169 1.170 1.171 1.172 1.173 1.174 1.175 1.176 1.177 1.178 1.179 1.180 1.181 1.182 1.183 1.184 1.185 1.186 1.187 1.188

182,100 183,200 184,200 185,300 186,300 187,400 188,400 189,500 190,500 191,600 192,600 193,600 194,700 195,700 196,700 197,800 198.800 199,800 200,900 201,900 202,900 203,900 204,900 206,000 207,000 208,000 209,000 210,000 211,000 212,000 213,000 214,000 215,000 216,000 217,000 218,000 219.000

1.190 1.191 1.192 1.193 1.194 1.195 1.196 1.197 1.198 1.199 1.200 1.201 1.202 1.203 1.204 1.205 1.206 1.207 1.208 1.209 1.210 1.211 1.212 1.213 1.214 1.215 1.216 1.217 1.218 1.219 1.220 1.221 1.222 1.223 1.224 1.225

221,000 222,000 223,?00 224,000 225,000 226,000 227,000 228,000 229,000

230,000 230,800 231,800 232,800 233,700 234,700 235,700 236,700 237,600 238,600 239,500 240,500 241,500 242,400 243,400 244,300 245,300 246,200 247,700 248,100 249,100 250,000 250,900 251,900 252,800 253,800 254,700

1.189 22o;ooo

8 3 m

TITRIMETRIC METHODS 37

Knowledge of the specific gravity of the sample is necessary to convert the analytical data determined for the sample from milligrams per liter to parts per million. In addition, the specific gravity will give an indication of the amount of dissolved solids present in the sample, as indicated in Table 3.VI.

TITRIMETRIC METHODS

Acidity, alkalinity, and borate boron

If the pH of the water is less than 4.5, the water possesses what is called “mineral-acid acidity”. The acidity of a petroleum-associated water may indicate a contaminant because of acid treatment of the well or it could indicate the presence of various dissolved gases and salts. Most petroleum- associated waters contain little or no acidity. If a water contains acidity, it does not contain alkalinity.

The acidity of a water is determined by adding a standard base such as 0.02N sodium hydroxide to the water until the pH of the water is 4.5 (Collins et al., 1961) as monitored with a pH meter. To obtain a value close to natural conditions, the acidity should be determined at the sampling point.

The alkalinity of a water is determined by adding a standard acid such as 0.05N hydrochloric acid to the water and recording the volume used to neutralize it to pH 8.1 and pH 4.5. The amounts of hydroxide, carbonate, and/or bicarbonate can then be calculated using the relationships shown in Table 3.VII. Because the alkalinity will change when the sample is exposed to the atmosphere, the alkalinity should be determined as rapidly as possible after sampling.

TABLE 3.VII

Relationships for determining alkalinity after neutralization with a standard acid

Volume of standard acid used

OH co3 HC03

P = O 0 0 T P = < 1 / 2 T 0 2P T - 2P P = 1/2T 0 2P 0 P > 1 /2T 2 P - T 2 ( T - P ) 0 P = T T 0 0

P = volume used to titrate to pH 8.1; T = volume used to titrate to pH 4.5 plus volume used to titrate to pH 8.1.


Reagents. The necessary reagents are standard hydrochloric acid, standard sodium hydroxide, pH buffer solutions (preferably for pH 4, 7, and lo), mannitol, and nitrogen gas.

Equipment The necessary equipment are a pH meter, 10-ml microburets, boron-free glassware, and boron-free reflux condensers.

Standardization of 0.02N sodium hydroxide

The 0.02N sodium hydroxide solution should be standardized to determine its exact normality. One of the better methods is to standardize it with potassium acid phthalate. Obtain a potassium acid phthalate sample of known purity, such as a National Bureau of Standards standard sample, and dry the salt at 105°C. Weigh 0.1 g of salt, dissolve it in 50 ml of distilled water, and titrate with sodium hydroxide to a pH of 7.0.

Reaction:

HOOC , ,’ COONa

ChH, - -‘ChH,’ + H,O ‘, NaOH +

/ KOOC ’ ‘COOK

Normality calculation: weight KHCs H, 0,

= 0.20422 x ml NaOH

Standardization of 0.05N hydrochloric acid

If constant boiling-point hydrochloric acid is not used in preparing 0.05N hydrochloric acid, the normality should be checked. One method is to use a potassium iodate sample of known purity; for example, a National Bureau of Standards standard sample. Dry the salt at 180’C for 2 hours, weigh 0.1 g, dissolve it in 50 ml of distilled water, add 2 g of potassium iodide and 2 g of sodium thiosulfate, and titrate with hydrochloric acid to a pH of 7.0. Reaction:

KI03 + 5KI = 6HC1 + 6KC1+ 312 + 3H20 I2 + 2Na2S203 + Na2S406 + 2NaI

Normality calculation : weight KI03

0.03567 x ml HC1 N =

TITR IM ETR IC METHODS 39

Procedure. Calibrate the pH meter to pH 4 and 7 with appropriate buffer solutions .and recheck the calibration often. Transfer an undiluted 50- or 100-ml sample to a beaker and determine the pH and record it. If the pH is above 8.1, titrate it to 8.1 with 0.05N hydrochloric acid and record the titer for the carbonate calculation. Continue the titration to pH 4.5 and record the titer for the bicarbonate calculation. If salts of organic acids are in the water sample, special precautions must be taken to separate the bicarbonate titer from that required for the organic salts. This may be done by extracting the acids, usually naphthenic, with a neutral organic solvent such as petroleum ether. If the initial pH is below 4.5, titrate to pH 7 with 0.02N sodium hydroxide and record the titer for the acidity calculation.

Next reduce the pH to 3.5 with 0.05N hydrochloric acid, and reflux the sample 5 minutes. Remove the sample and immediately cool in an ice-water bath. Carefully adjust the pH of the cooled brine to 7 with sodium hydroxide while nitrogen is aspirated gently over the top. Add 10 g of mannitol and titrate the sample back to pH 7 with 0.02N sodium hydroxide. Record this titer for the borate boron calculation. If more than 1 mg of boron is present in the titrated sample, the results may be low.

Calculations. If the initial pH was more than 8.1, the titer for carbonate and bicarbonate is determined:

m1 HC1 30y000 = mg carbonate per liter ml sample

To convert carbonate to bicarbonate, multiply the carbonate value by

If the initial pH is less than 8.1 but more than 4.5, only bicarbonate is 2.03.

present :

= mg bicarbonate per liter ml HC1 x N x 61,000 ml sample

If the initial pH is below 4.5, the brine is acid:

ml NaOH x N x 50,000 = acidity as mg CaCO, per liter ml sample

If the total titration is equal to the titer found to pH 8.1, only hydroxide is present:

ml HC1 x N x 50,000 mg sample = acidity as mg CaC0, per liter

The borate boron is calculated by using the titer for borate boron:

= mg borate boron per liter ml NaOH x N x 10,820 mg sample


Calcium and magnesium

Probably the most common method currently used to determine calcium and magnesium in waters is the complexometric method (American Petro- leum Institute, 1968) which utilizes a salt such as disodium ethylenediaminetetraacetic acid (EDTA) or disodium 1,2-cyclohexanediaminetetraacetic acid (CDTA) to chelate calcium or magnesium. At a pH of 10, both calcium and magnesium are chelated, while at a pH of 12, only calcium is chelated because magnesium will precipitate as the hydroxide.

Disodium ethylenediaminetetraacetate has the following structure (Welcher, 1957, p.128):

CHI - C O - 0 , Na’ 0 -CO - CHI

/

H Na’ ‘\

/ H N - (CH2 ) - N

/’ “CH, - CO - 0 0 - CO - CH,

\

Its molecular weight is 372.254, and it forms 1:l complexes with most cations according to the following equations:

Me+’ + H2Y-’ * MeY-’ + 2H+ Me+3 + H2 Y-’ * MeY- + 2H+ Me+4 + H2 Y-’ * MeY + 2H+

where Me = the cation, H2 Y = EDTA, and MeY = the complex. Therefore, 1 gram-ion of EDTA reacts with 1 gram-ion of the metal,

regardless of its valence. The resulting complexes have the same composition, differing only in the charge they carry.

A metal indicator in an EDTA titration can be represented by the following expression :

M-In + EDTA * M-EDTA + In

where M-In = the metal indicator complex, M-EDTA = the metal-EDTA complex, and In = the indicator. The metal indicator complex must be weaker than the metal-EDTA complex. The color change occurs because the metal- indicator complex ionizes, and the free metal is completely complexed by the EDTA, leaving a free indicator.

Sample size

Because many petroleum-associated waters contain high concentrations of dissolved solids including calcium and magnesium, it usually is necessary to dilute them or to use a micropipet to obtain a small sample before performing a complexometric titration. The dilution and subsequent aliquot


TABLE 3.VIII

Aliquot size for total hardness, calcium, and magnesium determination

Specific gravity Dilution Aliquot (ml)

1 .ooo--1.010 none 50 1.010-1.025 none 25 1.025-1 .O 50 dilute 25 ml to 100 ml, 12.5

1.050-1.090 dilute 25 ml to 100 ml, 6.25

1.090-1.1 20 dilute 25 ml to 500 ml, 1.25

1.120-1.150 dilute 25 ml to 1,000 ml, 0.625

take 50 ml

take 25 ml

take 25 ml

take 25 ml

TABLE 3.IX

Comparison of errors in direct reading of sample size using a micropipet versus the dilution technique

Direct-reading using micropipet

sample size error (ml)

Dilution technique

ml taken after error

to 100 ml diluting 10 ml (ml)

~~

200 h f 0.004 2 f 0.01 500 h f 0.01 5 f 0.025

1,000 h * 0.002 10 f 0.005 1 ml f 0.006 10 * 0.005 2 ml f 0.006 20 f 0.009 5 ml f 0.01 50 * 0.02

size usually can be determined by using data such as that illustrated in Table 3.VII1, which is applicable to most oilfield brines.

A more rapid method of obtaining a fraction of a milliliter of a liquid sample is direct measurement using a micropipet. A micropipet in the hands of a competent analyst can also yield a more accurate sample size than the dilution technique illustrated in Table 3.VIII; e.g., two reading errors are omitted because only one meniscus reading is necessary with the direct measurement as compared to three using the dilution. Table 3.IX illustrates a comparison of errors in sample sizes of the direct reading method versus the dilution method.

Reagents: CDTA (disodium 1,2-cyclohexanediaminetet,raacetic acid) standard solution, approximately 0.025M: dissolve 10.66 g CDTA in water and dilute


to 1 liter. (To standardize, dissolve 2.4971 g calcium carbonate in the smallest amount of hydrochloric acid possible and dilute to 1 liter with water (0.025M Ca solution). Pipet triplicate 10-ml aliquots into flasks and dilute to approximately 50 ml with water. Begin at paragraph 2 of the procedure, and carry the standard solutions through all the steps of that paragraph. Calculate the molarity using the following equation:

10.0 x 0.025 0.25 or - V V

M =

where V = volume of CDTA required to titrate 10 ml of 0.025M calcium solution.

Sodium hydroxide: dissolve 320 g sodium hydroxide pellets in water and dilute to 1 liter.

Ammonium chlorideammonium hydroxide buffer solution : dissolve 67.5 g ammonium chloride in approximately 200 ml of water. Add 570 ml concentrated ammonium hydroxide and dilute to 1 liter with water.

Eriochrome Black T indicator (sodium 1-( l-hydroxy-2-naphthylaz0)-6- nitro-2-naphtol-4-sulfonate): dissolve 0.5 g of the indicator and 4.5 g of hydroxylamine hydrochloride in 100 ml of water.

Calcon: dissolve 0.4 g sodium 1-( 2-hydroxy-l-naphthylazo)-2-naphthol-4- sulfonate in 100 ml of methanol.

Triethanolamine: dilute 30 ml triethanolamine to 100 ml with water.

Procedure. Filter the sample to remove undissolved solids and traces of oil from the water. Transfer, by means of “Lambda” pipet or volumetric transfer pipet, an aliquot of sample containing not more than 10 mg of calcium into an Erlenmeyer flask. Dilute to approximately 50 ml with water. (No more than 10 ml of standard CDTA are to be used in a titration for either calcium or magnesium.)

Add two to three drops of triethanolamine solution and approximately 4 ml of sodium hydroxide solution. The pH of the solution at this point should be 12.0-12.5. Add six drops of calcon indicator and titrate with standard CDTA solution until the indicator blue endpoint is reached. Record the volume of CDTA titrant used to titrate calcium.

Using the same pipet, pipet another aliquot into another Erlenmeyer flask and dilute to 50 ml with water. Add two to three drops of triethanolamine solution, 3-5 ml of the ammonium chloride ammonium hydroxide buffer solution, and three to four drops of Eriochrome Black T indicator. Refill the buret with the same standard CDTA titrant and titrate the sample until the color changes from wine to pure blue. This endpoint is sometimes delayed, so proceed cautiously with the titration near the endpoint. Record the volume of CDTA used to titrate calcium and magnesium, or hardness (Ca + Mg).

TITRIM ETRIC METHODS 43

Calcu la t ions :

B x M x 100,100 sample volume = mg total hardness as CaC03 per liter

A x M x 40,000 sample volume = mg Ca per liter

(B-A) x M x 24,300 = mg Mg per liter sample volume

where A = calcium titer (blank); B = hardness titer (blank); and M = molarity of CDTA.

The complexometric determination of calcium and magnesium will give a precision of about 2% of the amounts present. The accuracy is dependent upon the interferences present, and the major interferences are strontium and barium, both of which will be complexed along with calcium, thus producing high results. In the absence of strontium and barium the accuracy of the method is about 4% of the amount of calcium and magnesium present.

Ammonium nitrogen

Organic compounds containing nitrogen decompose in a reducing environment and form ammonia and the ammonium ion. A reducing environment is characteristic of a petroleum genetic environment (Collins et al., 1969). Bogomolov et al. (1970) call it an indicator of petroleum.

The ammonium ion is too weak an acid to be successfully titrated; however, when treated with formaldehyde, hexamethylenetetramine and a strong acid are produced. This strong acid can be titrated with a base using indicators or a potentiometer to determine the endpoint.

Reagents. The necessary reagents are hydrochloric acid, 12N; sodium hydroxide standard, OJN, and 0.02N; and formaldehyde.

Equipment. The necessary equipment includes an expanded-scale pH meter, a hotplate, microburets, flasks, and an ice-water bath.

Procedure. The method should not be used if less than 5 mg/l of ammonium nitrogen is present. Acidify the brine or water when sampling to a pH of about 1.5 with 12N HC1. The acid will stabilize the sample by changing to the ammonium ion any ammonium hydroxide which could volatilize as ammonia and be lost. Transfer a 100-ml aliquot of the acidified sample to a 250-ml Erlenmeyer flask and boil the solution for 5 minutes on a hotplate. Cool the solution as quickly as possible to about 25°C. An ice bath will facilitate .rapid adjustment to this temperature.


Using an expanded-scale pH meter, adjust the pH of the sample to 7.0 with 0.1N NaOH, add 5 ml of 37 wt.% formaldehyde solution, and heat the mixture to 4OoC. (Do not exceed this temperature.) Cool immediately to ambient temperature using an ice water bath, and titrate the sample with 0.02N NaOH to pH 8.6 using an expanded-scale pH meter to detect the endpoint .

The weak hydroxide titrant must be protected from atmospheric carbon dioxide, and a reagent blank must be determined because formaldehyde contains formic acid.

The reactions are :

6HCHO + 4NH4 C1 --f (CH2 )6 N4 + 4HC1+ 6H2 0 HC1+ NaOH + NaCl + H2 0

Calculation:

(ml NaOH x N used for sample) - (ml NaOH x N used for reagent blank) x 14,007

ml sample = mg/l NH4N

Chloride

A modification of the Mohr method (Furman, 1962) is satisfactory for the determination of chloride in petroleum-associated waters. Common interferences are bromide, iodide, sulfide, and iron. Sulfide can be removed by acidifying the sample with nitric acid and boiling. Iron can be removed by ion exchange or precipitation with sodium hydroxide or sodium peroxide followed by filtration.

Because most petroleum-associated waters contain high concentrations of chloride, it usually is necessary to dilute the sample before titrating with silver nitrate, because the voluminous precipitate masks the endpoint. About 50 mg of chloride is maximum for a satisfactory titration. The indicator usually is potassium chromate or sodium chromate, and at the endpoint the chromate ion combines with excess silver to form the slightly soluble red silver chromate:

Ag+ + C1- + AgCl ZAg+ + --f Ag2Cr04

The specific gravity of the sample can be used t o estimate the correct aliquot size. Table 3.X indicates aliquot sizes that will contain less than 50 mg of chloride. The micropipet can be used as demonstrated in the calcium-magnesium procedure and Table 3.IX.


TABLE 3.X

Aliquots that contain less than 50 mg of chloride as estimated from the specific gravity

Specific gravity

1.000-1.002 1.003-1.004 1.005-1.012 1.01 3-1.019 1.020-1.032 1.033-1.064 1.065-1.087 1.088-1.162 > 1.163

Dilution

none none dilute 10 ml to 100 ml, take 50 ml dilute 10 ml to 100 ml, take 20 ml dilute 10 ml to 100 ml, take 10 ml dilute 25 ml to 500 ml, take 10 ml dilute 20 ml to 500 ml, take 10 ml dilute 10 ml to 500 ml, take 10 ml dilute 10 ml to 1,000 ml, take 10 ml

-

Aliquot (ml)

100 50

5.0 2.0 1.0 0.5 0.4 0.2 0.1

Reagents. The necessary reagents include silver nitrate, standard solution, 0.05N; potassium or sodium chromate, neutral 5% aqueous solution; and nitric acid, 0.1N (nitrous free); and sodium bicarbonate.

Equipment. The necessary equipment includes a hotplate, a 10-ml microburet, flasks, and pipets.

Procedure. After removal of interferences and selection of correct aliquot size, dilute the sample to 20 ml or more, adjust the pH to 8.3 with sodium bicarbonate or 0.1N nitric acid, add 1 ml of a 5% aqueous potassium chromate solution, and titrate with an 0.05N silver nitrate solution until the red endpoint just persists.

Calculation:

ml AgN03 x N x 35,500 = mg,l cl- ml sample

The precision and accuracy of the method are about 1% and 2%, respectively, of the amount present.

Bromide and iodide

Bromide and iodide are present in almost all petroleum-associated waters. In the following procedure, iodide is selectively oxidized t'o iodate with bromine water; excess bromine is reacted with sodium formate. The iodate reacts with added iodide t o produce iodine which is titrated with thiosulfate. Hypochlorite is added to another sample to oxidize both bromide and iodide to bromate and iodate, respectively. Excess hypochlorite is reacted with sodium formate, and the bromate and iodate are reacted with iodide to liberate iodine for titration with thiosulfate.


Iron, manganese, and organic matter can interfere but are removed in the procedure. Fluoride is added to mask interference from any remaining traces of iron.

Reagents. The necessary reagents include a 2% ammonium molybdate solution; glacial acetic acid; calcium hydroxide; calcium carbonate; 0.05N hydrochloric acid; 6N hydrochloric acid; potassium iodide; sodium fluoride; starch indicator solution; 0 . O l N sodium thiosulfate (standardize prior to use); 3.8M sodium formate (prepare fresh daily); saturated bromine water; and methyl red indicator solution.

Equipment. The necessary equipment includes a mechanical shaker, 200-ml bottles, a hot-water bath, flasks, pipets, and microburets.

Procedure. To remove iron, manganese, and organic matter from the sample, add exactly 100 ml of sample to a stoppered bottle. Add 1 g of calcium hydroxide, and place the mixture in a shaker for 1 hour. Allow the mixture to stand overnight and filter through a dry folded filter, discarding the first 20 ml that comes through. Brines with specific gravities of less than 1.009 may be filtered without standing overnight. Prepare a blank in the same manner.

Transfer an aliquot of the filtrate containing 1-2 mg of iodide to a 250-ml Erlenmeyer flask. Add sufficient water t o make the total volume 75 ml, and three drops of methyl red indicator. Add 0.05N hydrochloric acid until the mixture is just slightly acid, add 10 ml of sodium acetate solution, 1 ml of glacial acetic acid, and 4 ml of bromine water, and allow to stand for 5 minutes. Next add 2 ml of sodium formate solution, blow out any bromine vapor from the neck of the flask, and wash down the sides with water.

When the solution is completely colorless, add 0.2 g of sodium fluoride and 0.5 g of potassium iodide. Mix until dissolved and add 15 ml of 6N hydrochloric acid. Titrate with 0.01N sodium thiosulfate using starch indicator. Disregard any return of blue color after the endpoint. Record this titration volume for the iodide calculation.

Transfer another aliquot of the filtrate containing 1-2 mg of bromide t o a 250-ml Erlenmeyer flask and add sufficient water to make the total volume 75 ml. Add 10 ml sodium hypochlorite solution and approximately 0.4 g of calcium carbonate (or enough so that approximately 0.1 g will remain after the next step). Adjust the pH of the solution with 3N hydrochloric acid to between 5.5 and 6.0 and heat in a water bath to 90°C for 10 minutes. (A small amount of undissolved calcium carbonate should remain at this point.)

Remove the flask and cautiously add 10 ml of sodium formate solution, return the flask to the water bath, and keep the contents hot for 5 minutes more and observe the timing very closely. Rinse down the inside of the flask with a few milliliters of distilled water and allow the solution to cool to room temperature. (Do not use a cold water bath.) To the ambient solution

TITRlMETRIC METHODS 47

add three drops of ammonium molybdate solution, 0.5 g sodium fluoride (if iron is present), and 0.5 g potassium iodide, mix until dissolved, and acidify with 15 ml of 6N hydrochloric acid. Titrate with 0.OW sodium thiosulfate using starch indicator. Disregard any return of blue color after the endpoint. Record this titration for the bromide calculation.

Calculations. Iodide: ml of Na, S2 O3 for sample - ml of Na, S2 O3 for blank = corrected ml of Na, S2 O 3 :

(ml x N) Na2S203 x 21,150- - mg/l I- ml sample

Bromide: ml of Na2 S2 O3 for sample - ml of Na2 S2 O3 for blank = corrected ml of Na2S203 :

(ml x N) Na, S 2 0 3 x 13.320 ml sample - mg/l I- x 0.63 = mg/l Br-

The precision and accuracy of the method are about 3% and 676, respectively, of the amounts of bromide and iodide present.

Oxygen

The solubility of a gas varies directly with pressure and inversely with temperature and usually is reduced by the presence of dissolved minerals. Most petroleum-associated waters contain little or no dissolved oxygen in situ at depth. Knowledge of the dissolved oxygen content of waters that are to be reinjected for waterflooding or disposal is needed to determine treatment required to prevent corrosion. Instrumental and wet chemical methods (American Petroleum Institute, 1968) are available for the determination of dissolved oxygen. Instrumental methods usually are modifications of the rotating platinum electrode method (Marsh, 1951), but with them the residual current (when no oxygen is present) is difficult to determine. The modified Winkler method probably is the most accurate wet chemical method available (Watkins, 1954).

In the Winkler method for quantitatively determining dissolved oxygen in water, a glass-stoppered bottle is completely filled with the water to be tested. Manganous sulfate (MnS04 ) and potassium hydroxide (KOH) are added, forming a precipitate of manganous hydroxide (Mn(OH), ) in accordance with the following reaction:

MnS04 + 2KOH + Mn (OH), + K2S04

The manganous hydroxide combines with the oxygen dissolved in the water to form a higher oxide of uncertain composition, assumed to be manganese hydroxide (MnO(OH), ), as follows:

2Mn (OH), + 0, + MnO (OH),


On acidification in the presence of an iodide, the higher oxide of manganese liberates a quantity of iodine stoichiometrically equivalent to the quantity of dissolved oxygen present in the sample in the following manner:

MnO (OH), + 2H2 SO4 +. Mn(S04 )Z + 3H20 Mn(S04), + 2KI +. MnS04 + K2S04 + I2

The quantity of iodine liberated is determined by titrating an aliquot portion of the sample with a standard solution of sodium thiosulfate (Na2S203) using starch solution as an indicator, as shown by the equation:

2Na2 S, O3 + I, +. Na, S4 0, + 2NaI

The iodine modification of the Winkler method depends upon the conversion of any hydrogen sulfide to hydrogen iodide and free sulfur by reducing the iodine added to the brine. This reaction proceeds as follows:

H,S+I2 + 2 H I + S

Tests have shown that interfering substances other than hydrogen sulfide that might be present in oilfield brines also are counteracted by the iodine added.

Reagents. It is important to use sterile glassware or polyethylene bottles in preparing and storing reagents for this test to prevent contamination and to make longer storage of reagents possible without appreciable changes in their normality.

Iodine solutions, 0.5N and 0.W. Hydrogen sulfide water: saturate distilled water (which has been boiled

and cooled recently to drive off dissolved oxygen) with hydrogen sulfide gas. Starch solution. Manganous sulfate solution: dissolve 480 g of manganous sulfate

(MnS04 *4H2 0) or 400 g of manganous sulfate (MnS04 *2H2 0) in distilled water, filter, and dilute to 1 liter.

Alkaline iodide solution: dissolve 700 g of potassium hydroxide (KOH) or 500 g of sodium hydroxide (NaOH) and 150 g of potassium iodide (KI), or 135 g of sodium iodide (NaI). in distilled water, and dilute the solution to 1 liter. If a white carbonate precipitate is formed, separate the precipitate by settling and then siphoning off the supernatant liquid. The solution should give no color with starch indicator when diluted and acidified, which indicates the absence of nitrates, iodates, and ferric salts.

Sulfuric acid, concentrated. Sodium thiosulfate solution, 0.1N. Standard sodium thiosulfate solution, 0.025N.


Equipment. The necessary equipment includes glass-stoppered bottles, pipets, flasks, and microburets.

Sa mp 1 ing

Care must be taken to obtain uncontaminated samples of water for determining dissolved gases. Glass-stoppered bottles should be used for sample containers. To determine dissolved oxygen in water, 300-ml bottles with pointed, ground-glass stoppers and overflow lips of the type used for biochemical oxygen-demand tests are particularly suitable. These bottles are so designed that samples may be obtained without contamination by atmospheric oxygen and so the necessary chemical reagents may be introduced during the analysis without excessive overflow from the lip of the bottle.

Before a sample is taken, rinse the bottle three times with the water to be sampled and fill through a rubber tube extending to the bottom of the bottle. A quantity of water equal to at least three times the capacity of the bottle should be allowed to overflow the bottle, and the rubber tube should be withdrawn slowly so that the space in the bottle occupied by the tube is filled simultaneously with water. The glass stopper, when placed in the mouth of the bottle, will displace all excess water. If any bubbles are seen, the sample is immediately analyzed. If the temperature of the water taken for analysis of dissolved gases is above 2OoC, a cooling coil should be used to cool the sample before the water enters the bottle. It is important that the samples contain no included atmospheric oxygen or carbon dioxide, as errors may be introduced into many of the analyses if extraneous oxygen or carbon dioxide is present in the water.

Procedure. All reagents in the following steps 1 through 8 should be added slowly and carefully under the surface of the water near the bottom of the bottle, using pipets, permitting the displaced water to overflow the top of the bottle. The quantities of reagents added should be recorded for use in the final calculation. After each reagent is added, the stopper should be carefully replaced and the bottle inverted gently several times so as not to introduce air into the bottle while adding and mixing reagents.

Collect the sample as described previously. Add excess 0.5N iodine solution to give the sample a yellow color and let stand 5 minutes. Add saturated hydrogen sulfide water until the sample is a very light straw-yellow, and 1 ml of starch solution as an indicator. Add dilute hydrogen sulfide water until the blue color just disappears and then add, drop by drop, 0.1N iodine solution until a faint blue color persists. Add 1 ml of manganous sulfate solution, 1 ml of alkaline iodide solution, and 1 ml of concentrated sulfuric acid, letting it run down the neck of the bottle.

Transfer 200 ml of the solution by pipet from the sample bottle to a 500-ml Erlenmeyer flask. Titrate the 200-ml sample in the Erlenmeyer flask with 0.025N sodium thiosulfate solution. The starch indicator should be


added when the yellow color of free iodine has been almost eliminated by the sodium thiosulfate titration, and the titration should be continued until one drop changes the solution from a light blue to colorless. (Subsequent blue recoloration should be disregarded.)

If no hydrogen sulfide or other interfering substances are present, the first six steps of the determination may be eliminated, using only the part of the procedure starting with the addition of the alkaline iodide solution.

Calculation. The dissolved oxygen content of the water is determined by the following equations:

x-( Y-1) v = 200 200 w u=-

V

where U = dissolved oxygen content, ppm; V = volume of sample titrated, ml; W = volume of 0.025N sodium thiosulfate required, ml; X = volume of sample bottle, ml; Y = total volume of all reagents added, ml; and 1 = the 1 ml of acid added, which does not change the effective oxygen-tested volume of the sample because it is added after all the oxygen has been absorbed.

The factor used to take into account the volume of reagents added may involve a slight error, because it is based on the assumption that the reagents contain no dissolved oxygen.

Carbon dioxide

Petroleum-associated waters containing carbon dioxide and bicarbonate or carbonate will contain a weak acid H2C03 or its salt, which buffers the solution. This combination controls the pH of waters in the range of about pH 4.5-8.0. Such buffering is caused by the presence of slightly dissociated acids or bases, and when H+ or OH- ions are added they first convert the undissociated acid or base to its salt or vice versa. Loss of carbon dioxide will disturb the carbon dioxide-bicarbonate-

carbonate buffer systems. For example, the pH probably will change and precipitation of calcium carbonate or other compounds may occur. An increase in carbon dioxide will shift t h e . carbon dioxide-carbonate- bicarbonate equilibria, allowing more material such as calcite to go into solution.

Bacterial reduction of sulfate can cause the amount of dissolved carbon dioxide and hydrogen sulfide in petroleum-associated waters to be quite high. Several hundred milligrams per liter of C02 can be present in such waters. Knowledge of the amount of carbon dioxide in solution is useful in carbonate equilibria studies (Garrels and Christ, 1965) and in water compatibility studies (Watkins, 1954).

TITR IMETR IC METHODS 51

Reagents. The necessary reagents are 0.05N sodium carbonate solution and phenolphthalein indicator solution.

Procedure. Collect the water sample in the same manner used in taking the sample to be analyzed for dissolved oxygen. Pipet 100 ml of the water into a flask and add five drops of phenolphthalein indicator. If the sample turns red, no free carbon dioxide is present; if it remains colorless, titrate the sample with the standard sodium carbonate solution to a red endpoint.

Calcula tion :

ml Na2 CO, x N x 22,000 = mg/l C02 ml sample

Sulfide

As mentioned above, the bacterial reduction of sulfate causes some petroleum-associated waters to contain appreciable concentrations of hydrogen sulfide. Knowledge of the amount of dissolved sulfide present is necessary for corrosion and water compatibility studies (Watkins, 1954).

The following method depends upon the reduction of iodine by the hydrogen sulfide in the brine, as shown by the following equation:

H2S+I2 + 2 H I + S

Because of the unstable nature of the hydrogen sulfide in solution in waters and brines, the sulfide is not titrated directly. To prevent the loss of hydrogen sulfide to the air, an excess of iodine solution is added, and the sample is back-titrated with standard sodium thiosulfate solution, in accordance with the following equation:

2Na2 S2 0, + I2 +. Na2 S4 O6 + 2NaI

Experiments conducted by the US. Bureau of Mines indicate that residual reducing agents that cannot be removed by aeration or boiling are present in some oilfield brines. Brine from the Arbuckle (siliceous) Limestone formation originally containing 96 mg/l hydrogen sulfide showed such residual reducing agents to equal 9 mg/l of hydrogen sulfide after air has been bubbled through the brine for 28 hours. This dropped to 4 mg/l after standing another 24 hours. Further tests in which the hydrogen sulfide was driven off by boiling indicated the presence of 5 mg/l residual reducing agents. When the brine was neutralized with hydrochloric acid (using methyl orange indicator) before boiling, residual reducing agents equal to 2 mg/l hydrogen sulfide remained.


Reagents. The necessary reagents are potassium iodide, standard sodium thiosulfate, 0.1N and 0.01N; standard iodine solutions, 0.1N and 0.01N; and starch indicator solution.

Procedure. Collect the sample in a glass-stoppered bottle (approximately 200-mi capacity) in the manner previously described for dissolved oxygen. Analysis should be made as soon as possible after sampling.

Pipet 5 ml of 0.1N or 0.01N standard iodine solution, depending upon the hydrogen sulfide concentration expected, into each of two Erlenmeyer flasks. It may be necessary to use a larger quantity of 0.01N solution if the hydrogen-sulfide content of the sample is high.

Add approximately 1 g of potassium iodide crystals to each flask. (This step usually may be omitted in determinations on brine samples because of the high mineral content of the water.) Add 50 ml of distilled water to the flask to be used for a blank determination, and pipet 50 ml of the water sample into the other flask. Titrate both the distilled water blank and the water sample with standard sodium thiosulfate solution of the same normality as the iodine solution used, adding 1 ml of starch indicator near the end of the titration. Record the milliliters of thiosulfate used in each titration.

Calculation. Subtract the milliliters of thiosulfate solution used for the sample from the milliliters used for the blank and use the difference in the following formula:

(ml x N ) I2 - (ml x N) Na2S203 x 17,000 ml sample = mg/l H2 S

Sulfur compounds

The redox potential of petroleum-associated waters indicates that sulfur compounds other than sulfate and sulfide may exist in solution. When the water is brought to the land surface, the change in pressure and temperature will affect the redox potential and, if the sample is allowed to come into contact with the atmosphere, the equilibria of the sample will start to change immediately. Better methods are needed to determine the composition of a water in situ. The following method can be used to gain a semiqualitative estimation of the amomts of thiosulfate, sulfite, and sulfide in a water.

Reagents. Zinc carbonate suspension: add zinc acetate to a solution of sodium carbonate, filter and wash the precipitate with several volumes of cold water. Prepare the zinc carbonate suspension by vigorously shaking the precipitate with water.

The other reagents are glycerol iodine, 0.01N; sodium thiosulfate, 0.01N; starch indicator solution; glacial acetic acid; and formaldehyde.

FLAME SPECTROPHOTOMETRIC METHODS 53

Determination o f thiosulfate, sulfate, and sulfide

Procedure. Collect a water sample as described in the dissolved oxygen procedure. Pipet 100 ml of the sample into a 300-ml flask, and add 20 ml of glycerol, 100 ml of an aqueous suspension of zinc carbonate, and 70 ml of distilled water. Shake the mixture vigorously for 1 minute, filter, and discard the precipitate.

Pipet 50 ml of the filtrate into a flask and add 5 ml of formaldehyde, and 3 ml of acetic acid, add starch indicator and titrate to the blue endpoint with 0.01N iodine. Record the amount of iodine used to calculate thiosulfate (A).

Pipet another 50-ml aliquot of the filtrate into another flask; add 0.01N iodine until the solution remains yellow. Add starch indicator and titrate to a colorless endpoint with 0.Ol.N sodium thiosulfate. Record the amount of iodine used for thiosulfate plus sulfite (B).

Pipet 25 ml of water that was not treated with the zinc carbonate into a flask and add an excess of 0.Ol.N iodine, 3 ml of acetic acid, add starch indicator and titrate to the colorless endpoint with 0.01N sodium thiosulfate, sulfite, and sulfide (C).

Calculations. Milliliters iodine used in A = X ml X ml x N x 112,000

ml sample = mg/l S2 03-2

Milliliters iodine used in A - milliliters iodine used in B = Y ml

Y ml x N x 40,000 ml sample = mg/l SO,-2

Milliliters iodine used in C - milliliters iodine used in B = 2 ml

2 ml x N x 16,000 ml sample = mg/l S-’

FLAME SPECTROPHOTOMETRIC METHODS

When a metal salt in solution is sprayed into a flame, the solvent evaporates and the salt decomposes and vaporizes, producing atoms. Some of these atoms can be raised to an excited state by the thermal energy of the flame, although a major portion of the atoms present in the flame remain at the grourid state. The return of the excited atoms to the ground state results in the emission of radiant energy characteristic of the element atomized. The quantitative measurement of this radiation is the basis of emission flame spectrophotometry, and the essential difference between this form of analysis and classical arc-emission spectrography is the temperature of the source used to excite the atoms. Because the gasa i r and gas-oxygen flames


are much cooler than the spark and arc sources used in spectrography, analysis by emission flame spectrophotometry is usually limited to the more easily excitable elements - lithium, sodium, and potassium.

Instrumentation requirements include: (1) A method of introducing the sample into the flame for vaporization. (2) A method of detecting and recording the radiation intensity emitted. (3) A method of selecting the correct wavelength, ordinarily a variable

monochromator. A more complete discussion of the theory and instrumentation can be

found in books by Burriel-Marti and Ramirez-Munoz (1957) and Dean (1960), as well as in publications of commercial instrument manufacturers.

Lithium

Lithium usually is calculated as a part of the sodium content in reporting the results of oilfield water analyses rather than being determined and reported separately. One of the more accurate methods to determine lithium in petroleum-associated waters is the flame spectrophotometric method (Collins, 1962).

Reagents. The reagents are lithium, standard solutions, 0.1 mg/ml and 0.01 mg/ml; and n-propanol.

Equipment. The necessary equipment includes a flame spectrophotometer, 10-ml 'microburets, and volumetric flasks.

Preliminary calibration curves. Preliminary calibration curves are useful in determining approximately how much lithium is in the sample and in determining the optimum amount of standard lithium solution to use in the analysis. Because n-propanol is easier to work with, it usually is used; however, if additional sensitivity is needed, the acetone-n-amyl alcohol mixture can be used (Collins, 1965).

To prepare the preliminary calibration curves, transfer to 50-ml volumetric flasks aliquots of diluted standard lithium solution containing the following amounts of lithium: 0.01 mg, 0.05 mg, 0.1 mg, 0.15 mg, and 0.2 mg. Add 20 ml of n-propanol to each flask and dilute to volume with distilled water. Aspirate, burn, and record the emission intensity of each of these five standards at 670.8 mp and their background at about 665 mp. Record several peaks for each standard at various sensitivity levels and slit widths.

Plot the results on linear graph paper by plotting milligrams of lithium versus intensity. Prepare a curve for each sensitivity level and slit width used, as illustrated in Fig. 3.2. The sensitivity of the instrument will determine the optimum concentrations of lithium and this will require some experimenta- tion.

The analyst may find it convenient to scan all the emission lines of


26 - 1 ' I I I I 2 4 ~ 0.01 mm r l i t 22- - tOppri 02

- - x 20- 5 p s i C2H2 0 0 18- 12.5 mm burner height L -

-

1,620 volta to I T 1 F W 6836

- - - -

5 10- - - - L

- - - -

mg L i / m l 50% n-PROPANOL

Fig. 3.2. Preliminary calibration curves for use in selecting optimum standard additions: Instrument: 0.01-mm slit, 1,620 V to ITT FW 6836, 10 psi 02, 5 psi C2HZ, and 12.5-mm burner height.

interest; e.g., lithium, sodium, potassium, rubidium, cesium, and perhaps others. This will give information concerning what elements are present.

Procedure. To determine the amount of lithium in the petroleum-associated water, transfer an aliquot of about 10 ml of brine to a 50-ml volumetric flask, add 20 ml of n-propanol, and dilute to volume with distilled water. (The size of the aliquot will vary with the sample. The specific gravity can be used to help decide the aliquot size. For a brine with a specific gravity of 1.1, an aliquot of 10 ml or less probably will be sufficient.) Aspirate the sample into the flame and read or record the emission intensity of the background at 665 mp and lithium line at 670.8 mp. With these readings and the preliminary calibration curves, calculate approximately how much lithium is in the sample.

Determine an aliquot size that will contain about 0.05 mg of lithium. Transfer equal aliquots to three 50-ml volumetric flasks. Add no lithium standard to the first flask, 0.05 mg to the second flask, and 0.1 mg to the third flask. Add 20 ml of n-propanol to each flask and dilute to volume with distilled water.

Aspirate and record the background at 665 mp and the emission intensity of each sample at 670.8 mp. Optimum accuracy is attained by this method when the two standard additions are respectively equal to and twice the amount of lithium in the sample. Care should be taken that too much lithium is not present in the final samples, because self-absorption will cause errors.

56

5

4

v) 13

r

a

a . x 2

2 3 W

c

I u

1

0

ANALYSIS OF OILFIELD WATERS

L I

COI t

2 s

I I I I I 3 4 5 6 7

ENTRATION OF STANDARD - ADDITIONS

Fig. 3.3. Standard-addition calculation graph. In this ideal case the unknown would contain 2 x the dilution factor (2 could be 2 mg or 2 pg or whatever unit the analyst used).

Calculation. A graph can be used in the calculation, as illustrated in Fig. 3.3. Plot the concentrations in milligrams of the standard-addition samples on the horizontal axis of linear graph paper and the emission intensities on the vertical axis. Plot the emission intensity of the sample to which no standard lithium soiution was added at 0 concentration. The plot should produce a straight line as shown in Fig. 3.3.

Multiply the chart reading at 0 concentration by 2, place this value on the y-axis, and draw a line parallel to the x-axis until it intersects the line plotted. From this point, draw a line parallel to the y-axis until it intersects the x-axis. The vrlue obtained in milligrams can be converted to milligrams per liter by the following formula:

mg Li x 1,000 = mg/l Li+ ml sample

The formula, shown in Table 3.X1, can be used to calculate the amount of lithium in the sample, using the flame spectrophotometric readings in lieu of the graph method. Optimum accuracy is attained with this method using either type of calculation when the two standard additions respectively are equal to and twice the amount of lithium that is present in the sample. The addition of alcohols to the aqueous phase before aspiration into the flame increases the sensitivity of the flame method, allowing the use of more dilute solutions and consequently less dissolved solids, which reduces burner plugging. The average precision and accuracy of the lithium method are about 2% and 4%, respectively, of the amount present.


TABLE 3.XI

Formula for standard-addition calculation C, = (rx - r b ) - where the following are true*:

Solution Concentration Reading

C r - r ,

. .-

Unknown c, r,

Mixture . c, = c, + c r

*C is a standard addition.

Sodium

The flame spectrophotometer offers an excellent instrumental technique for determining sodium in a petroleum-associated water. The flames containing alkali metals give strong resonance lines of these metals plus some additional continyous radiation. The strongest line for sodium results from a transition between the lowest excited level and the ground state. The yellow doublet of sodium at 589.0-589.6 mp results from such a transition.

Reagents. The necessary reagents are sodium standard solutions, 1 mglml and 0.01 mg/ml; and n-propanol.

Preliminary Calibration curves. Preliminary calibration curves similar to those shown in Fig. 3.2 should be used to determine the approximate amount of sodium in the sample. These curves are prepared in the same manner as the lithium curves, except that standard sodium solutions are used; the emission intensity of the sodium at 589 mp is determined, minus a background at about 582 mp.

Procedure. To analyze the petroleum-associated water, transfer an aliquot of water to a 50-ml volumetric flask, add 20 ml of n-propanol, and dilute to volume with distilled water. (The size of the aliquot will vary with the sample. The specific gravity can be used to help decide the aliquot size. For a water with a specific gravity of 1.1, an aliquot of 1 ml or less probably will be sufficient.) Aspirate the sample into the flame and record the emission intensity of the background at 582 mp and sodium line at 589 mp. With these readings, calculate approximately how much sodium is in the sample by using the preliminary calibration curves.

Determine the aliquot size that will contain about 0.05 mg of sodium. Transfer equal aliquots to three 50-ml volumetric flasks. Add no sodium


standard to the first flask, 0.05 mg to the second flask, and 0.1 mg to the third flask. Add 20 ml of n-propanol to each flask and dilute to volume with water. Aspirate and record the emission intensity of each sample at 589 mp and its background at 582 mp.

Calculation. Use the graph or formula illustrated in the lithium method. The value obtained in milligrams can be converted to milligrams per liter by the following formula:

mg Na x 1,000 ml sample = mg/l Na'

The precision and accuracy of the method are approximately 3% and 6%, respectively, of the amount of sodium present. Some elements, when present in the solution being analyzed, will cause a change in the emission intensity of the sodium. The use of a standard addition technique largely compensates for these interferences.

Potassium

Potassium usually is included with sodium without any differentiation in reporting the results of brine analyses, although potassium is known to be present in many oilfield brines. Potassium compounds often are dissolved before sodium compounds; however, they do not remain dissolved as readily because they are readily adsorbed and enriched in clays. In sea water and oilfield brines, only a small part of the originally dissolved potassium remains in solution. The fact that many oilfield brines are low in potassium with respect to sodium, whereas surface waters and young volcanic waters are enriched in potassium with respect to sodium, is an important criterion in identifying the sources of brines.

The flame spectrophotometer provides a sensitive method for the determination of potassium. The strongest lines for potassium detection in a flame are the doublet at 766.5 and 769.9 mp.

Reagents. The necessary reagents are potassium standard solution, 0.1 mg/ml; and n-propanol.

Preliminary calibration curves. Preliminary calibration curves are useful in determining the approximate amount of potassium in the sample, so that the optimum sample size for standard addition can be selected for the analysis. These curves can be prepared in the same manner used in the preparation of the lithium preliminary calibration curves (Fig.3.2) except that standard potassium solutions are used. The emission intensity of the potassium line at 766.5 mp minus the background at about 750 mp can be used in preparing the curves.


Procedure. To determine the amount of potassium in the sample, transfer an aliquot of sample to a 50-ml volumetric flask, add 20 ml of n-propanol, and dilute to volume with distilled water. The specific gravity can be used to help decide the aliquot size. For a brine with a specific gravity of 1.1, an aliquot of 5 ml or less probably will be sufficient. Aspirate the sample into the flame and record the emission intensity of the background at 750 mp and potassium line at 766.5 mp. With this reading, use the preliminary calibration curves and calculate approximately how much potassium is in the sample.

Determine an aliquot size that will contain about 0.05 mg of potassium. Transfer equal aliquots to three 50-ml volumetric flasks. Add no potassium standard to the first flask, 0.05 mg to the second flask, and 0.1 mg to the third flask. Add 20 ml of n-propanol to each flask and dilute to volume with distilled water. Aspirate and record the emission intensity of each sample at 766.5 mp and the background at 750 mp.

Optimum accuracy is attained by this method when the two standard additions are respectively equal to and twice the amount of potassium in the sample. Care should be taken that too much potassium is not present in the final samples, because self-absorption will cause errors.

Calculation. The graph or formula illustrated in the lithium method can be used. The value obtained in milligrams can be converted to milligrams per liter by the following formula:

mg K x 1,000 ml sample = mg/l K+

The precision and accuracy of the method are approximately 2% and 4% of the amount present. Several elements can interfere in the flame analysis of potassium. Elements which ionize easily will lower the degree of ionization of potassium, and elements which are difficult to ionize or have high ionization energies will give the opposite effect. By using the Saha equation (Herrmann and Alkemade, 1963), it is possible to estimate such interferences. Generally, the use of a standard addition compensates for interferences.

Rubidium and cesium

The flame spectrophotometer provides one of the most sensitive methods available for determining rubidium and cesium. Cesium has a pair of emission lines at 852.1 and 894.4 mp. Both lines are of about equal intensity, but water produces a molecular band system at 900 mp which can interfere at 894.4 mp. Rubidium also has two strong lines in the red region at 780.0 and 794.8 mp.

It is necessary to use a photomultiplier with an S-1 response to detect cesium and rubidium at the levels found in many waters. Examples of such tubes are ITT type 6836/FW118, RCA types 1P22 and 7102, and DuMont


type 6911. Such tubes also are useful for lithium and potassium determinations.

Several elements can interfere in the determination of cesium and rubidium. However, because a solvent extraction or standard-addition technique is used most interferences are either removed or compensated (Collins, 1965).

Reagents. The necessary reagents are cesium standard solution, 0.01 mg/ml; rubidium standard solution, 0.01 mg/ml; buffer solution, pH 6.6 (adjust the pH of a 1M sodium citrate solution to 6.6 with 0.5M nitric acid); sodium tetraphenylboron, 0.05M (dissolve 0.855 g of sodium tetraphenylboron in distilled water and dilute to 50 ml - prepare a fresh solution daily); nitroethane; hydrochloric acid, 0.1N; sodium hydroxide, 0.W; synthetic brine solution.

Procedure. To determine the amount of rubidium and cesium in the petroleum-associated water, transfer an aliquot of brine containing 0.005 to 0.05 mg of cesium and rubidium to a 100-ml beaker and add 25 ml of the citrate buffer solution. Transfer the solution to a 125-ml Teflon-stoppered separatory funnel and adjust to 100-ml volume. Add 2 ml of 0.05M sodium tetraphenylboron aqueous solution and 10 ml of nitroethane, and shake the mixture vigorously for 2 minutes. Allow the phases to separate for 30 minutes, after which time withdraw the aqueous phase. Centrifuge the nitroethane phase. Determine the cesium and rubidium emission intensities by burning the nitroethane phase in the flame spectrophotometer and automatically scanning the 780.0 mp, 794.8 mp, and 894.4 mp lines.

Calibration curves. Prepare calibration curves by using appropriate portions of the standard cesium and rubidium solutions. Add 5 ml of synthetic brine solution to each standard sample before buffering and extraction. Plot the resultant emission intensities versus milligrams of cesium or rubidium or linear graph paper.

Calculation. Determine the milligrams of cesium or rubidium in the sample by referring to the calibration curves. The milligrams can be converted to mg/l by the following formula:

mgx 1,000 ml sample = mg/l Cs+ or Rb'

Fig.3.4 illustrates the relative emission intensities obtained with cesium and rubidium in nitrobenzene, nitroethane, 1-nitropropane, and 2-nitropropane. 15 ml of each of these solvents.are used to extract 0.1 mg each of cesium and rubidium tetraphenylboron from aqueous solutions. The organic phases then are aspirated directly into the flame, and the peaks scanned automatically. Good resolution is obtained with a 0.01 mm slit width. Amy1 alcohol gives poorer results than nitrobenzene.

FLAME SPECTROPHOTOMETRIC METHODS

NITROBENZENE NITROETHANE I- NITROPROPANE 2 - NITROPROPANE

63

1 Fig. 3.4. Relative intensities obtained by burning organic solvents containing tetraphenylboron salts of cesium and rubidium.

Standard-addition technique to determine rubidium

Some waters contain sufficient rubidium to enable use of the standard- addition technique. To analyze such waters, preliminary calibration curves similar to those used to determine lithium (Fig.3.2) are recommended, to aid in selecting the optimum amount of standard rubidium solution to use.

Manganese

The amounts of sodium, potassium , calcium, and strontium in most petroleum-associated waters are too high to permit determination of manganese with the flame spectrophotometer without preliminary separations. These interferences can be obviated by extracting the manganese into a chloroform 8-hydroxyquinoline solution. The chloroform is removed by evaporation, and the manganese hydroxyquinoline is dissolved in n-propanol. This solution is burned in the flame spectrophotometer, and the emission intensity of its resonance triplet at 403.2 mp is recorded (Collins, 1962).

Reagents. The necessary reagents are standard manganese solution (dissolve 0.583 g of manganese dioxide in 10 ml of hydrochloric acid and dilute to 1 liter with distilled water, transfer a 100-ml aliquot of this solution to another


1-liter flask, add 10 ml of hydrochloric acid, and dilute to volume with distilled water; (1 ml of this solution contains 10 pg of manganese); chloroform solution of 8-hydroxyquinoline (dissolve 1 .O g of 8-hydroxyquinoline in 100 ml of chloroform); hydrogen peroxide (3% solution); ammonium hydroxide ( 3 N ) ; sodium potassium tartrate (10% solution); ammonium fluoride (5% solution); n-propanol; and chloroform.

Procedure. Transfer an aliquot of brine containing up to 150 pg of manganese to a 100-ml beaker; add 1 ml of hydrogen peroxide, 5 ml of ammonium fluoride, and 10 ml of sodium potassium tartrate; and adjust the pH of the mixture to 9.0 with ammonium hydroxide. Transfer the solution to a 125-ml Teflon-stoppered separatory funnel, add 10 ml of 8-hydroxyquinoline chloroform solution, and bring the mixture to equilibrium by shaking it vigorously for 1 minute.

Draw the chloroform phase off into a 100-ml beaker and strip the aqueous phase by an additional extraction with chloroform. Evaporate the combined chloroform extracts to dryness over a hotplate, taking care to prevent the residue from charring. Dissolve the residue in n-propanol and make to 50 ml volume with n-propanol. Aspirate the n-propanol solution directly into the flame and determine the net emission by subtracting the background emission at 400 mp.

Calculate the amount of manganese in the sample from a calibration curve prepared by adding known amounts of manganese to a synthetic brine solution. The calibration curve should be linear for up to 150 pg of manganese when the emission intensity is plotted versus micrograms of manganese on linear graph paper.

Calculation :

pg Mn (from curve) ml sample

The intensity of the emission of manganese in a flame spectrophotometer is enhanced by a factor of 16 by using n-propyl alcohol rather than water as the solvent. With this increased intensity, the sensitivity of the method is about 1 mg/l, although additional sensitivity is attainable by concentrating the brine by evaporation. The precision of the method is about 3%, and the accuracy is about 6% of the amount present.

= mg/l Mn +*

Strontium

Several flame photometric methods are available for determining strontium in oilfield brines; a standard curie may be unreliable if there are instrument changes, such as a slightly plugged burner, change of resistance in the amplifying circuit, or other variables. Chemical precipitation of strontium as the sulfate does not satisfactorily separate strontium from barium


and calcium without several preliminary separations. Precipitations as the carbonate or oxalate have the same disadvantages, and precipitation as the nitrate and subsequent solvent extraction of calcium with butylcellosolve still leaves barium in the precipitate. The use of a standard addition flame photometric method gives reproducible results without the necessity of several separations.

Reagents. The necessary reagents are standard strontium solution, 1 mg/ml; and n-propanol.

Preliminary calibration curves. To determine approximately how much strontium is present in the samples, it is advantageous to prepare preliminary calibration curves. A procedure similar to that used in the lithium method can be used, except that the strontium emission should be determined at 680 mp with a background reading at 690 mp. The data are plotted in a manner similar to Fig. 3.3.

Procedure. To determine the amount of strontium, transfer an aliquot of brine to a 50-ml volumetric flask, add 20 ml of n-propanol, and dilute to volume with distilled water. Aspirate the sample into the flame and read; record the emission intensity of the background at 690 mp and the strontium line at 680 mp. With these readings and the preliminary calibration curves, calculate approximately how much strontium is in the sample.

Determine an aliquot size that will contain about 1.0 mg of strontium. Transfer equal aliquots to three 50-ml volumetric flasks. Add no strontium standard to the first flask, 1.0 mg to the second flask, and 2.0 mg to the third flask. Add 20 ml of n-propanol to each flask and dilute to volume with distilled water. Aspirate and record the background at 690 mp and the emission intensity of each sample at 680 mp.

Calculation. A graph can be used in the calculation as illustrated in Fig.3.3. The value obtained in milligrams can be converted to milligrams per liter by the following formula:

mg Sr x 1,000 ml sample = mg/l Sr+*

The formula, shown in Table 3.X1, can be used to calculate the amount of strontium in the sample using the flame spectrophotometric readings in lieu of the graph method.

Barium

A flame spectrophotometric method was developed which utilizes the chromate precipation followed by dissolution in nitric acid, mixing with an alcohol, and burning in the flame (Collins, 1962). The flame method is

64 ANALYSIS OF OILFJELD WATERS

subject to few interferences except from calcium, but by using the chromate precipitation, calcium is eliminated and barium is concentrated.

Reagents. The necessary reagents are barium standard solution, 1 mg/ml; ammonium chromate solution (dissolve 10 g of ammonium chromate in distilled water and dilute to 100 ml); 10% ammonium acetate aqueous solution; nitric acid (4N) ; n-propanol; acetic acid; and synthetic brine solution (use carbon dioxide-saturated distilled water and dissolve the following amounts of constituents in 1 liter of water: sodium bicarbonate, 0.4 g; sodium chloride, 61 g; potassium. chloride, 5 g; calcium chloride, 19 g; magnesium chloride, 12 g; and strontium chloride, 5 g).

Procedure. Transfer an aliquot of the sample containing 0.5-15 mg of barium to a 100-ml beaker, add 1 ml of the ammonium acetate solution, 10 ml of the ammonium chromate solution, and adjust the pH to 4.6 using acetic acid. Cover the beaker with a watchglass; heat the solution to near boiling (90°C), remove from the hotplate, and allow to stand for 1 hour. Filter the solution through a 0.45-pm membrane filter using vacuum. Take care to transfer all of the precipitate from the beaker to the filter funnel. Use ammonium chromate solution rather than distilled water to aid in this transfer.

Wash the precipitate with 50 ml of ammonium chromate or until strontium and calcium are absent. Wash the precipitate with 50 ml of hot water to remove excess chromate.

Add 5 ml of 4N nitric acid to the filter and swirl the solution on the filter gently to dissolve the precipitate. A clean test tube should be placed below the filter to catch the dissolved precipitate. When all of the precipitate is dissolved, turn on the vacuum and catch the solution in the test tube. Repeat this procedure using an additional 5 ml of 4N nitric acid.

Transfer the solution from the test tube to a 50-ml volumetric flask. Carefully wash the test tube with two 5-ml portions of water. Add 25 ml of n-propanol, dilute to 50 ml volume with water, and mix the solution thoroughly. Burn the sample in the flame spectrophotometer and record the emission intensity at 873 mp and the background at 900 mp.

Prepare calibration curves by adding up to 25 mg of barium to 10 ml portions of the synthetic brine followed by analysis according to the foregoing procedure, and use in the calculation.

Calculation: mg Ba x 1,000

ml sample = mg/l Ba+’

ATOMIC ABSORPTION METHODS 65

ATOMIC ABSORPTION METHODS

Atomic absorption is complementary to flame spectroscopy. The spectra emitted are analyzed by absorption of resonance lines by free atoms of a constituent in the vapor phase. The unexcited or ground-state atoms produced in the flame can absorb radiant energy when supplied by a suitable external radiation source at a frequency coinciding with that of the emission frequencies of the element atomized. The measurement of this radiation absorbed forms the basis of absorption flame spectrophotometry - or atomic absorption spectrophotometry, as it is usually called.

At temperatures up to 2,7OO0C, ground-state atoms usually account for more than 90% of the atoms in the vapor phase. Hollow cathode discharge tubes generally are used as a light source. The sensitivity of detection does not depend upon the spectral response of the light receiver, since the absorption coefficient is a measure of the relative intensity of the light which passes through an absorption cell versus that which does not. Additional theory can be found in a book by Robinson (1966).

Atomic absorption is useful in water and brine analysis, and there are several publications on the subject. Publications oriented to oilfield and sea water analysis are Fabricand et al. (1966), and Angino and Billings (1967).

Table 3.XII illustrates the sensitivities that can be obtained using atomic absorption to determine some metals in aqueous solutions. The sensitivities listed are obtainable if no interferences are present. Interference usually

TABLE 3.XII

Approximate sensitivities for some metals to atomic absorption

Metal Wavelength Sensitivity Fuel and oxidant (A) (mg/l)

- - . -

Aluminum Barium Beryllium Cadmium Calcium Chromium Copper Iron Lead Magnesium Manganese Mercury Nickel Silver Sodium Zinc

3093 5536 2348 2288 4226 3579 3247 2483 2833 2852 2794 2536 2320 3281 5890 21 38

1 .o 0.2 0.1 0.04 0.08 0.15 0.2 0.3 0.5 0.02 0.15 0.01 0.15 0.1 0.03 0.04

nitrous oxide-acetylene nitrous oxide-acetylene nitrous oxide-acetylene air-acetylene air-acetylene air-acet ylene air-acet ylene air-acet ylene air-acet ylene air-acet ylene air-acet ylene air-acetylene air-acet ylene air-acet ylene air-acety lene air-acet ylene


results from lack of absorption of atoms bound in molecular combination in the flame and can occur when the flame is not hot enough to dissociate the molecule. It also occurs when a dissociated atom immediately oxidizes to a compound that cannot dissociate further at the temperature of the flame.

Interferences

Ionization

When a significant number of the atoms of the element being determined are ionized in the flame, an error in the analysis can result. This ionization is because of excessive flame temperature, which, however, can be changed to control this interference. Another type of interference can be caused by the presence in the sample of other, more easily ionizable elements than the one sought. The resulting increase can be controlled by the addition of a sufficient amount of the interfering element t o both sample and standards to produce a “plateau” in the absorbance above which no further increase occurs.

Che m ica 1

A chemical interference is caused by the formation, in the flame, of salts of the element sought which are difficult to decompose, thus reducing the amount of the element available for absorption. The formation of such compounds may often be precluded by the addition of another element, such as lanthanum, which forms a less-soluble salt with the interfering anion than does the element desired. The interfering anion is thus removed from the flame, and the interference is eliminated.

Phosphate combines with calcium and magnesium and produces an interference; however, the addition of lanthanum largely overcomes this interference. Addition of an excess of a cation having a similar or lower ionization potential usually reduces interference problems.

Matrix

Matrix interference is caused by unequal amounts of dissolved solids in the standards and samples. This can cause error because of differences in aspiration rates through the atomizer. Often this can be controlled by matching the specific gravities of the standards and samples or by adding salts to the standards.

Burners and solvents

Various types of burners are used with atomic absorption spectrophotometers. For example, a Boling burner usually is used for aqueous solutions,


while a premix burner is used for organic solutions. A nitrous oxide burner head with. a 2-inch slot is used for determining aluminium, barium, and beryllium because overheating is often encountered wit,h a 3-inch slot burner.

The use of concentration steps, such as solvent extraction of a chelated compound, enables sensitivities lower than those shown in Table 3.XII to be achieved. For example, aluminium and beryllium can be complexed with 8-quinolinol and extracted with chloroform; cadmium and lead can be complexed with ammonium pyrrolidine dithiocarbamate and extracted with methyl isobutyl ketone. When burning the organic solvents, it usually is necessary to reduce the fuel air ratio because the burning organic solvent contributes to the fuel supply producing an undesirable luminescent flame and may also lift the flame off the burner. An optimum fuel/air ratio can be found by noting the characteristics of the flame before burning the organic solvent and then reducing the fuel flow, while burning the organic solvent until the flame characteristics are similar to those noted before the organic solvent was burned. Ramirez-Munoz (1968) provides additional information.

Burner height is very important and adjustment often is necessary when changing from one element to another. Some instruments have a Vernier adjustment for reproducing burner-height settings and some do not. Fig. 3.5 illustrates a device which can be used for reproducing exact burner height (Ballinger et al., 1972).

0-m from hollow cathode lamp

Fig. 3.5. Device for reproducing burner height for emission and atomic absorption spec- trometers.


Lithium

Lithium is determined at the 6707.8 A wavelength with an air-acetylene flame.

Interferences. Ionization interference is suppressed by adding 1,000 pg/ml of potassium.

Reagents. The necessary reagents are: (1) Potassium solution: see reagents preparation under “Sodium”. (2) Standard lithium solution: obtain commercially or dissolve 5.324 g of

lithium carbonate, Liz CO, , in a minimum volume of one part Hz 0 to one part of HC1 (1 + 1). Dilute to 1 liter with water. 1 ml of this solution contains 1,000 pg of lithium.

Preliminary calibration. Prepare standard lithium solutions containing 1-5 pg/l of lithium using the standard lithium solution and 50-ml volumetric flasks. Add to each of these and to a blank, 0.5 ml of the potassium stock solution. Aspirate these standards and the blank as recommended in the calcium method and determine the absorbance at a wavelength of 6707.8 A.

Procedure. Transfer an aliquot of brine to a 50-ml volumetric flask. The specific gravity of the brine can be used as a guide in estimating the size of an aliquot containing about 0.05 mg of lithium. Add 0.5 ml of the potassium stock solution, dilute to volume with water, and aspirate. Calculate the approximate sample concentration from the preliminary calibration readings and determine the aliquot size that will contain about 0.05 mg of lithium.

Transfer equal aliquots containing about 0.05 mg of lithium to three 50-ml volumetric flasks. Add no lithium standard to the first flask, 0.05 mg of the lithium standard to the second flask, and 0.10 mg to the third. Add 0.5 ml of the potassium stock solution to each of the three flasks and dilute to volume. Aspirate and record the absorbance readings for each sample.

Calculations. See calculations under “Lithium” in the flame spectrophotometric section, Fig.3.3, or Table 3.XI:

mgLix 1,000 ml sample = mg/l Li+

Precision. In a single laboratory using oilfield water samples containing concentrations of 90 and 190 mg Li+/l, the standard deviations were k 3 and +5, respectively. The recoveries were 100.6% and 92.996, respectively.

Sodium

Two wavelengths are used: the 5890-5896 A doublet for the 1-mg/l


aliquots and the 3302-3303 a doublet for the 100-mg/l aliquots. Because of the wide .range of sodium concentrations found in brines, the higher wavelength can be used for the lower gravity brines and the lower wavelength for the higher gravity brines, thus avoiding making two dilutions with some of the heavier brines. I t is usually necessary to make a preliminary determination so that the correct aliquot can be used with the standard additions.

Interferences. Ionization interference is usually overcome by adding potassium.

Reagents. The necessary reagents are: (1) Potassium solution: dissolve 190.70 g of potassium chloride, KC1, in

water and dilute to 1 liter. 1 ml of this solution contains 100 mg of potassium.

(2) Standard sodium solution: obtain commercially or dissolve 25.420 g of sodium chloride in 1 liter of water. 1 ml of this solution contains 10 mg of sodium. Dilute 10 ml of this solution to a liter. 1 ml of this solution contains 100 pg of sodium.

Preliminary calibration. Prepare standard solutions containing 1 .O-5.0 and 100-500 pg/ml of sodium using the standard sodium solutions and 50-ml volumetric flasks. Add to each of these, and to a blank, 0.5 ml of the potassium stock solution. Aspirate these standards and blank as recommended in the calcium method and determine the absorbance at 5890-5896 a for the 1.0-5.0 pg/ml Na solutions and at 3302-3303 a for the 100-500 pg/ml Na solutions.

Procedure. Transfer an aliquot of brine to a 50-ml volumetric flask. The specific gravity of the brine can be used as a guide in estimating the size of an aliquot containing either about 0.05 mg or about 5 mg of sodium. Add 0.5 ml of the potassium stock solution, dilute to volume, and aspirate. Calculate the approximate sample concentration from the preliminary calibration readings. Determine the aliquot size that will contain either about 0.05 mg or 5 mg of sodium, depending on the wavelength to be used. Transfer equal aliquots to three 50-ml volumetric flasks. For the 0.05-mg aliquots, add no sodium standard to the first flask, 0.05 mg of sodium standard to the second flask, and 0.10 mg to the third. For the 5-mg aliquots, add no sodium standard to the first flask, 5 mg to the second, and 10 mg to the third. Add 0.5 ml of the potassium stock solution to each flask and dilute to volume. Aspirate and record the absorbance readings for each sample.

Calculations. See calculations under “Lithium” in the flame spectrophotometric section, Fig. 3.3, or Table 3.XI:

mg Na x 1,000 ml sample = mg/l Na+


Precision. In a single laboratory using oilfield water samples containing concentrations of 22,700 and 43,200 mg Na+/l, the standard deviations were +485 and ?1,890, respectively. The recoveries were 100.8% and 100.9%, respectively.

Potassium

Potassium is determined at the 7664.9 A wavelength with an air-acetylene flame.

Interferences. Ionization interference is suppressed by adding 1,000 pg/ml of sodium.

Reagents. The necessary reagents are: (1) Sodium solution: dissolve 254.20 g of sodium chloride in 1 liter of

water. 1 ml of this solution contains 100 mg of sodium. (2) Standard potassium solution: obtain commercially or dissolve 1.907 g

of potassium chloride, KCl, in 1 liter of water. 1 ml of this solution contains 1,000 pg of potassium.

Preliminary calibration. Prepare standard solutions containing 1-5 pg/l of potassium using the standard potassium solution and 50-ml volumetric flasks. Add 0.5 ml of the sodium stock solution to each of these and to a blank. Aspirate these standards and the blank as recommended in the calcium method and determine the absorbance at a wavelength of 7664.9 A.

Procedure. Transfer an aliquot of brine to a 50-ml volumetric flask. The specific gravity of the brine can be used as a guide in estimating the size of an aliquot containing about 0.05 mg of potassium. Add 0.5 ml of the sodium stock solution, dilute to volume with water, and aspirate. Calculate the approximate potassium concentration from the preliminary calibration readings and determine the aliquot size that will contain about 0.05 mg of potassium.

Transfer equal aliquots containing about 0.05 mg of potassium t o three 50-ml volumetric flasks. Add no potassium standard to the first flask, 0.05 mg of the potassium standard to the second flask, and 0.10 mg to the third. Add 0.5 ml of the sodium stock solution to each flask and dilute to volume. Aspirate and record the absorbance readings for each sample.


= mg/l K+ mg K x 1,000 ml sample


Precision. I n a single laboratory using oilfield water samples containing concentrations of 456 and 5,680 mg K+/1, the standard deviations were *25 and +325, respectively. The recoveries were 93.7% and 97.8%, respectively.

Magnesium (1)

Magnesium is determined at the 2852.1 A wavelength with an air- acetylene flame.

Interferences. The silicon and aluminum suppression of the magnesium absorption is generally removed by the addition of lanthanum or by the use of a nitrous oxide-acetylene flame.

Reagents. The reagents are: (1) Lanthanum solution (same as used in the calcium procedure). (2) Standard magnesium solution: obtain commercially or dissolve 1 .OOO g

of magnesium ribbon in a minimum of (1 + 1) HC1, and dilute to 1 liter with 1% (v/v) HC1. 1 ml of this solution contains 1,000 pg of magnesium per ml and should be made up daily to use for the standard additions.

Preliminary calibration. Prepare standard solutions containing 0.1-0.5 pg/l of magnesium using the standard magnesium solution and 50-ml volumetric flasks. Add to each of these and to a blank 5 ml of the stock lanthanum solution. Aspirate as suggested in the calcium method and determine the absorbance at 2852.1 A.

Procedure. Transfer an aliquot of brine to a 50-ml volumetric flask. The specific gravity of the brine often can be used as a guide in estimating the size of an aliquot containing about 0.005 mg of magnesium. Add 5 ml of the lanthanum stock solution, dilute to volume with water, and aspirate. Calcu- late the approximate sample concentration from the preliminary calibration readings, and determine the aliquot size that will contain about 0.005 mg magnesium.

Fig. 3.6 illustrates a plot of the concentration of magnesium found in some oilfield brines compared to their specific gravity. This figure cannot necessarily be applied to all oilfield brines, however, because some will contain more and some less. The concentrations of magnesium in brines from the same formation at about the same depth often are similar.

Transfer equal aliquots containing about 0.005 mg magnesium to three 50-ml volumetric flasks. Add no magnesium standard to the first flask, 0.005 mg to the second flask, and 0.010 mg to the third. Add 5 ml of the lanthanum stock solution to each of the three flasks and dilute to volume. Aspirate and record the absorbance readings for each sample.


4.000 -L

1.00 1.05 1.10 1.15 1.20 I .

SPECIFIC G R A V I T Y

5

Fig. 3.6. Relationship of the concentration of magnesium to specific gravity for some oilfield brines.


mgMgx 1,000 rnl sample = mg/l Mg+2

Precision. In a single laboratory using oilfield water samples containing concentrations of 1,470 and 2,000 mg Mg+2/1, the standard deviations were k36 and +128, respectively. The recoveries were 97.3% and 103.2% respectively.

Calcium (1)

Calcium is determined at the 4226.7 A wavelength with an air-acetylene flame.


Interferences. The chemical suppressions caused by silicon, aluminium, and phosphate are controlled by adding lanthanum. The lanthanum also controls a slight ionization interference. A pH above 7 causes low calcium values, so dilute HC1 is added to standards and samples. For samples containing large amounts of silica, it often is preferable to use the nitrous oxide-acetylene flame. The analysis appears to be free from chemical suppressions, but a large amount of alkali salt should be added' to control ionization interferences.

Reagents. The reagents are: (1) Lanthanum solution: wet 58.65 g of La203 with water, add 250 ml

concentrated HC1 very slowly until the material is dissolved and dilute to 1 liter. This provides a 5% lanthanum solution in 25% (v/v) HC1.

(2) Standard calcium solution: obtain commercially or prepare by adding 50 ml of water to 0.2497 g of primary standard calcium carbonate, CaC03. Add dropwise a minimum volume of HC1 to dissolve all of the CaCO, and dilute to 1 liter. 1 ml of solution contains 100 pg of calcium.

Preliminary calibration. Use the standard calcium solution (1 ml-100 pg Ca) and transfer the following amounts to six 50-ml volumetric flasks. To the first flask add 0.5 ml, to the second 1.0 ml, to the third 1.5 ml, to the fourth 2.0 ml, and to the fifth 2.5 ml; and the sixth flask should have 0.0 ml. To each flask add 5 ml of the lanthanum solution and sufficient distilled water to adjust the volume to 50.0 ml. The first flask now contains 1.0 pg/ml Ca, the fifth contains 5.0 pg/ml Ca, and the sixth is a blank. Aspirate these five standards and the blank into an air-acetylene flame and determine the absorbance at 4226.7 A. If the atomic absorption instrument has curvature correction controls, make the necessary adjustments to obtain a linear relationship between absorbance and the actual concentration of the standards. If the instrument does not have these controls, plot the results on linear graph paper as illustrated in Fig. 3.2 by substituting absorbance for intensity.

Procedure. Transfer an aliquot of brine to a 50-ml volumetric flask. The specific gravity of the brine can be used as a guide in estimating the size of an aliquot containing about 0.05 mg of calcium. Add 5 ml of the lanthanum stock solution, dilute to volume with water, aspirate the sample into an air- acetylene flame, and determine the absorbance of 4226.7 A. Calculate the approximate sample concentration from the preliminary calibration readings, and determine the aliquot size that will contain 0.05 mg of calcium.

Transfer equal aliquots containing 0.05 mg Ca+2 to three 50-ml volumetric flasks. Add no calcium standard to the first flask, 0.5 mg to the second flask, and 0.10 mg to the third.

ANALYSIS OF OILFIELD WATERS 74

Add 5 ml of the lanthanum stock solution to each of the three flasks and dilute to volume. Aspirate and record the absorbance readings for each sample.

Calculations. See calculations under “Lithium” in the flame spectrophotometric section, Fig.3.3, or Table 3.XI:

mg Ca x 1,000 ml sample = mg/l Ca+’

Precision. In a single laboratory using oilfield water samples containing concentrations of 17,400 and 32,500 mg Cat’ /1, the standard deviations were k430 and +1,090, respectively. The recoveries were 103.5% and 100.3’36, respectively.

Magnesium (2)

The following method for the determination of magnesium in an oilfield water was supplied through courtesy of the Halliburton Company (1970), and can be used to determine all concentrations of the magnesium ion in a brine.

Reagents. The necessary reagents are magnesium standard solution, 1 mg/ml; lanthanum solution, 1 g/ml; and hydrochloric acid.

Magnesium standard working so 1 u t ions

Pipet 1.0 ml of the magnesium standard stock solution into a 1 liter flask, add 11.0 ml to a second 1-liter flask, and add 21.0 ml to a third 1-liter flask. To each flask add 50 ml of concentrated hydrochloric acid, 10 ml of the lanthanum stock solution, and dilute each to an overall 1,000 ml volume with water. This yields standards of 1.0, 11.0, and 21.0 mg/l of magnesium in the first, second, and third flasks, respectively.

Procedure. Filter the sample with the micropore filter apparatus to remove solids and traces of hydrocarbons from the water. Transfer, by means of “Lambda” pipet or volumetric transfer pipet, an aliquot of sample to contain not more than 1.0 mg magnesium into a 100-ml volumetric flask. Add 5.0 ml hydrochloric acid, 1.0 ml lanthanum stock solution, and sufficient water to dilute to exactly the 100-ml mark. Mix thoroughly. Aspirate the 5-mg/l standard through the burner, positioning the burner angle as necessary until the recorder indicates a stable reading of about 25% absorption using a wavelength setting of 2852 a. Record the reading and aspirate distilled water through the burner until the recorder returns t o the original baseline. Next, aspirate the sample through the burner until a maximum stable reading is obtained on the recorder. Record the reading and if the sample


reading on the recorder is greater than the 5-mg/l standard, aspirate the 9-mg/l standard through the burner until a maximum stable reading is obtained. Record the reading and if the sample reading on the recorder is less than the 5-mg/l standard, aspirate the 1-mg/l standard through the burner until a maximum, stable reading is obtained, and record the reading.

Calculations:

where %A = percent absorption of high standard; %I2 = percent absorption of low standard; %A, = percent absorption of sample; mg/ll = mg Mgt2 /1 of high standard; mg/12 = mg Mg+2 /1 of low standard; mg/l, = mg Mg+2 /1 of sample; and DF= dilution factor of sample (100/ml sample).

Derivation of above equation: %A s-%A 2 - - %A 1 -%A 2

mg/l1 -mg/l2 mg/l,-mg/l2

or :

when mg/l, = 11, mg/12 = 1 ; A mg/l(l-2) = 10 when mg/ll = 21, mg/12 = 11; A mg/l( - 2 = 10 mg/ll -mg/12 = 10, when standards of 21 mg/l and 11 mg/l or 11 mg/l and 1 mg/l are used.

Calcium (2)

The same apparatus used in determining magnesium by atomic absorption can be used to determine calcium.

Reagents. The necessary reagents are calcium standard solution, 1 mg/ml; lanthanum solution, 1 g/ml; and hydrochloric acid.

Calcium standard working solutions

Pipet 1.0 ml of the calcium standard stock solution into a 1-liter flask, add 11.0 ml to a second 1-liter flask, and 21.0 ml to a third 1-liter flask. To each flask add 50 ml of concentrated hydrochloric acid, and 10 ml of the lanthanum stock solution, and dilute each to an overall 1,000 ml volume


with water. This yields standards of 1.0, 11.0, and 21.0 mg/l of calcium in the first, second, and third flasks, respectively.

Procedure. Filter the sample through the micropore filter apparatus to remove solids and traces of hydrocarbons from the water. Transfer, by means of micropipet or volumetric transfer pipet, an aliquot of sample containing not more than 2.0 mg calcium into a 100-ml volumetric flask. Add 5.0 ml hydrochloric acid, 1.0 ml lanthanum stock solution, and sufficient water to dilute to exactly the 100-ml mark and mix thoroughly. Aspirate the ll mg/l standard through the burner, positioning the burner angle as necessary until the recorder reaches a maximum stable reading of about 22% absorption using a wavelength setting of 4227 A. Record the reading and aspirate distilled water through the burner until the recorder returns to the original baseline. Re- move and aspirate the sample through the burner until a maximum stable reading is obtained on the recorder. Record the reading and aspirate distilled water through the burner until the recorder returns to the original baseline. If the sample reading on the recorder is greater than the 11 mg/l standard, aspirate the 21 mg/l standard through the burner until a maximum stable reading is obtained. Record the reading and if the sample reading on the recorder is less than the 11 mg/l standard, aspirate the 1 mg/l standard through the burner until a maximum, stable reading is obtained. Record the reading.

Calculations:

(%A ,--%A 2 ) %A 1 -76 2

10 + mg/12 x DF = mg/l Ca+2

where %A = percent absorption of high standard; %A2 = percent absorption of low standard; %A, = percent absorption of sample; mg/ll = mg Ca+2/l of high standard; mg/12 = mg Ca+2/l of low standard; mg/l, = mg Ca+?/l of sample; and DF = dilution factor of sample (100/ml sample).

Strontium

Strontium is determined at the 4607 A wavelength with an air-acetylene flame.

Interferences. The chemical suppression caused by silicon, aluminum, and phosphate is controlled by adding lanthanum. The lanthanum also controls ionization interference. The nitrous oxide-acetylene flame can be used to control chemical interferences, but a large excess of alkali salt should be added to control ionization.


Reagents. The necessary reagents are: (1) Lanthanum solution (same as used in the calcium standard-addition

procedure). (2) Standard strontium solution: obtain commercially or dissolve 2.415 g

of strontium nitrate, Sr(N03)2, in 1 liter of 1% (v/v) HNO,. 1 ml of the solution contains 1,000 pg of strontium.

Preliminary calibration. Prepare standard strontium solutions containing 1-10 pg/ml of strontium using the standard strontium stock solution and 50 ml of volumetric flasks. Add to each of these and to a blank, 5 ml of the lanthanum stock solution. Aspirate these standards and the blank as suggested in the calcium method and determine the absorbance of strontium at 4607 A.

Procedure. Transfer an aliquot of brine to a 50-ml volumetric flask. The specific gravity of the brine can be used as a guide in estimating the size of an aliquot containing about 0.1 mg of strontium (see Fig. 3.6). Add 5 ml of the lanthanum stock solution, dilute to volume, and aspirate. Calculate the approximate sample concentration from the preliminary calibration readings, and determine the aliquot size that will contain about 0.1 mg strontium.

Transfer equal aliquots containing about 0.1 mg of strontium to three volumetric flasks. Add no strontium standard to the first flask, 0.1 mg to the second, and 0.2 to the third. Add 5 ml of the lanthanum stock solution to each of the three flasks and dilute to volume. Aspirate and record the absorbance readings for each sample.


mg Sr x 1,000 ml sample = mg/l Sr+2

Precision. In a single laboratory using oilfield water samples containing concentrations of 840 and 2,250 mg Sr+2/1, the standard deviations were +48 and +110, respectively. The recoveries were 106.8% and 103.1%, respectively.

Barium

Barium is determined at the 5336 A wavelength with an acetylene nitrous-oxide flame.

Interferences. Ionization interference is suppressed by adding 1,000 pg/ml of sodium.


Reagents. The necessary reagents are: (1) Sodium solution: see reagents preparation under “Potassium”. (2) Standard barium solution: obtain commercially or dissolve 1.5161 g of

BaClz in 1 liter of water. 1 ml of this solution contains 1,000 pg of barium.

Preliminary calibmtion. Prepare standard barium solutions containing 2-1 0 pg/ml of barium using the standard barium solution and 50-ml volumetric flasks. Add to each of these and to a blank, 0.5 ml of the sodium stock solution. Aspirate these standards and the blank as recommended in the calcium method and determine the absorbance at a wavelength of 5336 8.

Procedure. Transfer an aliquot of brine to a 50-ml volumetric flask. The specific gravity of the brine can be used as a guide in estimating the size of an aliquot containing about 0.1 mg of barium. Add 0.5 ml of the sodium stock solution, dilute to volume with water, and aspirate. Calculate the approximate sample concentration from the preliminary calibration readings and determine the aliquot size that will contain about 0.1 mg of barium.

Transfer equal aliquots containing about 0.1 mg of barium to three 50-ml volumetric flasks. Add no barium standard to the first flask, 0.1 mg of the barium standard to the second flask, and 0.2 mg to the third. Add 0.5 ml of the sodium stock solution to each of the three flasks and dilute to volume. Aspirate and record the absorbance readings for each sample.

Calculations. See calculations under “Lithium” in the flame spectrophotometric section, Fig. 3.3 or Table 3.XI:

mg Ba x 1,000 ml sample = mg/l Ba+’

Precision. In a single laboratory using oilfield water samples containing concentrations of 7 and 8 mg Ba+’/l, the standard deviations were k0.5 and kO.9, respectively. The recoveries were 108.2% and 97.3% respectively.

Manganese

Manganese is determined at the 2794.8 8 wavelength with an air-acetylene flame.

Reagents. The necessary reagent is a standard manganese solution: obtain commercially or dissolve 1.000 g of manganese in a minimum volume of (1 +1) nitric acid. Dilute to 1 liter with 1% (v/v) HC1.l ml of solution contains 1 mg of manganese.

Preliminary calibration. Prepare standard manganese solutions containing 1-5 pg/ml using the standard manganese solution and 50-ml volumetric flasks. Aspirate these standards arid a blank as recommended in the calcium method, and determine the absorbance at a wavelength of 2794.8 8.


Procedure. Transfer an aliquot containing about 0.05 mg of manganese to a 50-ml volumetric flask. Dilute to volume and aspirate. Calculate the approximate sample concentration from the preliminary calibration readings and determine the aliquot size that will contain 0.05 mg of manganese. ’ Transfer equal aliquots containing about 0.05 mg of manganese to three 50-ml volumetric flasks. Add no manganese standard to the first flask, 0.05 mg of the manganese standard to the second flask, and 0.10 mg t o the third. Dilute to volume. Aspirate and record the absorbance readings for each sample.


mg Mn x 1,000 ml sample = mg/l Mn+’

Precision. In a single laboratory using oilfield water samples containing concentrations of 20 and 97 mg Mn+2/1, the standard deviations were k1 and +3, respectively. The recoveries were 102.2% and 105.4% respectively.

Iron

Iron is determined at the 2483.2 A wavelength with an air-acetylene flame.

Interferences. The sensitivity is reduced if nitric acid and nickel are present. This effect can be controlled by using a very lean (hot) flame.

Reagents. The necessary reagent is a standard solution: obtain commercially or dissolve 1.000 g of iron wire in 50 ml of (1 + 1) nitric acid and dilute to 1 liter with water. 1 ml of solution contains 1 mg of iron.

Preliminary calibration. Prepare standard iron solutions containing 1-5 Mg/ml using standard iron solution and 50-ml volumetric flasks. Aspirate these standards and a blank as recommended in the calcium method and determine the absorbance at a wavelength of 2483.2 A.

Procedure. Transfer an aliquot containing about 0.05 mg of iron to a 50-ml volumetric flask. Dilute to volume and aspirate. Calculate the approximate sample concentration from the preliminary calibration readings and determine the aliquot size that will contain about 0.05 mg of iron.

Add no iron standard to the first flask, 0.05 mg of the iron standard to the second flask, and 0.10 mg to the third. Dilute to volume. Aspirate and record the absorbance readings for each sample.

ANALYSIS OF OILFIELD WATERS 80


mg Fe x 1,000 ml sample = mg/l Fe+’

Precision. In a single laboratory using oilfield water samples containing concentrations of 6.3 and 6.8 mg Fe+2 /1, the standard deviations were k0.5 and k0.3, respectively. The recoveries were 115.6% and 97%, respectively.

copper

Copper is determined at the 3247.5 8 wavelength with an air-acetylene flame.

Reagents. The necessary reagent is a standard copper solution: obtain commercially or dissolve 1.000 g of copper metal in a minimum volume of (1 + 1) nitric acid. Dilute 1 liter with 1% (v/v)’ nitric acid. 1 ml of solution contains 1 mg of copper.

Preliminary calibration. Prepare standard copper solutions containing 1-5 pg/ml using the standard copper solution and 50-ml volumetric flasks. Aspirate these standards and a blank as recommended in the calcium method and determine the absorbance at a wavelength of 3247.5 8.

Procedure. Transfer an aliquot containing about 0.05 mg of copper to a 50-ml volumetric flask. Dilute to volume and aspirate. Calculate the approximate sample concentration from the preliminary calibration readings and determine the aliquot size that will contain 0.05 mg of copper.

Transfer equal aliquots containing about 0.05 mg of copper to three 50-ml volumetric flasks. Add no copper to the first flask, 0.05 mg of the copper standard to the second flask, and 0.10 mg to the third. Dilute to volume. Aspirate and record the absorbance readings for each sample.


mgCux 1,000 ml sample = mg/l CU+’

Precision. In a single laboratory using an oilfield water sample containing a concentration of 3 mg Cu+’ /1, the standard deviation was k0.2. The recovery was 100.5%.

zinc

Zinc 1- determined at the 2138.6 A wavelength with an air-acetylene flame.


Reagents. The necessary reagent is a standard zinc solution: obtain commercially or dissolve 0.500 g of zinc metal in a minimum volume of (1 +1) HC1 and dilute to 1 liter with 1% (v/v) HCl. 1 ml of solution contains 500 pg of zinc.

Preliminary calibration. Prepare standard zinc solutions containing 0.2-1.0 pg/ml using the standard zinc solution and 50-ml volumetric flasks. Aspirate these standards and a blank as recommended in the calcium method and determine the absorbance at a wavelength of 2138.6 a. Procedure. Transfer an aliquot containing about 10 pg of zinc to a 50-ml volumetric flask. Dilute to volume and aspirate. Calculate the approximate sample concentration from the preliminary calibration readings and determine the aliquot size that will contain 10 pg of zinc.

Transfer equal aliquots containing about 10 pg of zinc to three 50-ml volumetric flasks. Add no zinc standard to the first flask, 10 pg of the zinc standard t o the second flask, and 20 pg to the third. Dilute to volume. Aspirate and record the absorbance readings for each sample.


Precision. In a single laboratory using oilfield water samples containing concentrations of 27 and 120 mg Zn+2 /1, the standard deviations were +1. The recoveries were 103.5% and 102.3%, respectively.

Lead (1)

Lead is determined at the 2833.1 A wavelength with an air-acetylene flame.

Reagents. The necessary reagent is a standard lead solution: obtain commercially or dissolve 1.598 g of lead nitrate, Pb(N03)2, in 1 liter of 1% (v/v) HN03. 1 ml of solution contains 1,000 pg of lead.

Preliminary calibration. Prepare standard lead solutions containing 2-10 pg/ml using the standard lead solution and 50-ml volumetric flasks. Aspirate these standards and a blank as recommended in the calcium method and determine the absorbance at a wavelength of 2833.1 8.

Procedure. Transfer an aliquot containing 100 pg of lead to a 50-ml volumetric flask. Dilute to volume and aspirate. Calculate the approximate sample concentration from the preliminary calibration readings and determine the aliquot size that will contain 100 pg of lead.


Transfer equal aliquots containing about 100 pg of lead to the three 50-ml volumetric flasks. Add no lead standard to the first flask, 100 pg of lead standard to the second flask, and 200 pg to the third. Dilute to volume. Aspirate and record the absorbance readings for each sample.

Calculations. See calculations under “Lithium” in the flame spectrophotometric section, and Fig. 3.3, or Table 3.XI:

mg Pb x 1,000 ml sample = mg/l Pb+’

Precision. In a single laboratory using an oilfield water sample containing a concentration of 16 mg Pb+*/l, the standard deviation was k2.6. The recovery was 74.8%.

Lead (2)

Lead is determined by chelating with ammonium pyrollidine dithiocarbamate (APDC) and extracting with methyl isobutyl ketone (MIBK) (Brooks et al., 1967). The organic extract is analyzed by means of atomic-absorption spectrophotometry. Interferences have not been observed in the air- acetylene flame.

Reagents. The necessary reagents are methyl isobutyl ketone (MIBK); 0.3M hydrochloric acid; ammonium pyrollidine dithiocarbamate (APDC) (dissolve 1.0 g of APDC in 100 ml of distilled water); bromphenol blue indicator solution (dissolve 0.1 g bromphenol blue in 100 ml of 50% ethanol); 2.5M sodium hydroxide; and lead standard solution. The latter can be bought commercially or made from lead nitrate. The presence of 0.5% nitric acid in the lead standards of low concentrations retards the plating of the lead on the sides of the container.

Procedure. Pipet the sample into a 200-ml volumetric flask and adjust the volume to approximately 100 ml with distilled water. Add two drops of the bromphenol blue indicator solution. Adjust the pH by adding 2.5M NaOH by drops until a blue color persists. Add 0.3M HC1 until the blue color disappears. Add 2.0 ml of HC1 in excess. The pH should be 2.4. Add 2.5 ml of the APDC solution and mix. Add 10 ml of MIBK and shake vigorously for 1 minute. Allow the layer to separate and add distilled water until the ketone layer is in the neck of the flask. Aspirate the ketone layer for lead content. Prepare a calibration curve by adding known amounts of lead to a synthetic brine solution.

Calculations:

mg Pb (from curve) - - mg/l Pb’ * ml sample

EMISSION SPECTROMETRY a3

EMISSION SPECTROSCOPY

The basic requirements for all spectroscopic measurements are a source, a dispersion element, and a detector. The source may be an emitter whose emission is to be measured, or it may be a continuum that emits all wavelengths, within a certain range, so that absorption by material in the light path may be measured.

In general, emission spectra are concerned with transitions from upper state to lower state electronic levels in atoms and in simple molecular species. Some flames are hot enough to excite upper electronic levels in neutral atoms (un-ionized) and in molecules. Electric discharges produce more vigorous excitation, and a high-voltage spark tends to increase the ionization of the emitters.

In spectrographic analysis the light source first vaporizes and dissociates the sample and second excites the atoms causing them to radiate characteristic spectra. The intensities of the spectral lines of elements excited in a light source are proportional to the concentration of the elements in the sample, thus providing a basis for quantitative analysis. Excitation is mainly thermal in the sources, flames, arcs, and sparks.

Temperature is very important in spectrographic analysis because some elements are not easily excited in a thermal source while others are. The ionization potential of the element determines the ease of exciting its spectra. The alkali elements with ionization potentials of 4-5 V are excited in low energy sources while the rare gases with ionization potentials up to 25 V require high temperatures to be excited. A Bunsen flame gives a temperature of about 1,700'C; an oxyacetylene flame, about 2,700'C; an electric arc, 3,700'C-6,700'C; and an electric spark, about 9,700"C. In the following procedures a plasma arc source was used, capable of temperatures up to 7,700' C .

The plasma arc was adapted to analytical spectrography by Scribner and Margoshes (1961). The temperature of a direct current arc is increased by thermal-pinch effect.

The internal standard method is used in the following procedures, and with this method the intensity of a line of the element present in unknown concentration is measured relative to that of an invariant line of a reference element. With this method the intensity ratio must be highly reproducible.

Barium, boron, iron, manganese, and strontium

The emission characteristics of barium, boron, iron, manganese, strontium, and lanthanum in 10 solvent systems have been studied (Collins, 1967). The greatest emission enhancement was found in a mixture consisting of 30 ml of water plus 20 ml of 35% n-amyl-alcohol and 65% acetone, as illustrated by Fig. 3.7. Because n-propanol is easier to work with, it was used in the following procedure; however, if additional sensitivity is needed, the n-amyl-alcohol-acetone mixture can be used.

84

35 percent N-Amy1 90 65 percent acetone "'i w

2 50 I-

Proplonlc Add,

N-Proponoi Acetone

a 4 ~ t h y l ~ l f ~ ~ i d ~ 30

2 I I I I I I I I I I

0 I 2 3 4 5 6 7 8 9 101 CARBON, grams per SOml

ANALYSIS OF OILFIELD WATERS

I

Fig. 3.7. Relative intensity of lanthanum versus grams of carbon in the solvent aspirated into a plasma arc.

Reagents. The necessary reagents are: Helium. Eastman Kodak D-19 developer. Eastman Kodak rapid fixer and hardener. Stop-bath solution, e.g. 5% acetic acid. Standard spectroscopic stock solutions containing 1 mglml of the follow-

ing metals (use spectroscopic grade reagents): (1) barium: dissolve 1.4368 g of barium carbonate in a minimum amount of hydrochloric acid and dilute to 1 liter with distilled water; (2) strontium: dissolve 1.6848 g of strontium carbonate in a minimum amount of hydrochloric acid and dilute to 1 liter with distilled water; (3) boron: dissolve 5.7153 g of boric acid in distilled water and dilute to 1 liter with distilled water; (4) manganese: dissolve 1.5823 g of manganese dioxide in hydrochloric acid and dilute to 1 liter with 6N hydrochloric acid; (5) iron: dissolve 1.00 g of iron wire in aqua regia and dilute to 1 liter with 6N hydrochloric acid.

Internal standard solution: dissolve 2.3455 g of lanthanum oxide in a minium amount of hydrochloric acid and dilute to 1 liter with distilled water. 1 ml contains 2 mg of lanthanum.

Standard solution: prepare a composite standard containing 0.025 mg/ml of manganese, 0.075 mg/ml of iron, and 0.03 mg/ml of strontium by transferring appropriate quantities of the standard spectroscopy stock solutions to a 1-liter volumetric flask. Dilute the resultant mixture to volume with 6N hydrochloric acid.

Synthetic brine solution: prepare a solution containing the following ions, in mg/l: sodium, 32,000; calcium, 4,000; and magnesium, 2,500. Dissolve 73.766 g of sodium carbonate in hydrochloric acid, 9.989 g of calcium carbonate in hydrochloric acid and 2,500 g of magnesium metal in

EMISSION SPECTROMETRY 85

hydrochloric acid. Evaporate these acid solutions to dryness, dissolve the residues in distilled water, combine, and dilute to 1 liter with distilled water.

Hydrochloric acid, concentrated. n-Propanol.

Equipment. The necessary equipment includes a spectrograph; a d.c. arc source, 18-A minimum; a plasma arc assembly; a plate-developing machine; a microphotometer; 50-ml volumetric flasks; 10-ml microburets; pipets; and spectrographic plates, Eastman Kodak Type 1-N.

Spectrochemical excitation conditions. The conditions which are used to determine barium, boron, iron, manganese, and strontium are as follows:

Source, d.c. arc. Current, 18-25 A (keep constant). Voltage, 220 d.c. Pre-exposure time, 5 seconds. Exposure time, 15 seconds. Spectral region, 3200-5200 8, first order and second order. Dispersion, reciprocal linear 8.21 8 /mm first order, 4.02 8 /mm second

Plasma arc assembly. Helium lift gas, 7 liter per minute. Helium tangential gas, 60 liter per minute. Atomizer, Beckman Model 4030 with medium-bore capillary. Arc length above orifice, 7 mm. Full arc length, anode to cathode, 18 mm. Portion of arc viewed, 2 mm above orifice. Orifice electrodes; lower anode, Ultra Carbon 106 drilled to 3.97 mm in

center hole, tapered to 9.53 mm at bottom; center ring, neutral Ultra Carbon 861 drilled to 5.95 mm center hole, tapered to 9.53 mm at bottom.

Cathode electrode, vertical position, Ultra Carbon 6.35 mm graphite rod with pointed tip.

Slit, 20-p. Filter, 3-step.

order or better.

Spectrographic plate development conditions: 5 minutes in Eastman Kodak D-19 at 2OoC with constant agitation; 30 seconds in stop bath at 3OoC with agitation; 5 minutes in Eastman Kodak rapid fixer and hardener solution at 2OoC with constant agitation; 30 minutes in water rinse with constant fresh supply of water; 30 seconds rinse with distilled water; and 30 minutes in constant air bath to dry.

Microphotometer criteria. Slit, 1 2 p wide and 0.5 mm high. Read the background and intensity of the following lines: Ba, 11, 4554.03


8; B, I, 4995.46 8; Fe, 11, 5198.80 8; Mn, 11, 5152.20 8; Sr, 11,4215.52 8; La, 11, 4086.62 8; and La, 11, 4429.90 8.

The background and intensity of the following lines can be read if some of those above are too intense or if more than one line for a given element is wanted: Ba, 11, 4934.09 8; B, I, 4993.56 8; Fe, 11, 4196.74 8; Mn, 11, 5187.46 8; La, 11, 4077.35 8; La, 11, 4123.23 8; Sr, 11, 4077.71 8; and Sr, I, 4607.33 8.

Calibration. A preliminary curve, gamma curve, and calibration curves are needed unless a direct-reading instrument is used. To make a preliminary curve, record an iron spectrum using d.c. arc current excitation at about 4 A. Read the percent transmittance (% 2') of several iron lines at 100% unfiltered portion. (Any filter can be used as long as the 5% T is known.) Plot the 100% unfiltered lines versus the 63.10% filtered lines. The % T of these lines should vary from about 10% T to 90% T to give a good preliminary curve, shown in Fig. 3.8.

After the preliminary curve is plotted, the gamma or emulsion calibration curve is made, as shown in Fig.3.9. There are several methods of establishing a gamma curve.

The following example is given: 98 on x-axis set to equal 0.2, and 96 on the y-axis intersects curve at the same point on the curve that 98 does on the x-axis. The filter factor is now used. In this case, it is 100%/63.10% = 1.585.

%?' Relative intensity 98 = 0.2 96 = 0.2 x 1.585 0.317

arbitrarily set at 0.2

Owwit). rotio of filter is 1.585

100

0 FILTERED, percent

Fig. 3.8. Preliminary curve for emission spectrometry.


- 20-

- 40- z

v) P -

z -

I I I 1 1 1 ,

RELATIVE INTENSITY 0

Fig. 3.9. Gamma or emulsion calibration curve for emission spectrometry.

A t 96 on the x-axis, find the curve intersection point on the y-axis; in this case, it is 91.

% T Relative intensity

Repeat above procedure to obtain the following data:

91 = 0.317 x 1.585 0.502

81 = 0.502 x 1.585 0.796 63 = 0.796 x 1.585 1.262 38 = 1.262 x 1.585 2.000

19.5 = 2.000 x 1.585 3.17 9.5 = 3.17 x 1.585 5.024 4.6 = 5.024 x 1.585 7.963

2 = 7.963 x 1.585 12.621

Plot the gamma curve using the above values and plot the values on 3-cycle semilogarithmic paper. Place the 7% T values on the linear portion, usually the x-axis, and place the relative-intensity values on the log portion. The resultant curve should be an inverted S if the linear portion or % T is the x-axis. (Theoretically, only one gamma curve need be plotted for all plates with the same emulsion number.)

After the gamma curve is plotted, a calibration curve for each element desired can be plotted, as shown in Fig. 3.10. To do this, spectra are recorded for various concentrations of the element in question. The % T of each of the desired lines is determined, and these % T are referred to the gamma curve to obtain their relative intensities. Ordinarily, internal standards are used to permit a ratio of the relative intensity of the internal standard line to the relative intensity of the element line to be calculated for each concentration of the element. These ratios are plotted versus the element concentration on 2 x 2-cycle logarithmic paper.


I I I I 1 I I 0.2 0.4 0.6 0.8 1.0 2.0 4.0 t I '

INTENSITY RATIO 0

Fig. 3.10. Calibration curve for emission spectrometry.

To obtain data for calibration curves for barium, boron, iron, manganese, and strontium, use size 50-ml volumetric flasks. To one flask add no standard solution; add 1.0 ml to the second flask; and add 2.5 ml, 5.0 ml, 7.5 ml, and 10.0 ml of standard solution to the third, fourth, fifth, and sixth flasks, respectively. (These aliquots will vary with the sensitivity of your instrument.) Add 2 ml of concentrated hydrochloric acid, 2 ml of internal standard solution, 5 d of synthetic brine solution, 20 ml of n-propanol, and sufficient distilled water to adjust the final volume to 50 ml at ambient temperature. For optimum accuracy, prepare duplicate or triplicate samples.

Aspirate and burn the samples using the excitation conditions, the development conditions, and the microphotometer conditions described above; plot the curves using the above procedure.

The water sample should be adjusted to a pH of about 1.5 at the time of sampling to prevent precipitation and adsorption. The sample should be contained in a good quality plastic bottle that has been rinsed first with dilute nitric acid and then with distilled water.

Transfer to a 50-ml volumetric flask an aliquot of the sample of sufficient size to provide absolute quantities of the elements which will fall within the calibration curves. The optimum aliquot size will vary from brine to brine; however, equal-size aliquots often can be used for waters with similar specific gravities from the same geologic formation. Add 2 ml of concentrated hydrochloric acid, 2 ml of internal standard solution, 5 ml of synthetic brine solution (or try to approximate the ionic composition of the


standard), 20 ml of n-propanol, and sufficient distilled water to adjust the volume to 50 ml at ambient temperature. For optimum accuracy, prepare duplicate or triplicate samples.

Aspirate and excite the sample, develop the plate, and read the plate as suggested above. Determine the relative intensity ratios for the following: Ba 4554.03/La 4429.90; B 4995.46/La 4429.90; Mn 5152.20/La 4086.72; Sr 4215.52/La 4086.72; and Fe 5198.80/La 4086.72.

Calculations. Refer the calculated ratio to the appropriate calibration curve to determine milligrams of tested ion in the sample. Convert this value to milligrams per liter by use of the following equation:

mg from curve x 1,000 = mg/l ml sample

The relative intensity ratios for other line pairs can be calculated and used if desired. The precision and accuracy of the method are approximately 2-3% and 4-696, respectively, for strontium and barium; and 5 4 % and 10-1196, respectively, for boron, iron, and manganese.

Beryllium

Beryllium forms a complex with acetylacetone which can be extracted into chloroform from an aqueous solution. The chloroform extracted is aspirated into a plasma arc, and the beryllium I1 line at 3131.07 A is read. An apparent carbon line at 3036.3 A is used for an internal standard.

Reagents. Spectrographic plates, Eastman Kodak Type SA No. 1. Standard beryllium stock solution: dissolve 1.00 g of fused metallic beryl-

lium (spectroscopic grade) in a small amount of 6N hydrochloric acid and dilute to 1 liter with 1% hydrochloric acid. 1 ml contains 1 mg of beryllium.

Standard beryllium solution: prepare a standard by transferring a suitable aliquot of the standard stock solution to a 1-liter volumetric flask and diluting t o volume with 1% hydrochloric acid. The standard prepared will depend upon the resolution and dispersion of the spectrograph. However, for many instruments, a 0.01 pg/ml solution should be adequate.

EDTA solution: dissolve 10 g of disodium ethylenediaminetetraacetic acid and 2 g of sodium hydroxide in water and dilute to 100 ml.

Synthetic brine solution: dissolve 80 g of sodium chloride, 30 g of calcium chloride, 10 g of magnesium chloride, 5 g of strontium chloride, and 3 g of potassium chloride in distilled water that is saturated with carbon dioxide and dilute to 1 liter.

Hydrochloric acid, concentrated. Sodium hydroxide, 0.5N. Chloroform. Acetylacetone.


Procedure. The spectrochemical excitations used are the same as those shown in the procedure to determine barium, etc., with the exception that the spectral region is 2300-3300 8, first order and the slit is 10 p. The plate development conditions are the same as those shown in the procedure to determine barium, etc., and the microphotometer conditions are the same except that the background and the intensity of only the following lines are read: Be, 11, 3131.07 a, internal standard line, 3036.3 8; or if the 3131.07-8 line is too intense, the Be, 11, 3130.42-a line can be used.

To prevent precipitation and adsorption, immediately acidify the clean, oil-free sample to a pH of approximately 1.5 with concentrated hydrochloric acid. Store the sample for transportation to the laboratory, in a good quality plastic bottle which previously was washed with dilute nitric acid, rinsed with distilled water, and dried.

Transfer an aliquot of the sample estimated to contain 0.01-0.05 pg of beryllium to a 100-ml beaker, adjust the pH to 0.5 with concentrated hydrochloric acid, adjust the volume to about 30-50 ml with distilled water, boil gently for 5 minutes, and then cool. Add 2 ml of the EDTA solution and adjust the pH of the mixture to 7.0 with 0.5N sodium hydroxide. Add 2 ml of acetylacetone, readjust the pH to 7.0, mix thoroughly, and allow the solution to stand for 15 minutes. Transfer the sample to a 125-ml Teflon- stoppered, separatory funnel and adjust the volume to 75 ml with distilled water, add 10 ml of chloroform, and shake the mixture vigorously for 2 minutes. After the phases separate, extract the chloroform phase and centrifuge it. Aspirate the centrifuged extract into the plasma arc using the above excitation conditions. For optimum accuracy, prepare duplicate samples.

Develop the plates, make background corrections, and determine the relative intensity ratios for the following lines:

Be 3131.07 3036.3

Be 3130.42 3036.2 and

Determine the concentration of beryllium using a calibration curve prepared by using 0.01-0.05 pg of beryllium standard. This concentration in micrograms can be converted to milligrams per liter by this formula:

pg Be (from curve) ml sample = mg/l Be+2

Less than 1 ppb of beryllium can be detected with this method, the precision and accuracy of the method are about 2% and 496, respectively, of the amount present.

Aluminum,

Petroleum-associated water containing more than 5 mg/l of aluminum can be analyzed using the same procedure and internal standard that are

MASS SPECTROMETRIC METHODS 91

described above for barium, boron, iron, manganese, and strontium; the aluminum emission lines at 3082.5 a can be used. However, if the aluminum concentration is less than 5 mg/l, the aluminum should be separated and concentrated from the aqueous phase. This can be done by adjusting the pH of a sample containing up to 100 pg of aluminum to pH 0.4 with hydrochloric acid, adding 10 ml of a 6% aqueous solution of cupferron, adjusting the pH to 4.8 with sodium acetate, and extracting the aluminum complex into chloroform. The chloroform phase then is aspirated into the plasma arc using the same conditions and internal standard line that is described above for beryllium.

MASS SPECTROMETRIC METHODS FOR STABLE ISOTOPES

The ratios of the stable isotopes of deuterium and hydrogen and of oxygen-18 and oxygen-16 differ in water taken from various sources. These differences are useful in studying the origin of a water, and of studying paleoenvironments if the water is geologically old. The isotopic ratios are measured on a mass spectrometer and are always compared to the ratios found in a standard material because such a comparison proyides greater precision than direct analysis of absolute ratios.

Deuterium

Friedman and Woodcock (1957) developed a method whereby deuterium is converted to hydrogen gas by reacting a 0.01-ml sample with hot uranium metal. A mass spectrometer (Friedman, 1953) is used to compare the deuterium/hydrogen ratio in the emitted gas to the ratio in a standard gas. Replicates agreeing within k0.176 usually are considered satisfactory. The results usually are expressed as deuterium enrichments (+6 values) or depletion (-6 values) relative to SMOW (standard mean ocean water, with a D/H ratio of 158 x (Craig, 1961b). The standard deviation is about 0.2%, and a sample with a 6 value of -5 has 5% less deuterium than SMOW.

Oxygen-18

Epstein and Mayeda (1953) developed a method to analyze water samples for l 8 0 . A 10-ml sample of water is equilibrated with carbon dioxide at 25OC and an aliquot of the COz is analyzed using a mass spectrometer for l 8 0 . The isotope ratios in the sample are compared to those in a standard material, using the mass spectrometer, which gives a greater precision than direct analysis of the absolute ratios. The standard generally used in SMOW (standard mean ocean water) which is distributed by the National Bureau of Standards (Craig, 1961a). Delta units express the isotopic data as:


where R is the isotope ratio such as 180/160 or D/H, and the delta values are expressed in per mil like salinity, and &MOW = O%,.

COLORIMETRIC METHODS

The instrumental measurement of the absorption of radiant energy at a certain wavelength involves spectrophotometry. The essential components of a spectrophotometer include:

(1) Radiant energy source such as a tungsten-filament incandescent lamp for the visible region, while hydrogen or deuterium discharge lamps usually are used for the ultraviolet region.

(2) A monochromator, which is a device that isolates a narrow band of the radiant energy.

(3) Containers, cells, or cuvettes usually made of glass to hold the solution being analyzed.

(4) A detector, which is a device (usually a phototube) that measures the radiant energy passed through the solution.

In the application of spectrophotometric analysis the two terms “transmittance” and “absorbance” are important. Transmittance is:

I 2 T =- I1

where T = transmittance; II = radiant energy incident upon the first surface of the sample; and I2 = radiant energy leaving the sample.

The term absorbance is defined as: 1

A = -1ogIJ” = lOg1,T

or the negative logarithm of the transmittance. In the preparation of spectrophotometric curves of light-intensity ratio

plotted against concentration, it is preferable, for convenience, t o use absorbance as the basis of the plot. Under these conditions a system that conforms to Beer’s law gives a straight-line plot, and the commonly used colorimetric systems that do not conform will usually show only a moderate curvature (Willard et al., 1965). Extreme curvature, when the curve is plotted on the basis of absorbance data, is sometimes a sign that the system is not sufficiently stable for analytical purposes. Semicolloidal suspensions of colored substances often give extreme curvatures. When transmittance data are used for plotting, a curve is always obtained unless semilogarithmic coordinates are used. The modern. spectrophotometers have an absorbance calibration as well as the conventional “percent transmittance”, and it is common practice to use the absorbance scale. The relations between trans-

COLORIMETRIC METHODS 93

mittance and absorbance plots for potassium permanganate solutions at three wavelengths are illustrated by Mellon (1950, p.95).

Several other terms for light absorption are given in the literature and are still found on the printed scales of some photometers. “Optical density” is often used; it is the same as absorbance.

Interferences

In spectrophotometric determinations, interferences often result from the presence in the sample of dissolved or suspended foreign material that either absorbs radiant energy or reacts with the color reagent to form a complex that absorbs radiant energy. In either case, the absorbance of the sample is decreased. Where the interference results from the formation of an absorbing complex by ions in solution, dilution of the sample can eliminate the interference if the sensitivity of the color reagent for the element sought is sufficiently greater than for the interfering ions. If this is not the case, other methods must be found t o increase the selectivity of the method. Among such methods are:

(1) pH adjustment: if pH is an important factor in complex ion formation, its adjustment can favor the formation of the complex of the element desired instead of the interfering ions.

(2) Masking: compounds such as EDTA (ethylenediaminetetraacetic acid) are added to the sample to form a stable complex with interfering ions, thus preventing their reaction with the color reagent.

(3) Solvent extraction: preferential solubility of some ions in organic solvents permits the removal of interfering ions.

Another common source of interference in spectrophotometry is the use of color reagents that absorb at the wavelength at which the complex of the element desired is measured. Such interference usually can be reduced or eliminated by the use of a reagent blank.

In some samples a significant source of interference results from the presence of natural color. The natural color in water samples often gives appreciable absorbance and requires either compensation or elimination. In some cases it is possible to select a spectrophotometric reagent of sufficient sensitivity that the absorbance of the constituent sought will exceed the absorbance of the natural color by a large factor. If this factor is 50 or higher the error caused by the natural color is 2% or less. Knowledge of the relative sensitivity of the constituent to be determined relative to the natural color in the sample is necessary before such a factor can be used. If the relative sensitivity is unknown the natural color of the sample should be compensated for or removed. This can be done by determining the absorbance of the test sample versus the blank specified for the procedure. Determine the absorbance of the naturally colored sample versus distilled water. The difference is the corrected absorbance and is used to determine concentration values.


Iron

The spectrochemical procedure will give values only for total iron and will not differentiate ferrous iron from ferric iron. The following procedure can be used to determine F-+* and Fe+3 in a freshly sampled water (Collins et al., 1961).

Reagents and apparatus. Standard iron solution: dissolve 1.00 g of hydrogen-reduced iron in a minimum of hydrochloric acid and dilute to 1 liter with distilled water. This solution contains 1 mg/ml of iron. Transfer 10 ml of this solution to a l-liter flask and dilute to volume with distilled water. 1 ml of this solution contains 0.01 mg of iron.

Hydroquinone solution: dissolve 1 g of hydroquinone in 100 ml of distilled water.

IRON, m i l l i g r a m

Fig. 3.11. Plot of the optical density at 522 m p of the ferrous iron complex with 2,2'- bip yridine.


O-phenanthroline or 2,2‘-bipyridine (either reagent can be used, how ever, 2,2’-bipyridine is subject to less interferences): dissolve 0.5 g of either reagent in 100 ml of distilled water. The solution can be warmed to 60°C t o effect more rapid dissolution.

Sulfuric acid, approximately 9N (441.36 g per liter): cautiously pour 270 ml of pure concentrated sulfuric acid into 650 ml of distilled water. Care- fully mix the solution, cool, and dilute to 1 liter with distilled water.

Spectrophotometer capable of measurements at 508 mp or 522 mp, glass- electrode pH meter, 100-ml volumetric flasks, 10-ml microburet, and pipets.

Procedure. Prepare a calibration curve by transferring aliquots of the standard iron solution, containing from 0.02 mg to 0.20 mg of iron, to 100-ml volumetric flasks. To separate aliquots, add 5 ml of the sodium citrate solution and determine how much sulfuric acid is necessary to adjust the pH to 3.5. Add this amount to the aliquots in the volumetric flasks. Add reagents in the following order: 5 ml of hydroquinone solution, 5 ml of 2,2’-bipyridine or O-phenanthroline solution, and 5 ml of sodium citrate. The citrate must always be added last. Convert to volume with distilled water, mix well, and let stand for 1 hour. Prepare a reagent blank in the same manner.

Determine the absorbance at 522 mp if 2,2’-bipyridine is used or 508 mp if O-phenanthroline is used. Plot the absorption versus iron concentration on coordinate graph paper. The resulting curve should be linear, as shown in Fig. 3.11.

Obtain a clean sample of brine, free of oil. Determine ferrous iron, by following the above procedure, but omit the addition of hydroquinone. To determine dissolved iron, filter the sample and follow the above procedure. To determine total iron, do not filter the sample. The amount of ferric iron can be calculated from the difference.

Calculations:

1,000 x mg iron from curve sample volume = mg/l Fe+2 or Fe+’

Concentrating copper, iron, lead, and nickel by ion exchange

To determine accurately, using colorimetric methods, copper, nickel, lead, zinc, and cadmium in oilfield brines, they should be separated from interfering ions. Many oilfield brines contain metals in such minute amounts that they must be concentrated before analyses can be made. Concentration methods investigated were ion exchange, electro-deposition, solvent extraction, and evaporation. An ion-exchange method proved to be the most practical for concentrating copper, nickel, and lead, because it is less time consuming and requires less expensive equipment than any of the other methods studied.


Acidifying the samples to pH 3.5 with acetic or hydrochloric acid minimizes precipitation and adsorption. If acetic acid is used, 2 ml of formaldehyde per liter of sample should be added to retard mold growth. These precautions will aid in obtaining representative heavy metal analyses; however, to obtain optimum results, the samples should be analyzed as quickly after sampling as possible. If it is necessary to store the samples, they should be stored in a cool, dark place and should not be moved frequently. Light accelerates photochemical reactions, and high temperatures and moving accelerate chemical reactions. Once the seal of the cap of the sample bottle has been broken, the sample should be analyzed immediately.

A chelating ion-exchange resin such as Dowex A-1 can be used to separate copper, iron, nickel, and lead from an aqueous solution. Slurry the resin into a plastic column about 36 cm long and 1.7 cm in diameter. Convert the resin to the sodium form by washing with 2 volumes of distilled water, 1 volume being equal to the amount of resin used, followed by 2 volumes of 1N sodium hydroxide, and then with 10 volumes of distilled water. Because the resin expands more than 100% when changing from the hydrogen form to the sodium form, the column must be backwashed frequently to reduce compaction of the resin and to prevent shattering of the column. Pass the brine which has been neutralized to pH 7.0 with sodium hydroxide through the column. 2 liters or more probably will be necessary, depending upon the amount of heavy metals present in the brine. Elute the chelated metals with 2 volumes of 2N hydrochloric acid and water effluents to a small volume; cool and adjust to a predetermined volume (for example, 200 ml) with water. Use aliquots of this solution for determining copper, iron, nickel, and lead.

The resin must be changed back to the sodium form as soon as the metals have been eluted, because the resin tends to lose its chelating capacity if left in the water-rinsed hydrogen form for longer than a few hours. If this happens, the resin can be regenerated by heating it at 6OoC in a 30-50% sodium hydroxide solution for 24 hours.

Once the metals are separated from the brine and concentrated, they can be analyzed using various methods such as atomic absorption spectrometry, flame spectrometry, emission spectrometry, or colorimetry (Collins et al., 1962).

The compound 2,9-dimethyl-1 ,lo-phenanthroline, assigned the name neocuproine (Diehl and Smith, 1958, p.23), has the following structure:


This reagent is used to determine copper because of its nearly specific reaction with cuprous copper. The combining ratio is 2 moles of neocuproine to 1 mole of copper. The increased selectivity of neocuproine for copper is caused by a steric hindrance effect. The cuprous neocuproine compound is formed over a pH range of 3-10 and is bright orange. The compound can be extracted with n-amyl alcohol, isoamyl alcohol, n-hexyl alcohol, or chloroform. The maximum absorption of the compound in isoamyl alcohol occurs at a wavelength of 454 mp.

Hydroxylamine hydrochloride can be used to reduce the cupric ion to cuprous. Citrate will hold any iron present in solution when the pH is adjusted to between 5 and 6. The chromate ion can cause low results; however, this effect does not occur when iron is present, which is almost always the case with an oilfield brine. The anions such as sulfide, cyanide, periodate, nitrate, t hiocyanate, and ferricyanide can interfere by reacting with hydroxylamine; however, they are eliminated in the ion exchange separation.

Reagents. Neocuproine solution: dissolve 1 g of 2,9-dimethyl-l,1 O-phenanthroline in 1 liter of ethyl alcohol.

Hydroxylamine hydrochloride solution : dissolve 10 g of hydroxylamine hydrochloride in 100 ml of water.

Isoamyl alcohol, analytical reagent grade. Sodium citrate solution: dissolve 300 g of sodium citrate in 1 liter of

water, add 2 ml of the hydroxylamine hydrochloride solution, add 1 ml of neocuproine solution, and extract with 10-ml portions of chloroform until a colorless chloroform extract is obtained.

Standard copper solution: dissolve 0.100 g of copper in 5 ml of nitric acid and 5 ml of water by heating gently to dissolve the copper. Add 5 ml of perchloric acid and evaporate to fumes of perchloric acid. Cool, dilute with water, transfer to a l-liter volumetric flask, and dilute to volume. Pipet a 100-ml aliquot of this solution to another l-liter volumetric flask. Dilute to volume with water. This solution contains 10 mg/ml of copper.

Sodium acetate.

Procedure, Add 5 ml of 10% hydroxylamine hydrochloride solution and 20 ml of 30% sodium citrate solution to a sample of effluent from the ion exchange column containing 4-150 pg of copper, and adjust the pH of the mixture to between 5 and 6 with 1 g or more of sodium acetate. Extract with a 10-ml portion of isoamyl alcohol. Separate the liquids and discard the alcohol layer. Add 10 ml of 0.1% neocuproine solution and 10 ml of isoamyl alcohol, and shake the mixture vigorously for 1 minute. Let the phases separate and transfer the alcohol layer to a 50-ml volumetric flask. Make additional extractions until the alcohol layer remains colorless. Dilute the combined alcohol extracts to 50 ml with isoamyl alcohol, mix, and measure the absorbance at 454 mp in a l-cm cell with a spectrophotometer.

#.- 30 ANALYSIS OF OILFIELD WATERS

Calculations. Estimate the amount of copper present by using a calibration curve prepared by using about 10-200 pg of copper:

pg Cu (from curve) ml sample = mg/l C U + ~

Nickel

Nickel forms a wine-red or brown compound with dimethylglyoxime (Sandell, 1959, p.555). The structure of the chelate on the basis of available evidence is:

H 3 C - C - C = CH3 //

/ I /I H3C - C C = CH,

Dimethylglyoxime gives a nearly specific reaction with nickel that has been oxidized to its higher valences with an oxidizing agent such as bromine. The wine-red compound is somewhat unstable; therefore, the absorbance measurements should be made within 10 minutes after formation of the nickel dimethylglyoximate. Cobalt and copper also give colored compounds with dimethylglyoxime, but they can be removed by washing the chloroform extract of nickel dimethylglyoximate with dilute ammonium hydroxide. Iron interference is removed by extracting the nickel dimethylglyoximate with chloroform from a solution containing citrate. Palladium, platinum, and gold also give colored compounds when nickel dimethylglyoximate is extracted with chloroform; however, they are removed, if present, by the ion-exchange separation.

Reagents. Dimethylglyoxime solution: dissolve 1 g of dimethylglyoxime in 100 ml of ethyl alcohol.

Saturated bromine water. Ammonium hydroxide solution, approximately 4N: add 200 ml of con-

centrated ammonium hydroxide to 800 ml of water. Standard nickel solution: dissolve 0.100 g of nickel in dilute nitric acid by

heating gently. Cool, dilute with water, transfer to a 1-liter volumetric flask, and dilute to volume. Pipet a 100-ml aliquot of this stock solution into another 1-liter volumetric flask and dilute to volume. This solution contains 10 pg/ml of nickel.

Hydrochloric acid, approximately 6N: cautiously add 500 ml of concentrated hydrochloric acid to 500 ml of water.

Chloroform.


C6HS I

Ammonium citrate solution: dissolve 10 g of ammonium citrate in water

Hydroxylamine hydrochloride solution: dissolve 10 g of hydroxylamine and dilute to 100 ml.

hydrochloride in water and dilute to 50 ml.

Procedure. Add 10 ml of ammonium citrate solution, and 5 ml of hydroxylamine hydrochloride solution to a sample of effluent containing up to 100 pg of nickel, and adjust the pH to 8 with ammonium hydroxide. Transfer the mixture to a 125-ml separatory funnel, add 10 ml of dimethylglyoxime solution and 10 ml of chloroform, and shake the mixture vigorously for 1 minute. Let the phases separate and extract the chloroform phase into another 125-ml separatory funnel. Make additional extractions of the sample with 10-ml portions of chloroform until a colorless chloroform extract is obtained. Add 10 ml of 4N ammonium hydroxide solution to the combined chloroform extracts in the 125-ml separatory funnel, and shake the mixture vigorously for 1 minute. Let the phases separate and discard the ammonium hydroxide phase.

Acidify the chloroform phase with 1 ml of 6N hydrochloric acid, shake the mixture vigorously for 2 minutes, let the phases separate, and discard the chloroform phase. Add 10 ml of chloroform to the acid phase, shake the mixture vigorously for 1 minute, and discard the chloroform phase. Adjust the pH of the acid phase to 6.9, transfer it to a 100-ml volumetric flask, add bromine water until a yellow color persists, swirl the mixture, and allow it to stand for 10 minutes. Add 10 ml of 4N ammonium hydroxide and 10 ml of dimethylglyoxime solution. Swirl to mix, cool to room temperature in an ice water bath, and adjust to 100-ml volume with water. After 5 minutes determine the absorbance at 445 mp using a 1-cm cell and a spectrophotometer.

Calculations. Calculate the nickel concentration in the water by using a calibration curve prepared by using about 10-100 pg of nickel:

pg Ni (from curve) ml sample = mg/l Ni+ ’

Lead

Dithizone (Sandell, 1959, p. 665) is an excellent reagent for the determination of traces of lead. Lead dithizonate probably has a formula similar to the following:

r


Lead can be extracted from a basic solution with dithizone in chloroform or carbon tetrachloride in the presence of citrate or tartrate, which prevent the precipitation of several metal hydroxides. The optimum pH range for extraction of the lead dithizonate with chloroform is 8.5-11. Cyanide will complex all interfering metals except bismuth, thallium, and stannous tin. Because these metals are separated by ion, exchange, their interference is eliminated. Ferric iron can form a ferricyanide that will oxidize dithizone; however, this reaction can be prevented by adding a reducing agent such as hydroxylamine hydrochloride.

Excess of calcium, magnesium, and phosphorus retards the lead dithizonate extraction, but thz ion exchange separation excludes phosphorus as well as much of the calcium and magnesium. The lead dithizonate in chloroform absorbs at 510 mp. The amount of lead in the chloroform phase should not be much greater than 2.5 mg/l for optimum results.

Reagents. Hydroxylamine hydrochloride solution : dissolve 10 g of hydroxylamine hydrochloride in water and dilute to 50 ml.

Standard lead solution: dissolve 0.100 g of lead in 10-15 ml of nitric acid. Dilute to 1 liter volume with water. Pipet a 100-ml aliquot of this stock solution into another 1-liter volumetric flask, add 10 ml of nitric acid, and dilute to 1 liter volume with water. This solution contains 10 pg/ml of lead.

Ammonia-cyanide-sulfite solution: add 350 ml of concentrated ammonium hydroxide, 30 ml of a 10% potassium cyanide solution, and 1.5 g of sodium sulfite, to a 1-liter volumetric flask and dilute to volume with water.

Dithizone solution: dissolve 0.01 g of dithizone in 200 ml of chloroform. Chloroform.

Procedure. Transfer a sample of the ion exchange effluent containing up to 80 pg of lead to a 125-ml separatory funnel, and add 5 ml of hydroxylamine hydrochloride solution, 75 ml of ammonia-cyanidesulfite solution, and 10 ml of chloroform. Shake the mixture vigorously for 1 minute, let the phases separate, and discard the chloroform phase. Add 1 ml of 0.005% dithizone- chloroform solution, shake the mixture vigorously for 1 minute, let the phases separate, and extract the dithizone-chloroform phase into a 25-ml volumetric flask. If the dithizone-chloroform phase is green or some color other than cinnabar red, three possibilities exist: (1) there is no lead present; (2) there is an oxidizing agent present; or (3) an excess of dithizone has been used. In any event, if the dithizone-chloroform phase is not red, acidify it with 15 ml of 1 : l O O nitric acid, shake the mixture for 1 minute to transfer the lead to the nitric acid phase, and discard the chloroform. Treat the nitric acid phase with hydroxylamine hydrochloride solution, ammonia-cyanidesulfite solution, and make another dithizone-chloroform extraction using 0.5 ml or less of the dithizone-chloroform solution. If the dithizone- chloroform phase still does not turn red, take a larger sample of the effluent. However, if the original dithizone-chloroform extraction did turn red, make


additional extractions until the dithizone-chloroform phase remains green. Dilute the combined red dithizone-chloroform phases in the 25-ml volumetric flask to volume with chloroform, mix well, and determine the absorbance with a spectrophotometer at 510 mp.

Calculations. Prepare a calibration curve by using aliquots of the standard lead solution containing 10-80 pg of lead:

pg Pb (from curve) ml sample = mg/l Pb+2

zinc

Extraction of zinc with dithizone from a weakly ammoniacal solution containing a reducing agent and citrate prevents the precipitation of iron. Extraction of zinc at a pH of 4.75 in the presence of sodium thiosulfate largely eliminates interference from copper, mercury, lead, and cadmium. The zinc dithizonate complex can be broken in 0.02N hydrochloric acid, whereas cupric dithizonate cannot. Lead and cadmium dithizonates will dissociate in 0.02N hydrochloric acid, but only traces of them should be present after the preliminary extractions.

More accurate results are obtained by applying a zincon (Platte and Marcy, 1959) method to the zinc which has been isolated by the dithizone extractions than by making another dithizone extraction of the isolated zinc and using it for absorption measurements. Therefore, the following method is a combination of the dithizone and zincon methods. Traces of any remaining interferences can be complexed.

Zinc reacts with dithizone to form a compound similar to:

r

Zinc reacts with zincon: OH 1

CsHS

to form a 1:l blue complex that absorbs at a wavelength of 620 mp.


Reagents. Standard zinc solution: dissolve 1.00 g of zinc metal in hydrochloric acid and dilute to 1 liter with water. Dilute 10 ml of the stock solution to 1 liter to prepare a standard containing 10 pg/ml of zinc.

Sodium citrate solution: dissolve 10 g of sodium citrate in water and dilute to 100 ml.

Hydroxylamine hydrochloride solution : dissolve 10 g of hydroxylamine hydrochloride in water and dilute to 100 ml.

Buffer solution, pH 4.75: dissolve 130 g of sodium acetate and 57 ml of glacial acetic acid in water and dilute to 1 liter.

Dithizone solution: dissolve 0.1 g of dithizone in a liter of alcohol-free carbon tetrachloride. Extract any alcohol from the carbon tetrachloride by shaking it with distilled water. Keep a water blanket on the extracted carbon tetrachloride when storing it.

Potassium cyanide solution: dissolve 1.0 g of potassium cyanide in water and dilute to 100 ml.

Buffer solution, pH 9.0: dilute 213 ml of lN sodium hydroxide to 600 ml with water. Dissolve 37.3 g of potassium chloride and 31.0 g of boric acid in water, mix with the sodium hydroxide, and dilute to 1 liter.

Zincon solution: dissolve 0.13 g of zincon in 2 ml of 1N sodium hydroxide and dilute to 100 ml with water.

Chloral hydrate solution: dissolve 10 g of chloral hydrate in water and dilute to 100 ml.

Hydrochloric acid, 0.02N: add 1.7 ml of concentrated hydrochloric acid to water and dilute to 1 liter.

Ammonium hydroxide. Sodium ascorbate. Sodium thiosulfate solution: dissolve 25 g of sodium thiosulfate in water

and dilute to 100 ml.

Procedure. Add 10 ml of the hydroxylamine hydrochloride solution to an aliquot of brine containing up to 200 pg of zinc, mix, add 10 ml of sodium citrate solution, and adjust the pH to 8.3 with ammonium hydroxide. Transfer the sample to a separatory funnel, add 3 ml of 0.01% dithizone solution, and shake the mixture vigorously for 1 minute. Let the phases separate and note the color of the dithizone phase. If any zinc is present, the dithizone phase will be red or violet, but not green. If the dithizone phase is green, take a larger aliquot of brine. If the dithizone phase is red or violet, extract it into another separatory funnel containing 1 ml of sodium thiosulfate solution and 10 ml of pH 4.75 buffer solution. Make additional extractions of the brine solution with dithizone solution until the dithizone remains green, which indicates that all the zinc has been extracted. This is important because the final dithizone phase must be green, not violet.

Discard the brine solution and wash the combined dithizone extracts by mixing them vigorously for 1 minute with the buffer solution. Let the phases separate, extract the dithizone phase into another separatory funnel con-


taining 10 ml of 0.02N hydrochloric acid, and shake this mixture vigorously for 2 minutes. Let the phases separate, and extract and discard the carbon tetrachloride phase. Wash the acid phase twice with carbon tetrachloride, extract, and discard the carbon tetrachloride. Transfer the acid phase to a 50-ml volumetric flask and make to volume with water.

Pipet 10-ml aliquots from the 50-ml volumetric flask to two 50-ml Erlen- meyer flasks. To both flasks add 0.5 g of sodium ascorbate followed by, in this order and with mixing, 1 ml of potassium cyanide solution, 5 ml of pH 9.0 buffer solution, and 3 ml of zincon solution. To one sample add 3 ml of chloral hydrate solution, and to the other (which is the reference solution) add 3 ml of water. Within 2-5 minutes after adding the last reagent, measure the absorbance of the sample versus the reference solution at 620 mp in 1-cm cells with a spectrophotometer.

Calculations. Prepare a calibration using aliquots of the standard zinc solution containing 10-80 pg of zinc, and use the curve to calculate the amount of zinc in the sample:

pg Zn (from curve) ml sample = mg/l Zn+*

Cadmium

Cadmium can be extracted from aqueous solutions as cadmium dithizonate into carbon tetrachloride or chloroform. Cadmium dithizonate is extracted more readily into carbon tetrachloride than is zinc dithizonate, but zinc dithizonate is extracted more readily into chloroform than the cadmium compounds. Therefore, because many oilfield brines contain more zinc than cadmium, the cadmium extraction should be made with carbon tetrachloride to insure the best possible separation from zinc.

Although citrate and tartrate do not hinder the cadmium dithizonate extraction, they do impede the extraction of lead and zinc. Cadmium dithizonate can be extracted from an alkaline solution containing cyanide and tartrate; the dithizonates of nickel, copper, silver, and tin are not extracted. Most of the interference from iron can be eliminated by oxidizing it with peroxide and filtering.

Cadmium reacts with dithizone to form a compound of the type:


Cadmium dithizonate in carbon tetrachloride absorbs strongly at a wavelength of 620 mp.

Reagents. Standard cadmium solution: dissolve 0.100 g of cadmium metal in hydrochloric acid and dilute to 1 liter with water. Pipet a 10-ml aliquot of this stock solution into another l-liter volumetric flask and dilute to volume. This solution contains 1 pg/ml of cadmium.

Ammonium chloride, 1N: dissolve 53.5 g of ammonium chloride in water and dilute to 1 liter.

Rochelle salt solution: dissolve 100 g of rochelle salt (KNaC4H406 - 4H20) in water and dilute to 1 liter.

Sodium citrate solution: dissolve 100 g of sodium citrate in water and dilute to 1 liter.

Hydrogen peroxide, reagent grade 30% hydrogen peroxide. Tartaric acid solution: dissolve 20 g of tartaric acid in 1 liter of water.

Store in a refrigerator and discard if any mold is present. No.1 dithizone reagent: dissolve 0.12 g of dithizone in 1 liter of carbon

tetrachloride. Store in a refrigerator in a dark bottle. No.2 dithizone reagent: dilute 5 ml of No.1 reagent to 100 ml with

carbon tetrachloride. Store in the refrigerator. Hydroxylamine hydrochloride solution : dissolve 10 g of hydroxylamine

hydrochloride in 50 ml of water. Prepare fresh weekly. Sodium hydroxide (35%)-potassium cyanide (1%) solution: dissolve 175 g

of sodium hydroxide and 0.5 g of potassium cyanide in water and dilute to 1 liter.

Ammonium hydroxide 5M: dilute 16.0 ml of concentrated ammonium hydroxide (14.8M) to 50 ml.

Sodium hydroxide, 5% solution: dissolve 5 g of sodium hydroxide in water and dilute to 100 ml.

Procedure. Filter the brine through Whatman No.4 filter paper (double thickness). Transfer 900 ml or less of the filtered brine to a 2-liter beaker, add 5 ml of 30% hydrogen peroxide, and heat until complete decomposition of the excess hydrogen peroxide is attained. Cool the solution and filter if any precipitate is present. Add 100 ml of ammonium chloride solution, 10 ml of rochelle salt solution, 25 ml of sodium citrate solution, and adjust the pH to between 8 and 8.5 with 5M ammonium hydroxide. Transfer the solution to a liter separatory funnel, add 15 ml of the No.1 dithizone solution, and shake the mixture vigorously for 5 minutes. Let the phases separate and extract the dithizone phase into a 50-ml separatory funnel. Reextract the brine with another 15 ml of No.1 dithizone solution. Separate the dithizone phase into the 50-ml separatory funnel and discard the brine phase.

Add 10 ml of tartaric acid solution to the combined dithizone extractions in the 50-ml separatory funnel and shake the mixture vigorously for 2


minutes. Discard the carbon tetrachloride phase and wash the tartaric acid phase twice with a 3-ml portion of carbon tetrachloride. To the tartaric acid phase add 1 ml of hydroxylamine hydrochloride solution, 5 ml of the 35% sodium hydroxide-1% potassium cyanide solution, and 10 ml of the No. 2 dithizone solution Shake the mixture vigorously for 1 minute. Let the phases separate and extract the dithizone phase into another 50-ml separatory funnel. Reextract the aqueous phase with 10 ml of No.2 dithizone solution, and add the dithizone extraction of the previous separation. Wash the aqueous phase with 5 ml of carbon tetrachloride, extract the carbon tetrachloride, and combine it with the two dithizone extractions. Discard the aqueous phase. Add 15 ml of 5% sodium hydroxide solution to the combined dithizone extractions, shake the mixture vigorously for 1 minute, extract the carbon tetrachloride phase, and determine its absorbance at 620 mp in a l-cm cell with a spectrophotometer.

Calculations Run a blank and make appropriate corrections, using a calibration curve prepared by using aliquots of the standard cadmium solution containing 1-7 pg of cadmium:

pg Cd (from curve) ml sample = mg/l Cd+2

Phosphate

Only orthophosphate will respond to the test. Polyphosphates must be reverted to orthophosphates by boiling with acid (American Petroleum Institute, 1968).

Interferences. Color development in the test is inhibited when the dissolved solids content of the sample is greater than 8% (a specific gravity greater than 1.06) or when the total iron is greater than 50 mg/l. In such cases the sample taken for analysis must be diluted with distilled water so that these limits are not exceeded. Sulfide interferes by giving high results, and should be destroyed by adding potassium permanganate solution to the acidified sample.

Reagents. Hydrochloric acid, concentrated. Reagent No. 1 : dissolve 46 g of ammonium molybdate [ (NH), )a Mo, 02,

4H2 01 in 700 ml of distilled water. The ammonium molybdate used should consist of white crystals without a bluish-green tinge. Add 2.5 ml of concentrated ammonium hydroxide to the solution and dilute to 1 liter with distilled water.

Amino solution: dissolve 10 g (about 1 level tablespoon) of amino powder mixture in 100 ml of distilled water. If solution remains turbid, filter. Store solution in a well-stoppered, brown glass bottle and prepare fresh at least every 2 weeks.


The amino powder mixture is made up by adding 5 g of sodium sulfite and 1.0 g of l-amino-2-naphthol-4-sulfonic acid to a dry mortar. Grind the materials to a fine powder. Transfer the powder to a large wide-mouthed bottle containing 66.5 g of sodium bisulfite (meta, powder, Naz Sz 0, ) and 35 g of sodium sulfite. Mix well by shaking. If the mix is not uniform, it should be passed through a 20-mesh screen and again shaken in the large bottle. Store mixture in a well-stoppered, wide-mouthed brown bottle.

Standard phosphate solution: dissolve in distilled water 0.1335 g of potassium dihydrogen phosphate (KHz PO4 ) which has been dried in an oven at 105°C. Dilute to 1 liter. 1 ml of this solution is equivalent to 0.1 mg sodium metaphosphate (NaP03 ).

Procedure. Thoroughly shake a freshly drawn sample to disperse the solids and pipet 100-ml aliquot into each of two 250-ml beakers. If the expected concentration of sodium metaphosphate is greater than 10 mg/l, take smaller aliquots diluted to 100 ml with distilled water.

Note: phosphate-free glassware must be used in this determination. The glassware should be soaked in dilute hydrochloric acid, followed by rinsing with distilled water.

Add 7 ml of concentrated hydrochloric acid to one of the samples. If it is suspected to contain sulfide, stir the solution vigorously for a minute to remove as much of the sulfide as possible, then add potassium permanganate solution (8%) dropwise until the solution just turns pink. Boil solution vigorously for 30 minutes while maintaining the volume between 75 and 100 ml by adding distilled water. Cool sample to a temperature between 70" and 95°F and dilute to 107 ml with distilled water in a graduated cylinder bearing a mark at the 107-ml level.

Add 7 ml of concentrated hydrochloric acid to the unboiled sample and treat with permanganate as above if sulfide is suspected. Filter both boiled and unboiled samples if turbid.

Add 5 ml of reagent No.1 to both samples and mix well. Add 5 ml of amino solution to both and again mix well.

Ten minutes after the amino solution addition, measure the color with a spectrophotometer at a wavelength of 690 mp, after adjusting the meter to 100% transmittance with a proper blank.

Calibration curve. Prepare a calibration curve by using aliquots of the standard phosphate solution containing up to 10 mg/l of sodium metaphosphate.

Calculations. Refer the spectrophotometer readings to the calibration curve (expressed as milligrams of NaP03 versus photometer reading) to obtain the sodium metaphosphate concentration. The results on the heated sample correspond to total phosphate, whereas, those on the unheated sample correspond to orthophosphate, the difference being polyphosphate, usually expressed as sodium metaphosphate (NaP03 ):


where A = mg NaPO, (heated sample), and B = mg NaPO, (unheated sample).

Precision. The precision is about k3% of the amount present.

Silica

Silicon is the second most abundant element in the earth’s crust and is found in most rocks as the oxide Si02 or as a silicate such as Mg,Si2O5 (OH), . The solubilities of silicate minerals in saline waters are a function of temperature, pressure, pH, Eh, dissolved gases, and other ions in solution. A limited amount of research has been done concerning silicate solubilities (Collins, 1969) in saline solutions. Some investigators believe that most silica exists in solution as H4Si04 (White et al., 1956); others that it exists both in colloidal form and as H4Si04 (Krauskopf, 1956). Hydration of silica gives the following reaction:

Si02 + 2H2 0 + Si(OH), or H4 Si04

A method developed by Schrink (1965) was used to study silicate solubilities in saline waters (Collins, 1969) and it gave satisfactory results. It also has been used to analyze some petroleum-associated waters. The method involves adding 1 ml of a 4% ammonium molybdate solution in 0.75 molar sulfuric acid solution to an appropriate aliquot of the water sample; add 15 ml of 4.5N sulfuric acid; extract for 1 minute with ethyl acetate; and determine the absorbance of the ester extract with a spectrophotometer at a wavelength of 335 mp.

Nitrate nitrogen

Nitrate is the most highly oxidized form of nitrogen and is the most stable form in an oxidizing environment. Many fertilizers contain nitrate, and waters will leach the nitrate from soil or rock. Most rocks do not contain much nitrate; therefore, it is unlikely that petroleum-associated waters contain appreciable quantities of nitrate. The nitrate in deep waters also may be depleted through anion exchange (George and Hastings, 1951).

Chloride is a serious interference in many of the methods used to determine nitrate nitrogen. Oxidizing or reducing agents such as ferric or ferrous iron also interfere. The Brucine method (Fisher et al., 1958) can be applied to a petroleum-associated water. To determine the nitrate concentration, transfer an aliquot of the sample containing up to 15 pg of nitrate into a 50-ml Erlenmeyer flask, add 15 ml of water, 1 ml of Brucine reagent (2%


aqueous solution of Brucine hydrochloride), acid, place in a dark area and allow to cool to 30°C. Determine the absorbance of the sample with a spectrophotometer at a wavelength of 410 mp.

Arsenic

The determination of arsenic in brines has received little attention despite its toxic relationship to fish and animals. The arsenic content of sea water was first investigated by Gautier (1903), who found inconsistent variations. He attributed the higher amounts found at great depth to volcanic influences, and the higher amounts found at the surface to evaporation and disturbances caused by marine animals.

Rakestraw and Lutz (1933) and Gorgy et al. (1948) also studied arsenic in sea water. They conclude that 50-60% of the arsenic is in the arsenite form, with 8--10% each of arsenate, dissolved organic arsenic, and arsenic suspended in particulate matter. Smales and Pate (1952) used an activation analysis method to determine submicrogram quantities of arsenic in sea water. They found an average of 2.6 pg of arsenic per liter, with a range of 1.6-5.0 pg/l. The water analyzed is believed representative for Atlantic Ocean water.

The Gutzeit method can be used to analyze a petroleum-associated water for arsenic (Collins et al., 1961). Arsenic is reduced to arsine with zinc in acid solution. A yellow to brown stain is produced when AsH3 passes through paper impregnated with mercuric chloride or mercuric bromide. The color- ation is produced by A s H ( H ~ B ~ ) ~ - yellow, A s ( H ~ B ~ ) ~ - brown, and As2Hg3 - black. By comparing unknowns with a series of standard papers prepared with known amounts of arsenic, a quantitative estimation can be made. Papers prepared from mercuric bromide can be preserved for several months in a dark, dry atmosphere.

Arsenic silver diethyldithiocarbamate method

Arsine gas is liberated from arsenic compounds upon the addition of zinc in an acid medium (Stratton and Whitehead, 1962). The arsine gas is passed through a lead acetate scrubber and into an absorbing tube containing silver diethyldithiocarbamate solution. The arsine and the silver diethyldithiocarbamate solution react forming a red color that can be measured spectrophotometrically.

Apparatus. Arsine generator, scrubber, and absorber. Spectrophotometer set at the following operating conditions: wavelength

- 535 mp; cells - 10 mm; phototube -blue sensitive; and slit width - 0.02 mm.

Reagents. Standard arsenious oxide solution: dissolve 1.320 g of As203 in


10 ml of 1OM NaOH and dilute to 1 liter with distilled water. 1 ml of this solution contains 1.00 mg of A% 03. Dilute this stock standard solution as required.

Hydrochloric acid, concentrated, analytical-grade. Lead acetate solution: dissolve 10 g of Pb(C2H302)2 * 3 H 2 0 in distilled

Potassium iodide solution: dissolve 15 g of KI in distilled water and dilute

Silver diethyldithiocarbamate solution: dissolve 1 g of AgS[SN(C2 H5 )2 ]

Stannous chloride solution: dissolve 40 g of arsenic-free SnC12 *2H2 0 in

Zinc, 20 mesh, arsenic-free.

water and dilute to 100 ml.

to 100 ml. Store in an amber colored bottle.

in 200 ml of pyridine. Store in an amber colored bottle.

1:3 HC1 and dilute to 100 ml with the same acid.

Procedure. Place a 25-ml sample, or suitable aliquot, containing less than 20 pg of arsenic in a Gutzeit generator.

Add to the flask successively, 5 ml of concentrated HCl, 2 ml of KI solution, and eight drops of SnC12 solution. Thoroughly mix after each addition. Allow 15 minutes for reduction of the arsenic to the tervalent state.

Insert a plug of glass wool that has been impregnated with the lead acetate solution into the scrubber. Assemble the generating apparatus and add 4 mi of the silver diethyldithiocarbamate solution to the absorber. Glass beads should be added to the absorber until the liquid just covers them.

Add 3 g of zinc to the generator and reconnect immediately. Allow 30 minutes for complete evolution of the arsine. Warm the generating flask gently to assure complete evolution of the arsine and then pour the solution from the absorber directly into the spectrophotometer cells. Make the determinations within 30 minutes as the color developed is not permanent.

CuZcuZutions. The quantity of arsenic in the sample is determined from a plot of absorbances of the standards:

pg As (from curve) ml sample = mg/l As

Fluoride

Because of interferences from large amounts of chloride present in petroleum-associated waters, a standard addition method was developed which is accurate in the presence of large amounts of chloride and sulfate and is more rapid than methods requiring distillation (Collins et al., 1961). Up to 0.01 mg of phosphate in the aliquots taken for analysis can be toler- ated. Larger amounts of phosphate than this decolorize the zirconium


cyanine R complex completely, and distillation is necessary to remove the phosphate.

Reagents. Eriochrome Cyanine R stock solution: dissolve 1.80 g of Eriochrome Cyanine R in 200 ml of distilled water.

Zirconyl nitrate stock solution: dissolve 0.40 g of zirconyl nitrate dihydrate in 100 ml of concentrated hydrochloric acid and dilute to 200 ml.

Fluoride indicator solution: add 20.0 ml of the Eriochrome Cyanine R solution to about 500 ml of water, stir and add 10.0 ml of the zirconyl nitrate solution, 75 ml of concentrated hydrochloric acid, and 4 g of barium chloride. This mixture is stable for 4 - 6 months.

Thiosemicarbazide, powdered solid.

Procedure. Measure equal amounts of brine containing less than 0.03 mg of fluoride into each of three 50-ml volumetric flasks. Add lOpg of fluoride to one of the flasks and add 20 pg to another. Add a few milligrams of solid thiosemicarbazide and 25 ml of fluoride indicator solution to each 50-ml volumetric flask. If sulfate is present, it will precipitate as barium sulfate and must be centrifuged out of suspension. Arbitrarily adjust the transmission of the blank (25 ml of fluoride indicator solution made to 50-ml volume with distilled water) at 540 mp to 32% and measure the transmission of the three solutions.

Calculations. Using coordinate graph paper, plot the transmission of the standard-addition samples on the y-axis and their concentrations in milligrams of fluoride per liter on the x-axis. Multiply the sample reading at 0 concentration by 2, and from this point on the y-axis, draw a line parallel to the x-axis until it intersects the line plotted. From this point of intersection, draw a line parallel to the y-axis until it intersects the x-axis. This value from the x-axis multiplied by the dilution factor equals the amount of fluoride in milligrams per liter. Fig. 3.3 illustrates this procedure.

Iodide

A rapid, accurate method for the determination of iodide suitable for field work utilizes the principle whereby iodide is oxidized to iodine with nitrous acid and extracted into carbon tetrachloride. Hydrogen sulfide will interfere, but it can be removed by acidifying the sample and boiling (Collins et al., 1961).

Reagents. Bromphenol blue: dissolve 0.1 g of bromphenol blue in 100 ml of distilled water.

Carbon tetrachloride. Iodide standard solution: dissolve 1.3081 g of potassium iodide in distilled

water and dilute to 1,000 ml. 1 ml contains 1 mg of iodide.


Potassium nitrite solution: dissolve 10 g of potassium nitrite in 100 ml of

Sulfuric acid, 9N. distilled water.

Procedure. Pipet a sample containing less than 3 mg of iodide into a separatory funnel, and add three drops of the bromphenol blue solution and a few drops of 9N sulfuric acid until the indicator turns yellow. Add 10 ml of carbon tetrachloride and 1 ml of a 10% aqueous potassium nitrite solution, and vigorously mix the combined phases. Extract the carbon tetrachloride phase into a glass-stoppered cylinder. A violet color in the carbon tetrachloride indicates iodine. Repeat the extractions with 5-ml portions of carbon tetrachloride until all of the iodine is extracted. Dilute the combined extracts to 25 ml with carbon tetrachloride and measure the absorbance using a spectrophotometer at a wavelength of 517 mp. Use a calibration curve prepared with standard iodide solutions to determine the milligrams of iodide in the sample.

Calculation:

mg I (from curve) x 1,000 ml sample = mg/l r

Selenium

Selenium can be reduced t o the elemental form with sulfur dioxids (Collins et al., 1964), hydrazine, hydroxylamine hydrochloride, hypo- phosphorous acid, ascorbic acid, and stannous chloride. From hydrochloric acid solutions exceeding 8N, selenium is precipitated free of tellurium when the reducing agent is sulfur dioxide. Both selenium and tellurium are precipitated by sulfur dioxide from 3 to 5N hydrochloric acid solutions. Traces of nitric acid should be removed before sulfur dioxide reduction. When precipitating selenium, it is important that the temperature of the solution be kept below 30°C because the volatile selenium monochloride easily can form and be lost. A large excess of reducing agent helps to prevent loss of the monochloride.

Selenium can be determined semiquantitatively by comparing the color of the red amorphous form, or it can be adjusted to the quadrivalent form, reacted with 3,3’-diaminobenzidine to form the monopiazselenol, and quantitatively determined spectrophotometrically. If sufficient selenium is present, it also can be determined gravimetrically .

Selenate (VI) can be reduced to selenite (IV) by heating in concentrated hydrochloric acid. Selenite is the only form that reacts with 3,3’-diaminobenzidine; the reaction is :

% N w - NH2 + H, SeO, + N = NH2 + 3Ha0

NH2 ii

H2 N NH2 S e N


Selenium adsorption on glassware can introduce a significant error. Much of this adsorption can be eliminated by treating the glassware with a solution of chlorosilane.

Reagents. Hydrobromic acid, 48%. Selenium, stock solution: dry some selenium dioxide by placing it in a

desiccator over phosphorous pentoxide for 24 hours. Dissolve 0.141 g of the dry selenium dioxide in water, add 80 ml of 48% hydrobromic acid, and dilute to 1 liter with water. 1 ml of this solution contains 0.1 mg of selenium. (Note: particles of red selenium may appear in this stock solution after long standing as a result of reduction. When this happens, a new stock solution must be prepared.)

Selenium solution: pipet 100 ml of the selenium stock solution into a 1-liter volumetric flask, add 80 ml of 48% hydrobromic acid, and dilute with water. 1 ml of this solution contains 0.01 mg, or 10 pg of selenium.

Sulfur dioxide selenium free. Hydrochloric acid, concentrated. Sulfuric acid, concentrated. 3,3'-diaminobenzidine hydrochloride: dissolve 0.25 g of 3,3'-diaminoben-

Formic acid, 2.5M: dissolve 11.5 g of formic acid in water, and dilute to

Toluene, spectro-grade. Ammonium hydroxide: dilute 10 ml of concentrated ammonium hy-

Barium chloride solution: dissolve 5 g of barium chloride in 100 ml of

EDTA solution, 0.1M: dissolve 37.225 g of disodium ethylenediamine-

zidine hydrochloride in 50 ml of water. Prepare a fresh solution each day.

100 ml with water.

droxide to 100 ml with water.

water.

tetraacetate in water and dilute to 1 liter.

Procedure. Pipet an aliquot of brine (50 ml or less) into a 100-ml volumetric flask and dilute to volume with concentrated hydrochloric acid. If desired, the detection limit can be increased by first concentrating the brine by careful evaporation after adjusting the pH to 2 with hydrochloric acid. Mix the solution and allow it to stand until most of the sodium chloride precipitates.

Carefully withdraw 50 ml of the supernatant clear liquor into a 150-ml beaker and add 10 ml of concentrated hydrochloric acid. Heat the mixture to near boiling for 10 minutes. Place the beaker in an ice-water bath beneath an exhaust hood, let the mixture cool to the temperature of the ice water, and then bubble sulfur dioxide gas rapidly into the solution for about 8 minutes. If a heavy turbidity develops, filter the solution through a micropore filter. Wash the precipitate with 20 ml of cold water if a 30-ml crucible is used, or with 5 ml if a 1.5-ml crucible is used. Take care that no air is


pulled through the precipitate until the entire filtration and washing process is complete.

Transfer the filter and precipitate back to the 150-ml beaker and add 5 ml of a 1:l mixture of hydrochloric acid and nitric acid. Heat the mixture to near boiling for a few minutes, taking care not to let the mixture boil violently or to dryness. Examine the mixture carefully to make sure that all of the selenium has dissolved. Place the beaker containing the mixture in a vacuum desiccator over anhydrous magnesium perchlorate and sodium hydroxide and let the mixture evaporate to dryness. Dissolve the residue in 5 ml of concentrated hydrochloric acid and heat the mixture to near boiling for a few minutes.

Cool the mixture, add 20 ml of water, and filter it through Whatman No.4 filter paper into a 100-ml volumetric flask. Adjust the volume to 100 ml and pipet an aliquot containing 1-100 pg of selenium (IV) from the 100-ml flask into a 100-ml beaker. Add 5 ml of 0.1M EDTA and 2 ml of 2.5M formic acid and adjust the pH to 1.5 with hydrochloric acid. Adjust the volume to about 50 ml with water, add 2 ml of 3,3'-diaminobenzidine solution, mix, and let stand for 30 minutes. Adjust the pH to 8 and transfer the solution to a 1 2 5 4 Teflon-stoppered separatory funnel containing 10.0 ml of toluene. Shake this mixture vigorously for 2 minutes and let the phases separate. Extract the toluene phase, which now contains the monopiazselenol, into a centrifuge tube. Centrifuge briefly t o clear the toluene of water droplets. If a centrifuge is not available, the organic phase can be filtered through a dry filter paper to which has been added 100 mg of anhydrous sodium sulfate. Determine the absorbance of the toluene phase at 420 mp versus a reagent blank. 1-cm cells are used; however, longer path length cells will increase sensitivity.

Calculation. Prepare a calibration curve by plotting log I,JI, which is the extinction or optical density of the solution versus the concentration, using solutions containing known amounts of selenium and treated as previously described. Estimate the amount of selenium from this curve, and calculate as follows:

'g Se = mg/l Se-* ml sample

Semiquantitative determination of selenium

Pipet a 20- to 50-ml aliquot of brine into a 100-ml volumetric flask and dilute to volume with concentrated hydrochloric acid. (To increase the detection limit, the brine can first be concentrated by careful evaporation after acidifying it to pH 2 with hydrochloric acid.) Mix the solution and allow it to stand until most of the sodium chloride precipitates.

Withdraw an aliquot of the supernatant clear liquor into a small beaker,


add additional concentrated hydrochloric acid if necessary, and bubble sulfur dioxide gas into the solution for 3 minutes. If the solution remains clear, there is less than 25 pg of selenium present. Filter the solution through a 5-ml micropore filter.

Compare the color in the crucible with a series of color standards comprising 3-20 pg of selenium. These cofar standards are prepared with known amounts of selenium and will give the fobwing colorations (in pg of selenium): 3 - very pale yellow; 6 - very pale orange; 10 - pale orange; 15 - orange; and 20 - red orange.

Barium

Qualitative test

This test can be used to detect barium and strontium in an oilfield brine. It is possible to detect barium and strontium individually by using chromate to precipitate the barium.

Transfer an aliquot of brine to a test tube, add a few millimeters of 0.5% aqueous sodium rhodizonate solution, stopper the tube, and shake the mixture vigorously. Barium and/or strontium is present if a bright red, a brownish-red, or a yellow-red precipitate forms. The deeper brown indicates barium, while the lighter yellow may indicate strontium. In any event, if a precipitate forms, barium and/or strontium is present. A series of standards can be prepared to help in determining the approximate amounts present.

To differentiate between barium and strontium, a few milliliters of a 10% aqueous solution of ammonium chromate can be added to a sample brine 30-60 minutes before the sodium rhodizonate solution is added. The more soluble strontium chromate will react with the rhodizonate while the less soluble barium chromate will not.

GRAVIMETRIC METHODS

Gravimetric methods involve isolating a compound and determining its weight. Their use can involve considerable time because preliminary separations often are necessary to remove interfering elements; e.g., to determine barium as the sulfate, all strontium should be removed before the final precipitation of the barium sulfate. One constituent present in most oilfield waters that has resisted development of a good instrumental method of analysis is sulfate, and perhaps the most accurate method to determine sulfate in oilfield waters is still the gravimetric method.

Sulfate

Sulfate is precipitated as barium sulfate from an acid solution. The precipitate is baked, cooled, and weighed.

GRAVIMETRIC METHODS 115

Reagents. Hydrochloric acid, concentrated. Barium chloride solution, 10% aqueous.

Procedure. Use an aliquot that will produce no more than 100 mg of precipitated barium sulfate. Dilute the aliquot to 250 ml with distilled water and add 1 ml of hydrochloric acid. If the sample volume itself is larger than 250 ml, add 1 ml of hydrochloric acid per 250 ml of volume. Heat to boiling and add an excess of hot, 10% barium chloride solution while stirring. Cover the solution and allow it to stand for about 4 hours at a temperature of about 85OC. Filter through a very retentive filter paper such as Munktells No.OOH or Whatman No.42, and wash with hot water until the filtrate is chloride free. Place the filter plus precipitate in a tared crucible, char slowly without igniting, and bake at 800°C for 1 hour. Place the crucible in a desiccator to cool and then weigh.

Calculation:

Barium

Interest in the knowledge of the barium concentration in most petroleum-associated waters has spurred the development of several types of methods to determine barium. Perhaps the most rapid but least accurate method is the turbidimetric method, which measures the turbidity of the sample caused by precipitated barium sulfate after addition of excess sulfate. The gravimetric method also measures precipitated barium sulfate or more preferably barium chromate. It is a more time-consuming method than the turbidimetric method, but will yield more accurate results. The double precipitation as chromate reduces the interference from calcium and strontium.

Reagents. Ammonium chromate solution: dissolve 10 g of ammonium chromate in water, dilute to 100 ml, and filter.

Ammonium chromate wash solution: dissolve 5 g of ammonium chromate in water and dilute to 1 liter. Adjust the pH of this solution to 4.6 with ammonium acetate or acetic and filter.

Ammonium acetate solution: dissolve 30 g of ammonium acetate in water, dilute to 100 ml, and filter.

Nitric acid, 4N: cautiously add 30 ml of concentrated nitric acid to 90 ml of water.

Ammonium hydroxide, concentrated. Hydrogen peroxide, 30% solution.

Procedure. Because iron will interfere if present, it should be removed by


adding a few drops of hydrogen peroxide to the sample before heating to near boiling, adding ammonium hydroxide dropwise, and stirring until the odor of ammonia is faint but distinct. Heat to boiling to remove excess peroxide and flocculate any precipitate, and then filter out the iron hydroxide.

To an aliquot of iron-free filtered water (the water should be filtered even if iron is not specifically removed) containing less than 500 mg of barium and strontium, add acetic acid until the pH is 4.6. Then add 10 ml of ammonium chromate and 1 ml of ammonium acetate. Readjust the pH to 4.6. The final volume should be about 200 ml. Boil the mixture for 5 minutes, stirring occasionally. Remove the mixture from the heat, cool it fairly rapidly to room temperature, and allow it to stand at room temperature for 1 hour.

Filter the solution through a fine porosity filter. Wash the precipitate from the beaker into the filter with the ammonium chromate wash solution. Since a second precipitation is made, it is not necessary to police the beaker. Wash the precipitate on the filter with 50 ml or more of ammonium chromate wash solution or until calcium and strontium are absent.

Dissolve the precipitate in 3 or 4 ml of 4N nitric acid. Transfer the dissolved precipitate back to the beaker and repeat the precipitation. The same filter can be used, but make sure that it is acid-free.

Dry the second precipitate for 1 hour at llO°C or until it reaches a constant weight.

Calcuhtions. Weigh the barium chromate and calculate barium as follows: mgBaCr04 x 542

ml sample = mg/l Ba+ *

Precision and accuracy. The precision and accuracy of this method with optimum conditions are 1% and 2% respectively, of the amount of barium in the sample.

OTHER METHODS

The approximate concentration of sodium in an oilfield water can be calculated by using a knowledge of the amounts of other major cations and anions in the sample. Likewise, the dissolved solids concentration in an oilfield water can be calculated.

Sodium

The practice of determining sodium by calculation does not give an accurate sodium value. For example, this value is calculated after determining all of the major common anions plus two or more cations, usually calcium and

OTHER METHODS 117

magnesium. The excess of equivalents per million of anions over cations is assumed to be sodium plus potassium, and this practice includes all the errors of the analysis plus the undetermined ions in the combined sodium plus potassium value. The ions are converted to milliequivalents per liter (me/l) by dividing each ion concentration (mg/l) by its milliequivalent weight (mglme) to give the milliequivalents per liter for each ion determined. After adding the milliequivalents per liter for both the anions and the cations, the difference is multiplied by the milliequivalent weight of sodium to give the calculated milligrams per liter of sodium.

Procedure. The calculation method is demonstrated as follows:

Anions: chloride (50,000 mg/1)/(35.5 mg/me) = 1,410 me/l sulfate (1,290 mg/1)/(48.0 mg/me) = 27 me/l bicarbonate (204 mg/1)/(61.0 mg/me) = 3 me/l

Total anions 1,440 me/l

Cations: calcium (5,900 mg/1)/(20.0 mg/me) = 295 me/l magnesium (2,000 mg/1)/(12.1 mg/me) = 164 me/l

Total cations 459 me/l

Determination of sodium: (1,440 - 459 me/l) x 23.0 mg/me = 22,600 mg/l

Dissolved solids

The dissolved solids determination can be used to estimate the accuracy of the resistivity determination. The specific gravity determination, and the evaporation method can be used t o double check the calculated total dissolved solids. Theoretically, if all the dissolved solids are accurately determined, their sum will equal the weight of the residue left after evaporation of the water. The dissolved solids include all the solid material in solution which is ionized, or which is not ionized but does not include suspended material, colloids, or gases.

The residue method involves evaporating a filtered sample to dryness followed by drying the residue in an oven at 180°C for 1 hour. The cooled residue is weighed and the total dissolved solids are calculated; e.g., if 100 ml of brine is evaporated and the residue weighs 3.0 g, then the dissolved solids equal 30,000 mg/l. The evaporation method is subject to errors when hygroscopic material such as calcium chloride is in the water, as is usually the case in oilfield waters.

The calculation method simply involves adding the sum of all the analyzed constituents as follows:


Constituent Na+ K+ Li+ Ca+ Mg+ c1- Br- HC03 S04-2

-

Total dissolved solids

Concentration( mg/l) 13,500

400 10

2,000 1,200

23,500 500

1,200 1,200

43,500

Spent acid

Hydrochloric acid is the oldest and most common solution used in oil-well acidizing (Halliburton Company, 1970)..Many additives and other acids may be used in conjunction with HC1, for example HF and HAc. Normally, 15% HCl is used; however, other strengths are quite common. These acid solutions are pumped into carbonate formations to dissolve and remove a part of the formation.

After reacting with carbonate rocks or being “spent” on the formation, the solutions are returned to the surface by various means. Often, they are mixed with formation water, and an operator may want to know when the spent acid has been recovered, or if formation water or a mixture of solution and water is being produced.

When 15% HC1 is completely spent on CaC03 or M g C 0 3 , the resulting solution will contain 90,000 mg/l Ca or Ca equivalent. The normal formation water contains only about 10,000 mg/l Ca or Ca equivalent. The procedure is based on these differences.

Reagents and equipment. The necessary reagents and equipment include: Calcium carbonate, 10-mesh. NH4 OH, reagent. Whatman No.31 filter paper. Plastic funnel. 150-ml beakers. Graduated cylinder, 25 ml. 1-ml syringe or pipette, preferably plastic. 0.5% Eriochrome Black T indicator. 2N NaOH solution. CDTA solution (disodium dihydrogen 1,2-cyclohexanediamine-tetraace-

tate): dissolve 100.0 g CDTA in 900 ml water and dilute to 1 liter. 1 ml equals 9.0 mg Ca.

OTHER METHODS 119

100

Buffer solution: 67.5 g NH4C1, 570 ml NH40H made to 1 liter with distilled water.

Example: I m l formation water = 1.3 ml CDTA

I ml return water = 5.8 ml CDTA p H r e f w n woter = 6.0 I ml CDTA = 9.0 mg Ca -

Procedure: (1) Determine the pH of the returned water. If pH is below 4, the

presence of HC1 is indicated. (2) Pour 10-15 ml of the sample into a beaker containing 10 g of

10-mesh CaC03. Bring to a boil, remove from the hotplate, allow to settle for about 5 minutes, and filter.

(3) Pipet 1.0 ml of the filtrate into a beaker containing 50 ml of HZO. Heat to boiling, add 1 ml NH40H while stirring, remove from heat, let settle for a few minutes, and filter through Whatman No.31 paper. Wash the beaker and filter twice, using 25.0 ml H2 0 for each wash. (4) Add 0.5 g Eriochrome Black T indicator to the filtrate and 10 ml of

the buffer solution (pH should be 10). Titrate with standard CDTA solution (1 ml = 9.0 mg Ca) to a permanent clear blue endpoint. Record the milliliters of CDTA used. Refer to a curve to determine the percent spent acid in the sample.

(5) To determine a blank, take 1.0 ml of the formation water through the procedure, starting at step 3 and determine 0% spent acid, or the blank correction.

Curve construction

It is desirable to construct a curve tpercent spent acid versus milliliter CDTA) for the determination of spent acid. On rectangular graph paper, plot

I

Fig. 3.12. Graph for use in calculating the amount of spent mineral acid in a water sample.


the blank titration (formation water) as 0% spent acid. Draw a straight line from this point through the intersection of the 100% spent acid and the 10.0-ml CDTA lines as illustrated in Fig. 3.12. This procedure corrects for any Ca+’ or Mg+2 present in the dilution water.

In cases where it is impossible to obtain formation water for the 0% spent acid, a reasonable approximation can be made by titrating 100 ml of the water used for washing and dilution. To this volume of CDTA, add 1.3 ml. This value can then be used for the 0% spent acid point on the plot.

Free HCl

When free HC1 is indicated (pH below 4), and it is to be determined, an additional sample is required. Withdraw 1.0 ml of clear sample. Start with step 3 and follow the procedure. The free HC1 is determined by the difference of the two titrations:

% free HC1= (A -B) x 1.5 where A = ml standard CDTA to titrate CaCO, treated sample, and B = ml standard CDTA to titrate sample.

Acetic acid solutions

Generally, acetic acid solutions are mixtures of acetic acid and HC1.

Example: 10% HCI t 5% acetic acid I ml = 7.0 ml CDTA I ml formation waler = 1.3 ml CDTA I ml return water = 4 . 2 ml CDTA I ml CDTA = 9.0 mg Ca Return canlains 51% rpent acid

ml, CDTA

Fig. 3.13. Graph for use in calculating the amount of spent mineral and organic acid in a water sample.

REFERENCES 121

Various proportions of each are common. The determination is complicated by the fact that acetic acid will not completely spend itself on calcium and magnesium carbonates. At a pH of 5-6, considerable free acetic acid is still present in the solution and this necessitates a modification of the procedure.

In this case, it is necessary to have a representative sample, or to prepare a sample of the original acid mixture used on the acid job. Take 10-15 ml of the treating acid and 10-15 ml of the returned water through the same procedure as outlined for HC1.

Again a plot is constructed, percent spent acid versus milliliters CDTA. Plot the milliliters CDTA used by the formation water as 0% spent acid and the milliliters CDTA used by the injected acid sample as 100% spent acid as illustrated in Fig.3.13. Connect these points by a straight line. From the curve, determine the percent spent acid in the sample of returned water.

Other acid mixtures are sometimes used in oil wells. The handling of these are usually too complicated for a rapid field determination.

References

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Ballinger, D.G., Booth, R.L., Midgett, M.R., Kroner, R.C., Kopp, J.F., Lichtenberg, J.J., Winter, J.A., Dressman, R.C., Eichelberger, J.W. and Longbottom, J.E., 1972. Hand- book for Analytical Quality Control in Water and Wastewater Laboratories. National Environmental Research Center, Cincinnati, Ohio, 107 pp.

Bogomolov, G.V., Kudelskii, A.V. and Kozlov, M.F., 1970. Ammonium as one of the indications of oil-gas content. Dokl. Akad. Nauk S.S.S.R., 195:938-940 (in Russian).

Brooks, R.R., Presley, B.J. and Kaplan, I.R., 1967. APDC-MIBK extraction system for the determination of trace elements in saline waters by atomic absorption spectrophotometry. Talanta, 14:809-816.

Burriel-Marti, F. and Ramirez-Munoz, J., 1957. Flame Photometry. American Elsevier, New York, N.Y., 531 pp.

Collins, A.G., 1962. Methods of analyzing oilfield waters: flame-spectrophotometric determination of potassium, lithium, strontium, barium, and manganese. US. Bur. Min. Rep. Invest., No. 6047, 18 pp.

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Friedman, I., 1953. Deuterium content of natural waters and other substances. Geochim. Cosmochim Acta, 4:213-224.

Friedman, I. and Woodcock, A.H. 1957. Determination of deuterium/hydrogen ratios in Hawaiian waters. Tellus, 9:553-556.

Furman, N.H., 1962. Standard Methods of Chemical Analysis. D. Van Nostrand, Princeton, N.J., 6th ed., 332 pp.

Garrels, R.M. and Christ, C.L. 1965. Solutions, Minerals, and Equilibria. Harper and Row, New York, N.Y., 450 pp.

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Gorgy, S. , Rakestraw, N.W. and Cox, D.L., 1948. Arsenic in the sea. J. Mar. Res.,

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Latimer, W.M., 1952. Oxidation Potentials. Prentice-Hall, New York, N.Y., 2nd ed., 392 PP.

Marsh, G.A., 1951. Portable dissolved oxygen meter for use with oilfield brines. Anal. Chern, 23:1427.

Mellon, M.G., 1950. Analytical Absorption Spectroscopy. John Wiley and Sons, New York, N.Y., 618 pp.

Mellon, M.G.,. 1956. Quantitative Analyses. Thomas F. Crowell, New York, N.Y., 694 pp. Platte, J.A. and Marcy, V.M., 1959. Photometric determination of zinc with zincon:

Potter, E.C., 1956. Electrochemistry. MacMillan, New York, N.Y., 418 pp.

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Chapter 4. INTERPRETATION OF CHEMICAL ANALYSES OF OIL- FIELD WATERS

Water analyses may be used to identify the source of a water. In the oilfield one of the prime uses of these analyses is to determine the source of extraneous water in an oil well, so that casing can be set and cemented to prevent such water from flooding the oil or gas horizons. In some wells a leak may develop in the casing or cement, and water analyses are used to identify the water-bearing horizon so that the leaking area can be repaired. With the present emphasis on water pollution prevention, it is very important to locate the source of a polluting brine, so that remedial action can be taken.

Comparisons of water-analysis data are tedious and time-consuming; therefore, graphical methods are commonly used for positive, rapid identification. A number of systems have been developed, all of which have some merit.

Calculating probable compounds

The hypothetical combinations of dissolved constituents found in waters are commonly calculated by combining the positive and negative radicals in the following order:

calcium bicarbonate magnesium sulfate sodium chloride potassium nitrate Calcium is combined with bicarbonate, and if more calcium is available

than that consumed by bicarbonate, it is combined with sulfate, chloride, and nitrate until exhausted. Conversely, any excess bicarbonate is combined with magnesium, sodium, and potassium until consumed. Other radicals can and should be added for most petroleum reservoir waters. These include lithium, strontium, barium, iron, borate, phosphate, bromide, and iodide. They can be grouped in the appropriate column and then in the calculations each positive and negative radical is totally combined, the next following radical is combined until both the cations and anions are exhausted. If the analysis is correct, the cations and anions will be present in approximately equivalent amounts.

To calculate the hypothetical combinations, the reacting values of the positive and negative radicals or ions are calculated as follows: reacting

126 INTERPRETATION OF CHEMICAL ANALYSES

TABLE 4.1

Reaction coefficients

Cation Anion

Calcium 0.0499 bicarbonate 0.0164 Magnesium 0.0823 sulfate 0.0208 Iron 0.0358 chloride 0.0282 Sodium 0.0435

TABLE 4.11

Reacting values (RV)

Cation (mg/l) RV Anion (mg/l) RV

Ca 4,000 x 0.0499 = 199.6 HC03 500 x 0.0164 = 8.2 Mg 3,000 x 0.0823 = 246.8 so4 200 x 0.0208 = 4.2 Fe 100 x 0.0358 = 3.6 C1 30,000 x 0.0282 = 846.3 Na 9,400 x 0.0435 = 408.9

858.9 858.7

TABLE 4.111

Reacting value distribution

Ca as calcium bicarbonate Ca as calcium sulfate Ca as calcium chloride Mg as magnesium chloride Fe as iron chloride Na as sodium chloride

8.2 4.2

187.2 246.8 3.6

408.9

858.9

values (RV) or equivalents per million (epm) = mg/l of ion x valence of ion/ molecular weight of ion.

The term valence of ion/molecular weight of ion is called “reaction coefficient” and the positive and negative ions have values as shown in Table 4.1. Table 4.11 indicates how the results of a water analysis are converted to reacting values.

The reacting values are a measure of the cations and anions dissolved in the water. The 4,000 mg/l of calcium with a reacting value of 199.6 can combine with all the bicarbonate, all the sulfate, and 187.2 epm of the chloride. Magnesium will combine with 246.8, iron with 3.6, and sodium with 408.9 epm of chloride. Thus the reacting values can be considered to be distributed as shown in Table 4.111.

DETERMINING A SOUGHT COMPOUND 127

TABLE 4.IV

Combination factors

Reaction values given Compound sought Combination factor

Ca o r C 0 3 Ca or SO4 Ca or C1 Mg or C03 Mg or SO4 Mg or C1 Fe or C03 Fe o r S 0 4 Fe orC1 Na or C03 Na or SO4 Na or C1

CaC03 CaS04 CaClz MgCO3 MgS04 MgClz FeC03 FeS04

N a ~ C 0 3 Naz SO4 NaCl

Fa12

50.1 68.1 55.5 42.2 60.1 47.6 57.8 76.0 63.4 53.1 71.0 58.4

TABLE 4.V

Hypothetical combinations

Ca(HC03 ) to CaC03 8.2 x 50.1 = 411 CaC03* CaS04 4 . 2 ~ 68.1 = 286CaS04 CaC12 187.2 x 55.5 = 10,390 CaC12 MgCh 246.8 x 47.6 = 11,748 MgClz FeClz 3.6 x 63.4 = 228 FeCIz NaCl 858.9 x 58.4 = 50,160 NaCl

*In mg/l.

Determining a sought compound

It is necessary to multiply the reacting value by a combination factor to determine a hypothetical compound. This factor is necessary to convert the reported radical into the desired compound. For example, the factor for converting Ca to CaCO, is 2.50 and the reaction coefficient for Ca is 0.0499. Therefore, the combination factor to convert the reacting value for Ca to CaCO, is 2.50 + 0.0499 = 50.1. Table 4.IV illustrates some combination factors.

The combination factors given in Table 4.IV can be used to calculate the hypothetical combinations shown in Table 4.V, using the analysis shown in Table 4.111.


Graphic plots

Graphic plots of the reacting values can be made to illustrate the relative amount of each radical present. The graphical presentation is an aid to rapid identification of a water, and classification as to its type, and there are several methods that have been developed.

Tickell diagram

The Tickell (1921) diagram was developed using a 6-axis system or star diagram. Percentage reaction values of the ions are plotted on the axes. The percentage values are calculated by summing the epm’s of all the ions, dividing the epm of a given ion by the sum of the total epm’s, and multiplying by 100.

Na Ca+Mg Na Ca+Mg 2-

c i \ So4

(a) CI RV=49.92% (b) h 9 2 ma / I i tar

Fig. 4.1. Tickell (a) and modified Tickell (b) diagram for Gulf Coast water, sample No.1.

Na Ca+Mg Ca + Mg s

(a) C I ~ v = 4 9 . 2 9 % (b) 1i07 ma/ l l tar

Fig. 4.2. Tickell (a) and modified Tickell (b) diagram for Anadarko Basin water, sample No. 2.

GRAPHIC PLOTS 129

H

so4 (a) C I RV= 49.92 %

so4 (b) 5,708 m e / l i ter

Fig. 4.3. Tickell (a) and modified Tickell (b) diagram for Williston Basin water, sample N0.3.

No Ca+Ma Co+Mg

$

c i\ so4 (b) 1.769 me / liter

Fig. 4.4. Tickell (a) and modified Tickell (b) diagram for Gulf Coast and Anadarko Basin waters, mixed 1:l.

Na Co+Mg

C I so4

Na Ca+Mg

(b) ‘7 C I 2870 me $. / i i t r r

Fig. 4.6. Tickell (a) and modified Tickell (b) diagram for Gulf Coast, Williston, and Anadarko Basin waters, mixed 1 : 1 : 1.


Fig. 4.1. illustrates the Tickell diagram using reaction values in percentage in the diagram on the left, and total reaction values in the diagram on the right. The plots of total reaction values, rather than of percentage reaction values, are often more useful in water identification because the percentage values do not take into account the actual 'ion concentrations. Water differing only in concentrations of dissolved constituents cannot be distinguished.

To illustrate differences in patterns for different waters, Fig. 4.1-5 were prepared using the Tickell method. Fig. 4.1 represents a water from the Gulf Coast Basin, taken from the Wilcox formation of Eocene age. Fig. 4.2 is of a sample from the Mer?.mec formation of Mississipian age in the Anadarko Basin. Fig. 4.3 is of sample from a Devonian age formation in the Williston Basin. Fig. 4.4 represents a 1:l mixture of waters of the Gulf Coast and Anadarko Basins, and Fig. 4.5 is a 1 : 1 : 1 mixture of all three waters.

REISTLE SYSTEM

Fig. 4.6. Water-analysis interpretation, Reistle system - sample numbers correspond to the samples of Fig. 4.1-3.

GRAPHIC PLOTS 131

Reistle diagram

Reistle (1927) devised a method of plotting water analyses using the ion concentrations as shown in Fig. 4.6. The data are plotted on a vertical diagram, with the cations plotted above the central zero line and the anions below. This type of diagram often is useful in making regional correlations or studying lateral variations in the water of a single formation, because several analyses can be plotted on a large sheet of paper.

St iff diagra m

Stiff (1951) plotted the reaction values of the ions on a system of rectangular coordinates as illustrated in Fig. 4.7. The cations are plotted to the left and the anions to the right of a vertical zero line. The end points then are connected by straight lines to form a closed diagram, sometimes called a “butterfly” diagram. To emphasize a constituent that may be a key to interpretation, the scales may be varied by changing the denominator of the

Fig. 4.7. Water-analysis interpretation, Stiff method - sample numbers correspond to the samples of Fig. 4.1-3.


ion fraction usually in multiples of 10. However, when looking at a group of waters all must be plotted on the same scale.

Many investigators believe that this is the best method of comparing oilfield water analyses. The method is simple, and nontechnical personnel can be easily trained to construct the diagrams.

Other methods

Several other water identification diagrams have been developed, primarily for use with fresh waters, and they will not be discussed here. The Piper (1953) diagram and the Stiff (1951) diagram were adapted to automatic data processing by Morgan et al. (1966), and Morgan and McNellis (1969). The Piper (1953) diagram uses a multiple trilinear plot to depict the water analysis, and this quaternary diagram shows the chemical composition of the water in terms of cations and anions. Angino and Morgan (1966) applied the automated Stiff and Piper diagrams to some oilfield brines and obtained good results.

References

Angino, E.E. and Morgan, C.O., 1966. Application of pattern analysis t o the classification of oilfield brines. Kans. State Geol. Sum., Comput. Contrib., No.7, pp.53-56.

Morgan, C.O. and McNellis, J.M., 1969. Stiff diagrams of water-quality data programmed for the digital computer. Kuns. State Geol. Sum., Spec. Distrib. Publ., No.43, 27 pp.

Morgan, C.O., Dingman, R.J. and McNellis, J.M., 1966. Digital computer methods for water-quality data. Ground Water, 4:35-42.

Piper, A.M., 1953. A graphic procedure in the geochemical interpretation of water analyses. US. Geol. Surv. Ground Water Note, No.12, 14 pp.

Reistle, C.E., 1927. Identification of oilfield waters by chemical analysis. U.S. Bur. Min. Tech. Paper, No.404, 25 pp.

Stiff, H.A., 1951. The interpretation of chemical water analysis by means of patterns. J. Pet. Technol., 3:15-17.

Tickell, F.G., 1921. A method for graphical interpretation of water analysis. Calif. State Oil Gas Superv., 6:5-11.

Chapter 5. SIGNIFICANCE OF SOME INORGANIC CONSTITUENTS AND PHYSICAL PROPERTIES OF OILFIELD WATERS

In general, the concentrations of the constituents in various natural solids of reservoir rocks must be considered along with the amounts that are found in associated oilfield waters. Some possible chemical reactions between host rock and reservoir water may deplete or enrich the concentration of the constituents in oilfield waters. Another important factor is the solubility of a constituent.

The ionic potential, determined by dividing the ionic radius by the valence, influences the solubility of elements. For example, elements with low ionic potential are more likely to remain in true ionic solution. Elements commonly found in oilfield waters have the following ionic potentials: sodium, 0.95; calcium, 0.50; magnesium, 0.33; chlorine, 1.81; bromine, 1.95; and iodine, 2.16. Apparently the cation (magnesium) and the anion (chlorine) would be the most likely to remain in true ionic solution; however, several other variables occur during diagenesis which lead to depletion or enrichment of constituents in waters.

Lithium

Lithium is the lightest alkali metal; it has a distinctly smaller radius, 0.60 8, than the other alkalies and is the smallest of all singly charged cations. I t is one of the less abundant elements, and its abundance in the earth’s crust is about 6.5 x wt.% (Fleischer, 1962). Here again, it is an exception because in general, the lighter elements tend to be more abundant than the heavier elements. I t is lithophilic in that it tends to be associated with the silicate phase in rocks (Ahrens, 1965); however, because of its small size, it supposedly cannot replace the abundant alkali metals in mica.

I t and the other alkali metals exist in a uniform positive one state of oxidation and are inherently ionic. Their chemical behavior depends almost entirely upon electron loss, and their chemistry is simpler than that of any of the other metallic elements (Moeller, 1954).

Lithium is potentially toxic to plants (Hem, 1970), yet it is regularly found in plant ashes, which indicates that it normally is present in soil waters (Goldschmidt, 1958). Coal ashes of Neurode, Silesia, contained up to 198 ppm lithium, whereas soils in northeast Scotland contain 30-5,000 ppm. The content of lithium in sediments ranges up to 6 ppm in quartzites and sandstones, up to 15 ppm in calcareous rocks, and up to 120 ppm in clays and shales.

134 INORGANIC CONSTITUENTS AND PHYSICAL PROPERTIES

TABLE 5.1

Properties of the alkali metals

Property Lithium Sodium Potassium Rubidium Cesium

Atomic number 3 11 19 37 55 Nonhydrated radius (A) 0.60 0.95 1.33 1.48 1.69 Hydrated radius (A) 3.82 3.58 3.31 Outer electronic configuration 1s' 2s' 2s2 2p6 3s' 3s' 3p6 4s' 4s2 4p6 5s' 5s' 5p6 6s' Atomic weight 6.939 22.990 39.102 85.47 132.905 Ionization potential (V) 5.390 5.138 4.339 4.176 3.893

- -

TABLE 5.11

Five relative concentration changes of some dissolved ions during evaporation of sea water and brine*

Constituents Concentrations (mg/l)

Sea water CaSO4 NaCl MgS04 KCI MgC12

Lithium Sodium Potassium Rubidium Magnesium Calcium Strontium Boron Chloride Bromide Iodide

0.2 2 11,000 98,000

350 3,600 0.1 1

1,300 13,000 400 1,700 7 60 5 40

19,000 178,000 65 600 0.05 2

11 140,000 23,000

6 74,000

100 10 300

275,000 4,000

5

12 70,000 37,000

8 80,000

10 1

310 277,000 4,300

7

27 13,000 26,000

14 130,000

0 0

750 360,000 8,600

8

34 12,000 1,200

10 153,000

0 0

850 425,000 10,000

8

*Approximate mg/l. Columns headed sea water, CaS04, etc., represent stages in sea water evaporation. For example, sea water contains 0.2 mg/l of lithium, after calcium sulfate has precipitated the residual brine contains about 2 mg/l of lithium, after sodium chloride has precipitated the residual brine contains about 11 mg/l of lithium, the residual brine contains about 12 mg/l of lithium after magnesium sulfate precipitates, 27 mg/l of lithium after potassium chloride precipitates, and 34 mg/l of lithium after magnesium chloride precipitates.

LITHIUM 135

The hydrated radius of lithium is 3.82 a, as shown in Table 5.1 (Moeller, 1954). The ionic potential is 0.60, and the polarization is 1.67. The polarization is quite high and is a measure of its replacing power in an exchange system. Apparently it can replace strontium, calcium, and magnesium since their polarizations are 1.77, 2.02, and 3.08, respectively.

Some surface waters of the volcanic sodium chloride type are enriched in lithium (White, 1957). Lithium from Searles Lake brine is recovered as Li2NaP04 (Brasted, 1957). The content of lithium in oilfield waters is usually less than 10 mg/l but in some Smackover formation waters from east Texas, concentrations up to 500 mg/l are present. When a brine containing lithium goes through an evaporite sequence, lithium is one of the elements whose concentration does not decrease, as illustrated in Table 5.11, in the liquid phase as various minerals precipitate (Collins, 1970). Fig. 5.1 illustrates the enrichment of lithium as compared to an evaporite sequence in some subsurface brines from Tertiary, Cretaceous, and Jurassic age sediments. Fig. 5.2 illustrates a similar enrichment for some brines taken from Pennsylvanian and Mississippian age sediments (Collins, 1969a). Possibly lithium was liberated and potassium was depleted by exchange reactions with clay minerals, degradation of lithium containing minerals, or simply a leaching of minerals, primarily silicates, which contain lithium. Lithium sub- stitutes in the structure of several common minerals and forms few minerals of its own. If the minerals in which it has substituted should degrade or break down with depth, the lithium might be resolubilized, thus increasing its concentration in the aqueous phase. White et al. (1963) postulated that because the lithium concentration in magmatic waters is related to volcanic

LITHIUM, mgll

Fig. 5.1. Comparison of the lithium concentrations in some Tertiary (T), Cretaceous (C), and Jurassic (J) age formation waters from Louisiana with an evaporating sea water.


u 10 20 3

LITHIUM, mg/l

Fig. 5.2. Comparison of the lithium concentrations in some Mississippian (M) and Pennsylvanian (P) age formation waters from Oklahoma with an evaporating sea water.

emanations, the increase in the lithium content of deeper waters might be related to the same cause.

Sodium

The most abundant member of the alkali-metal group is sodium, ranking number 6 with respect to all the metallic elements. The radius of the sodium ion is 0.95 A, and its geochemistry is controlled to some extent by calcium because of the similarity of their ionic radii. Its abundance in the earth's crust is about 2.8 wt.% (Fleischer, 1962). Table 5.1 shows that its outer electronic configuration is 2s' 2p6 3s' , with a first ionization potential of 5.138 V, indicating that its single outer electron is less firmly held than in the lithium atom with a first ionization potential of 5.390 V. The ionization potential is a measure of the chemical reactivity - the lower the potential, the greater the reactivity. Table 5.1 (Moeller, 1954) also illustrates some qf its other properties.

According to Ahrens (1965), sodium is lithophilic, and many distinctly lithophile elements have valence electrons outside a closed shell of eight electrons. The ionic radius decreases as the charge on the cation increases. Sodium does readily participate in solid solution relationships because its radius is small, making replacement of cations with 30% larger radii difficult. The amounts of sodium in argillaceous sediments and marine shales are about 1,000 ppm and 1,300 ppm, respectively (Goldschmidt, 1958).

SODIUM 137

Sodium in solution tends to stay in solution; it does not readily precipitate with an anion, and it is less easily adsorbed by clay minerals than are cesium, rubidium, potassium, lithium, barium, and magnesium. The major source of sodium in sea water can be attributed to the weathering of rocks. Some sodium probably was derived through volcanic activity. The ocean and evaporite sediments contain the bulk of the sodium. Igneous rocks contain appreciably more sodium than sedimentary rocks with the exception of evaporites.

Sea water contains about 11,000 mg/l of sodium, as illustrated in Table 5.11. The concentration of sodium increases in brine as it evaporates, to about 140,000 mg/l, when halite precipitates. Most oilfield waters contain more sodium than any other cation, and most oilfield waters are believed to be of marine origin. Fig.5.3 is a log-log plot of the chloride concentration versus sodium of some subsurface brines taken from sediments of Tertiary, Cretaceous, and Jurassic age. The straight line is a plot of chloride versus sodium concentrations for some evaporite waters, and indicates the enrichment of sodium ions until halite (NaC1) precipitates - at a chloride concentration of about 140,000 mg/l (compared to that of normal sea water, 19,000 mg/l). The plot of the concentrations of sodium versus chloride for these subsurface brines falls very near the normal evaporite curve, indicating that the concentration mechanism may be related to an evaporite process (Collins, 1970). Fig. 5.4 is a similar plot for some subsurface brines taken from sediments of Pennsylvanian and Mississippian age (Collins, 1969a). Several of these samples are somewhat depleted in sodium which indicates that

SODIUM, g / l

Fig. 5.3. Sodium versus chloride concentrations for some formation waters taken from Tertiary (T), Cretaceous (C), and Jurassic (J) zge sediments and compared to evaporating sea water.


500F --/ /

0 - Nor ma1 evaoor it e 200t-

associated b i n e

I- /"

SODIUM, mg/l

Fig. 5.4. Sodium versus chloride concentrations for some formation waters taken from Pennsylvanian (P) and Mississippian (M) age formation sediments and compared to evaporating sea water.

diagenetic processes, such as ion-exchange or ultra-filtration reactions involving clays and/or carbonates, may operate to deplete the sodium concentration in waters in older sediments.

Potassium

The second most abundant member of the alkali-metal group is potassium; its abundance in the crust of the earth is about 2.55 wt.% (Fleischer, 1962). Like the other alkali metals, it is lithophilic, and with its large ionic radius (see Table 5.1) it participates in forming solid solutions and forms its own minerals, such as feldspar and mica. The potassium feldspars are resistant to leaching by water, which may account for the low potassium concentrations in many natural waters. Clay minerals readily adsorb potassium, and in illite it is incorporated into the crystal structure in such a manner that it cannot be removed by ion-exchange reactions (Lyon and Buckman, 1960).

Potassium is less easily hydrated than sodium, and is more easily adsorbed by colloids; therefore, it is retained in sediments and soils in greater abundance than sodium. It is an essential element to plants and animals. Accord- ing to Gol&chmidt (1958), potassium in pulverized potassium feldspars is absolutely unavailable to plants.

The concentrations of potassium in carbonates, sandstones, and shales is about 2,700, 10,700, and 26,600 ppm, respectively (Mason, 1966). Potas-

POTASSIUM 139

~~ .lvv

200 -

- 100 -

1 I I I I I l l

POTASSIUM, g / I

Fig. 5.5. Potassium versus chloride concentrations for some formation waters taken from Tertiary (T), Cretaceous (C), and Jurassic (J) age sediments and compared to evaporating sea water.

sium concentrates primarily in hydrolysates (clay minerals), such as illite and glauconite, and in evaporites. Table 5.11 illustrates how the concentration of potassium in the aqueous phase increases until sylvite (KC1) precipitates. The concentration of potassium in some subsurface brines usually is depleted with respect to an evaporite-associated sea water. Fig.5.5 illustrates the relation of potassium in some subsurface brines taken from sediments of Terti-

- ,' 500 -

-

- N m a l evaporite curve

- - 5- - -

m POTASSIUM, mg/l

Fig. 5.6. Comparison of the potassium concentrations in some Pennsylvanian (P) and Mississippian (M) age formation waters from Oklahoma with an evaporating sea water.


ary, Cretaceous, and Jurassic ages to an evaporite-associated sea water (Collins, 1970). Fig.5.6 illustrates the same relation for some subsurface brines taken from Pennsylvanian and Mississippian age sediments (Collins, 1969a).

The depletion of potassium in subsurface brines might be caused by its uptake by clays. For example, montmorillonite-type clay minerals systematically change to illite with increasing depth of burial, due to thermal diagenesis; and, as a result of this transformation, they lose interlayer (bound) water (Burst, 1969). This change appears t o begin at a temperature above 90°C. (This freed interlayer water can be readily expelled, and its movement probably is important in the first migration stage of hydrocarbons.) Laboratory experiments at elevated temperatures and pressures indicate that montmorillonite loses its interlayer water and transforms into illite in the presence of potassium-enriched water (Khitarov and Pugin, 1966). The structural variations of the expandable minerals in clays apparently are also influenced by the potassium content of the associated waters.

Rubidium

Rubidium, like the other alkali metals is lithophilic, and its abundance in the earth’s crust is about 3.0 x wt.%, which is greater than that of lithium (Fleischer, 1962). I t tends to be removed from solution more readily than lithium, primarily because of its ability to replace potassium in mineral structures. Table 5.11 indicates that it precipitates from an evaporite along with sylvite to a greater extent than lithium, and it has a high chemical reactivity. The radius of its ion, 1.48 a, is only about 10% larger than the potassium ion, so it can be accommodated into the same crystal lattices. Because of this, it forms no minerals of its own.

Rubidium and cesium occur sympathetically in nature; that is, both are commonly found in amazonite, vorobyevite, and beryl (Goldschmidt, 1958). Rubidium is a member of series NH4-K-Rb-Cs, and members of this series are more similar in their chemical and physical properties than are the members of any other group, with the exception of the halogens. Rubidium concentrates in the late crystallates, particularly those of granitic derivation, and it has a greater tendency to be adsorbed by clays than has potassium. It is removed from igneous rocks by water leaching and then adsorbed by hydrolysate sediments and soils.

Shales contain about 250 ppm of rubidium; deep-sea red clays, about 400 ppm; and some glauconites, about 500 ppm (Goldschmidt, 1958). Sea water contains about 0.12 mg/l of rubidium; subsurface brines contain up to 4 mg/l. Higher concentrations of rubidium probably can be found in brines associated with rocks containing potassium minerals, such as microcline feldspars, or lepidolite mica.

CESIUM 141

Cesium

Cesium is the heaviest alkali metal and also the rarest, with an abundance of about 7 x wt.% in the earth’s crust (Fleischer, 1962). I t has an ionic radius of 1.69 8, which is distinctly larger than potassium, and it cannot replace potassium in minerals as easily as rubidium; probably because of this, it forms its own minerals. I t is leached from igneous and metamorphic rocks by water during weathering, and is adsorbed by hydrolysate sediments and soils more readily than rubidium or potassium. Its low ionization potential indicates that it has the greatest chemical reactivity of the alkali metals. Cesium and rubidium were discovered in 1860 by Robert Bunsen by use of spectral analysis, a method which he and Kirchhoff invented.

Cesium concentrates primarily like rubidium, in marine argillaceous sediments. Some shales contain about 15 ppm; deep-sea red clays, 20 ppm; and glauconite, 15 ppm of cesium (Goldschmidt, 1958). Sea water contains 5 x mg/l of cesium, and some subsurface brines contain up to 1 mg/l.

Beryllium

Beryllium is a member of the alkaline earth group in the periodic chart of the elements, but few of its properties are similar to the more abundant members, such as magnesium, calcium, and strontium. Beryllium, like lithium, is a light element with an atomic weight of 9.012 (Table 5.111; see also Moeller, 1954), and like lithium, it is an exception to the rule that light elements are more abundant than heavy elements. The earth’s crust contains about 6 x

In sedimentary rocks, beryllium is restricted primarily to hydrolysates and especially to bauxites enriched in aluminum (Goldschmidt, 1958). Shales contain about 6 ppm, and some coal ashes contain up to 8,000 ppm, although generally only about 4 ppm. The concentration of beryllium in sea

wt.% of beryllium (Fleischer, 1962).

TABLE 5.111

Properties of the alkaline earth metals

Property Beryllium Magnesium Calcium Strontium Barium

Atomic number 4 12 20 38 56 Ionic radius (A 1 0.31 0.65 0.99 1.13 1.35 Outer electronic configuration 1s’ 2s’ 2s’ 2p6 3s’ 3s2 3p6 4s2 4s’ 4p6 5s2 5s2 5p6 6s’ Atomic weight 9.012 24.31 40.08 87.62 137.34 Ionization potential (V) 9.320 7.644 6.111 5.692 5.210


water is about 5 x lo-' mg/l, and some subsurface brines contain 0.02-4.2 mg/l. Since beryllium is highly toxic, waters containing it should be handled with caution.

Magnesium

One of the more abundant members of the alkaline earth group of metals, magnesium makes up about 2.1 wt.% (Fleischer, 1962) of the crust of the earth.

Magnesium is dissolved during chemical weathering, mainly as the chloride and sulfate. Ferromagnesian minerals in igneous rocks and magnesium carbonate in carbonate rocks are generally considered to be the principal sources of magnesium in natural waters. Carbon dioxide plays an important role in the dissolution of magnesium from silicate and carbonate minerals. Waters associated with either granite or siliceous sand may contain less than 5 mg/l of magnesium, whereas those associated with either dolomite or limestone may contain over 2,000 mg/l of magnesium.

Elements commonly found in oilfield waters have the following ionic potentials: sodium, 0.95; calcium, 0.50; magnesium, 0.33; chlorine, 1.81; bromine, 1.95; and iodine, 2.16. Apparently the cation (magnesium) and the anion (chlorine) would be the most likely to remain in true ionic solution; however, several other variables occur during diagenesis which lead to depletion of magnesium in waters.

Depletion of magnesium in some waters probably is a result of the replacement reaction to form dolomite, CaMg(C0, ) 2 . Whole mountain masses are made of dolomite, which is formed by the regular substitution in the calcite

2oo t

MAGNESIUM, mg I I

Normal evaporite curve

'so0 500 rpoo 2,000 5ooO lop00 20,m 5Q( MAGNESIUM, mg I I

C J

?$ Normal / evaporite curve

Fig. 5.7. Comparison of the magnesium concentrations in some Tertiary (T), Cretaceous (C), and Jurassic (J) age formation waters from Louisiana with an evaporating sea water.

CALCIUM 143

c Normal evaporite curve

500

M M

P

r 20

1,000 I 0,000 lO0,OoO 10

MAGNESIUM, mg/l

Fig. 5.8. Comparison of the magnesium concentrations of some Pennsylvanian (P) and Mississippian (M) age formation waters from Oklahoma with an evaporating sea water.

crystal lattice of alternate ions of calcium and magnesium. The large differences in the ionic radii of Ca (0.99 A) and Mg (0.65 A) are the reason for this diadochy.

Magnesium ions in aqueous solution have a large attraction for water molecules and probably are surrounded by six water molecules in octahedral arrangement. This may account for the paucity of magnesium in soils, because the small cation becomes large by hydration. Sodium has a similar reaction, but potassium, which does not, is readily adsorbed by soil colloids.

Shales, sandstones, and carbonates contain 15,000, 7,000, and 47,000 ppm of magnesium, respectively (Mason, 1966). Subsurface brines contain from less than 100 mg/l to more than 30,000 mg/l; however, many subsurface brines are depleted in magnesium if compared to a sea water evaporite sequence, (Table 5.11). Sea water contains about 1,300 mg/l. Fig. 5.7 is a plot of chloride versus magnesium for some subsurface brines taken from Tertiary, Cretaceous, and Jurassic age sediments. The position of the normal evaporite curve indicates that all of these waters were depleted in magnesium with respect to this curve (Collins, 1970). Fig. 5.8 is a plot showing similar depletion of some subsurface brines taken from some sediments of Pennsyl- vanian and Mississippian age.

Calcium

The abundance of calcium in the crust of the earth is about 3.55 wt.% (Fleischer, 1962), making it the most abundant of the alkaline earth metals,


but only in the crust; in the earth as a whole, magnesium is much more abundant. Calcium is dissolved as bicarbonate as a result of chemical weathering of calcium-bearing minerals. Waters associated with limestone, dolomite, gypsum, or gypsiferous shale usually contain an abundance of calcium, but waters associated with granite or silicious sand may contain less than 10 mg/l of calcium. Slight changes in the pH of waters containing calcium bicarbonate will cause calcium carbonate to precipitate, and calcium carbonate is one of the most common deposits found in plugged oilfield lines, equipment, and reservoirs.

Precipitation of calcium carbonate in the sea is the prime mode of the origin of limestone. The solubility of calcium carbonate in sea water increases with salinity and increasing partial pressure of carbon dioxide, but it decreases with increasing pH, calcium content, and temperature. The solubility of calcium sulfate decreases with increasing temperature.

Shales, sandstones, and carbonate rocks contain about 22,100, 39,100, and 302,300 ppm of calcium, respectively (Mason, 1966). Sea water contains 400 mg/l and subsurface brines often contain 2,000-3,000 mg/l, with some as high as 30,000 mg/l. Fig. 5.9 is a plot of chloride versus calcium concentrations for some subsurface waters taken from Tertiary, Cretaceous, and Jurassic age sediments. The amount of calcium in these waters increases with increasing salinity, and the waters from the older sediments appear to contain more calcium. Fig. 5.10 is a similar plot for some subsurface brines taken from sediments of Pennsylvanian and Mississippian age. These samples all appear to be enriched in calcium relative to the evaporite curve, and the concentration of calcium appears to increase with increasing salinity.

200 -


- 100- - - \ 0

1 I 1 I I I111 500 1 , m 2 p 5poo lop00 29ooo

CALCIUM, mg/l

Fig. 5.9. Comparison of the calcium concentrations of some Tertiary (T), Cretaceous (C), and Jurassic (J) age formation waters from Louisiana with an evaporating sea water.

STRONTIUM 145

&-\- Normal

2 0 1 /

M

P

Ii

evaporite curve

P M M

1

CALCIUM, mg/ I

Fig. 5.10. Comparison of the calcium concentrations of some

00

Pennsylvanian (P) and MEsissippian (M) age formation waters from Oklahoma with an evaporating sea water.

Strontium

Strontium, a minor element compared to calcium and magnesium comprises about 0.03 wt.% of the earth's crust (Fleischer, 1962). Table 5.111 illustrates some of its properties, and it resembles calcium chemically. Stron- tium has a tendency to work upward during fractional crystallizaticn because of its relatively large radius (Goldschmidt, 1958). It occurs abundantly with potassium in volcanic rocks, alkali rocks, and pegmatites.

Dissolved strontium results from water leaching of rocks, and it has been postulated that the strontium in petroleum-associated waters also may be a byproduct of the organic decay processes which originally formed petroleum. Strontium is only a microconstituent in most terrestrial animals, but several species of marine animals contain considerable quantities of strontium in their skeletons (Odum, 1951).

Table 5.11 indicates that strontium may reach a concentration of 60 mg/l during sea-water evaporation, and then most of it precipitates with calcium sulfate. The amount of sulfate in the water influences the amount of strontium that remains in solution. Data by Sillhn and Martell (1964) indicate that if the sulfate activity in a water is 100 mg/l, the strontium activity can be about 28 mg/l. Davis and Collins (1971) studied the solubility of strontium sulfate in strong electrolyte solutions and found that 958 mg/l of strontium is soluble in a synthetic brine solution of ionic strength 3.05,


containing ions of sodium, calcium, magnesium, potassium, chloride, bromide, and iodide. Calcium chloride concentration apparently has a very pronounced effect upon the solubility of strontium sulfate.

Celestite and strontianite occur commonly in sediments. Carbonate sediments contain up to 1,200 ppm of strontium; dolomites, usually less than

“““I I C -Cretaceous J -Jurassic

C J c cc 2,000

cC

C

T I I I I I I I IIL 10 20 50 100 2 a

STRONTIUM, mgll

Fig. 5.11. Comparison of the strontium concentrations of some Tertiary (T), Cretaceous (C), and Jurassic (J) age formation waters from Louisiana with an evaporating sea water.

500 - -

200 - - \

P

I I l l 50 100 ZOO 500 1,000

STRONTIUM, mg/l

Fig. 5.12. Comparison of the strontium concentrations of some Pennsylvanian (P) and Mississippian (M) age formation waters from Oklahoma with an evaporating sea water.

BARIUM 147

170 ppm; and secondary gypsum, up to 1,100 ppm (Goldschmidt, 1958). Sea water contains about 8 mg/l of strontium, but subsurface brines contain up to 3,500 mg/l. Fig. 5.11 is a plot of chloride versus strontium content for some subsurface brines taken from some Tertiary, Cretaceous, and Jurassic age sediments. Most of these samples were enriched in strontium compared to the evaporite-associated water, and it is possible that a mechanism similar to dolomitization could cause the enrichment. In comparison to calcium, the strontium appears to be increasingly accumulated; for example, only five samples (from Tertiary sediments) fell within the normal evaporite curve. Fig. 5.12 is a similar plot for some subsurface brines showing similar results taken from sediments of Mississippian and Pennsylvanian age.

Barium

Barium, like strontium, is a minor element, comprising 0.04 wt.%, of the earth’s crust; it is more concentrated in igneous rocks and less concentrated in sedimentary rocks (Fleischer, 1962). It, like the other alkaline earth metals, is predominantly lithophile. Table 5.111 illustrates some of the properties of barium; its ionic radius, 1.35 A, permits it to replace potassium, but usually not calcium and even less commonly magnesium. Barium forms more of its own minerals than does strontium. Barium is readily absorbed by colloids, like potassium, and is therefore retained by soils or precipitated with hydrolysates; it is also concentrated in deep-sea manganese nodules (Hem, 1970).

Barium dissolves as bicarbonate, chroride, or sulfate during weathering processes, and migrates in aqueous solutions as these compounds. The solubility of barium sulfate increases when hydrochloric acid or chlorides of the alkali or other alkaline earth metals are present in solution. The properties of barium are similar to those of strontium. Both precipitate through loss of carbon dioxide from a bicarbonate-bearing solution, or as sulfates by the action of sulfuric acid, sulfides, or sulfates. Strontium, however, is less likely to be absorbed by clays than barium, because its ionic radius is smaller and its ionic potential is higher.

Encrustation deposits taken from plugged pipes of waterflood systems for secondary recovery of oil, where barium is present, usually contain barium, calcium, strontium, iron, and traces of other metals. Barium may cause problems in waterflood systems by reacting with the chromate-type oxygen- corrosion inhibitors, forming water-insoluble barium chromate.

The amount of barium found in sandstones, shales, and carbonates is about 180, 450, and 90 ppm, respectively (Goldschmidt, 1958). Sea water contains about 0.03 mg/l, and subsurface brines may contain more than 100 mg/l; however, many brines contain less than 10 mg/l. Davis and Collins (1971) found that 59 mg/l of barium sulfate is soluble in a synthetic brine with an innic strength of 3.0487, containing sodium, calcium, magnesium,

TABLE 5.IV

Properties of aluminum. copper. iron, lead, manganese, and zinc

property Aluminum Copper Iron Lead Manganese Zinc

Atomic number 13 27 26 82 Ionic radius (A) 0.50 0.96(+1) 0.76(+2) 1.20(+2)

0.691+21 0.64(+3) 0.84(+4)

25 30 0.80(+2) 0.74 0.46c+7 1.. . , . . . .

Outer electronic configuration 2s22p63s23p1 3s23p63d'04s' 3s23p63d64s' 4d'05s'5p64f'5d106s'6p' 3s' 3p6 3d5 4s' 3s2'3p6 3d" 4s' Atomic weight 26.98 63.54 55.54 207.19 54.938 65.37 Ionization potential (V) 5.984 1.723 1.165 7.415 1.168 9.391

MANGANESE 149

potassium, chloride, bromide, and iodide ions. Many analyses performed by wet chemical methods indicate rather high concentrations of barium in some subsurface brines. Some of these high results probably should be attributed to strontium plus barium rather than barium only, because satisfactory separation of the two in wet chemical methods is very difficult to accomplish.

Manganese

Manganese is a member of the VII B group of elements and is well known for its multiplicity of oxidation states. Essentially it is cationic, and the Mn+4 oxidation state usually is found in sediments. Its (+2) ionic radius is 0.80 8, while the ferric iron radius is 0.76 8 (see Table 5.IV); reasonable amounts of interchange in crystal lattices between these two ions are possible. The abundance of manganese is about 0.1 wt.% of the earth’s crust (Fleischer, 1962).

Manganese is present in many oilfield brines because it is readily dissolved by waters containing carbon dioxide and sulfate. Except for titanium, manganese is the most abundant trace element in igneous rocks. Nearly all mineral groups of petrological importance contain manganese. During weathering, manganese is dissolved mainly as the bicarbonate. Decomposition of the bicarbonate leads to the formation of M d 4 compounds. In a reducing type of environment Mn+ compounds are less mobile, and Mn+4 compounds precipitate from aqueous solutions. In general, manganese remains in solution at a low redox potential and precipitates at a high redox potential.

According to Goldberg (1963), manganese oxide nodules on the ocean bottom occur in both shallow water and deep water environments. He attributes these deposits to slow oxidation of dissolved manganese in areas where the waters contact an oxide surface. In most subsurface brines, the manganese is in the reduced form (Mn+*) because the redox potential is low and the pH is less than 7.0. Any in subsurface brines probably would be suspended with particulate matter or complexed by organic compounds, rather than in ionic solution.

Shales and carbonates contain about 850 ppm and 1,100 ppm, respectively, of manganese (Mason, 1966). Sea water contains about 0.002 mg/l, and many subsurface brines contain 1.0 to 6.0 mg/l of manganese.

compounds migrate in aqueous solutions. Mn+

Iron

Iron is a member of the VIII group of elements and is predominantly siderophile. However, because it has an affinity for sulfur, it is also thiophile; and because it commonly enters into silicate minerals, it is lithophile as well. It is an ubiquitous element, with an abundance of about 5 wt.% of the earth’s crust (Fleischer, 1962).


Iron, cobalt, and nickel possess atomic radii that differ only about 2% or less, so that the crystal chemistry of the three are related. The divalent ions of nickel, magnesium, cobalt, and iron have similar ionic radii; consequently, their chemistries in the sequence of isomorphous crystallization of mixtures are similar. The trivalent ions of iron and cobalt are similar in size, but the high oxidation potential of cobalt prevents much replacement (Goldschmidt, 1958).

The solubility of iron compounds in ground waters is a function of the type of iron compound involved, the amounts and types of other ions in solution, the pH, and the Eh. According to Larson and King (1954), 100 ppm of ferrous iron can stay in solution at pH 8 and pH 7; the theoretical maximum is about 10,000 ppm. The effects of many other ions, plus temperature and pressure differentials, such as those common to oilfield waters, have not been thoroughly studied. When a ground water in which ferrous iron is dissolved contacts the atmosphere, the following reaction can occur:

2Fe2+ + 4HCO3- + H2 0 + 1/2 0 2 + 2Fe(OH), + 4C02

Sandstone contains iron oxide, iron carbonate, and iron hydroxide, and shales and carbonate rocks contain oxides, carbonates, and sulfides of iron. Oilfield waters with characteristic low redox potentials dissolve some iron from the surrounding rock. The iron occurs in such waters at two levels of oxidation, ferrous or ferric.

Knowledge of the amount and type of iron compounds in oilfield waters is used to estimate the amount of corrosion that is occurring in the production system, and to determine the type of treatment required if the water is t o be used for waterflooding. This knowledge also enables determination of the Eh of the in situ water, because the Eh can be calculated from the Fe+2 and Fe+ values.

Shales, sandstones, and carbonates contain about 47,200, 9,800, and 3,800 ppm, respectively, of iron (Mason, 1966). Sea water contains about 0.01 mg/l, and subsurface brines contain from traces to over 1,000 mg/l of iron.

Copper

Copper is a member of the VIII group of elements, and it is character- istically thiophile; the largest concentrations of it are found in various sulfur compounds. The earth’s crust contains about 0.01 wt.% of copper (Fleischer, 1962). Its compounds are dissolved easily during weathering, if the pH of the solution is less than 4.5. Many of the water-soluble copper compounds are salts of organic acids such as acetic, citric, and naphthenic. Much of the copper that is dissolved is precipitated afterward as sulfide. Traces of copper remain in the oceans, but its content is kept low because of the adsorption on, or combination with, marine organisms. Miholic (1947) presented an age

ZINC 151

division for mineral waters based on the presence of heavy metals in waters associated with joints and faults caused by tectonic movements of different geological ages. He placed copper as the predominant heavy metal in the Caledonian Group of the Orogenic Epoch (post-Silurian). Biochemical processes are known to be responsible for enriching a deposit in metals such as uranium, copper, and vanadium; therefore, this classification is restricted to waters of igneous origin.

Most shales and carbonates contain about 45 and 4 ppm, respectively, of copper, with sandstones containing less than 1 ppm (Mason, 1966). Sea water contains about 0.003 mg/l, and most subsurface brines analyzed in this laboratory contained from less than 0.5 mg/l up to about 3 mg/l. The solubility of copper generally decreases with decreasing redox potential and increases with increasing redox potential if reduced sulfur is present. Most subsurface oilfield brines have relatively low redox potentials.

zinc

Zinc is a member of the I1 B group of elements and is predominantly thiophile. Its abundance in the crust of the earth is about 0.013 wt.% (Fleischer, 1962). Its geochemistry results from the similarity of its divalent ionic radius and the radii of Mg+’, Ni+?, Co+’, Fe+’, and Mn+’ (Goldschmidt, 1958).

Zinc is dissolved readily as sulfate or chloride from acid rocks, such as granite, during weathering. Conversely, zinc is not dissolved easily from limestone with which it is deposited. Most alkaline waters do not extract zinc; however, a solution of NH,, NH,NO,, and NaC10, can extract and hold small quantities of zinc; the more acidic the water, the greater the amount of zinc extracted. Zinc is precipitated as the sulfide, oxide, carbonate, or silicate. Traces of zinc are found in sea water, but eventually zinc is deposited in carbonated sediments or in bottom muds or sapropels as sulfide.

Shales, sandstones, and carbonates contain about 95, 16, and 20 ppm, respectively, of zinc (Mason, 1966). Sea water contains about 0.01 mg/l, and subsurface brines contain traces to more than 500 mg/l of zinc.

Mercury

Mercury is a member of the I1 B group of elements, which also includes zinc and cadmium. It is relatively abundant for a heavy element, but still must be considered scarce, with an abundance of about 4 x lo-’ wt.% of the crust of the earth (Fleischer, 1962). Most commercial deposits of mercury are of hydrothermal origin and are related to magmatic rocks; the commercial ore is cinnabar, HgS, or the liquid metal itself (Goldschmidt, 1958). Mercury is predominantly thiophile, and its geochemistry is controlled by the fact that it is volatile, with a boiling point of 357”C, and can be reduced to the metal by ferrous iron. Therefore, in a magmatic environment


the temperature and the redox potential control its occurrence. It is transported in hot springs (White et al., 1963).

Shales, sandstones, and carbonates contain about 0.4, 0.03, and 0.04 ppm, respectively, of mercury. Sea water contains 3 x lo-’ mg/l, and subsurface oilfield brines contain 0-0.15 mg/l. The samples containing 0.15 mg/l of mercury were found in relatively dilute brines taken from the Cymric and the Rio Bravo oilfields in California. Free mercury is found in the oils produced from these fields, and the ages of the producing formations range from Eocene to Pleistocene.

The mercury content of natural waters has been used to locate cinnabar deposits (Dall’Aglio, 1968). The amounts of mercury in waters appear to increase with increasing bicarbonate concentration. Karasik et al. (1965) found that saline waters containing 200,000 mg/l of chloride contain very small amounts of mercury, which suggests that anionic complexes such as HgC14-* may not be important transporters of mercury. Brackish waters containing up to 3,000 mg/l dissolved solids, up to 400 mg/l of bicarbonate, and the iodide ion sometimes contain up to 10 ppb of mercury, while stronger brines contain <0.1 ppb of mercury, which suggests that mercury may be transported as Hg14-* in brackish waters.

Lead

Lead is a member of the IV A group of elements; it is ubiquitous in the earth, but its abundance in the crust is only about 0.002 wt.% (Fleischer, 1962). I t is extracted from its minerals during weathering and migrates in the form of soluble-stable compounds. I t is particularly soluble in acetic and other acids. Because the bicarbonate form is more soluble than the carbonate, lead can be transported as the bicarbonate. Most of the lead is precipitated from waters before they reach the sea. Hemley (1953) studied lead sulfide solubility related to ore deposition from saline waters. He concluded that lead-complex concentrations increase with increasing concentrations of bivalent sulfur and decrease at pH values above 7. The solubility of lead is limited primarily by the solubility restrictions of its sulfide and sulfate in reducing and oxidizing systems. How its solubility is influenced by many other ions, such as those found in a brine, has not been sufficiently studied.

Shales, sandstones, and carbonates contain about 20, 7, and 9 ppm of lead, respectively. Sea water contains about 0.003 mg/l, and subsurface brines contain trace amounts to more than 100 mg/l of lead.

Cadmium

Cadmium is a member of the I1 B group of elements and may be considered one of the rarer elements; its abundance is about 3 x lo-’ wt.% of the earth’s crust (Fleischer, 1962). It is strongly thiophile, but its chemistry

BORON 153

differs from that of zinc in that it will precipitate from a strong acid solution, whereas zinc will not. There are few independent cadmium minerals, and its distribution is mainly that of a “guest” atom or ion in minerals. It frequently is present in lead-zinc deposits and occurs in solid solution in hypogene sulfides. A main carrier of cadmium is sphalerite, and oxidation of sphalerite or other sulfides containing cadmium will release the soluble cadmium sulfate.

Shales and carbonates contain about 0.3 and 0.035 ppm of cadmium, respectively, and sandstones contain less than 0.01 ppm (Mason, 1966). Sea water contains about 0.0001 mg/l, and the subsurface oilfield brines may contain from 0 to about 0.001 mg/l of cadmium. Subsurface brines of the sulfate type in contact with lead-zinc deposits probably contain higher concentrations of cadmium.

Boron

Boron is a member of the I11 A group of elements, and it is an oxyphile and lithophile element. Its abundance in the crust of the earth is about 0.001 wt.% (Fleischer, 1962). It has small atomic and ionic radii.

Knowledge of the presence of boron compounds in oilfield waters is important for several reasons. Boron is useful in identifying the sources of brines intrusive to oil wells, or in fresh-water lakes or streams. In concentrations exceeding 100 mg/l, it affects electric log deflections. Boron is present in oilfield brines as boric acid, inorganic borates, and organic borates. When it is present as undissociated boric acid, it is an important buffer mechanism, being second only to the carbonate system. It may be precipitated as the relatively insoluble calcium and magnesium borates.

Kazmina (1951) calculated the borate-chloride coefficient of some Russian oilfield waters. With a plot of the borate-chloride coefficient in logarithmic coordinates as a function of chloride content, he distinguished genetic groups of natural waters found in oil-bearing regions.

Mitgarts (1956) studied the significance of boron and other elements in petroleum prospecting. In general, boron, together with bromine and iodine, is always associated with waters accompanying petroleum. Like chlorine, it can be considered an element of marine origin. The solubility of most boron compounds, the hydrolytic cleavage of boron salts, and their ability to be occluded and coprecipitated with other compounds account for the extensive migration of boron. Soluble-complex boron compounds in brines and connate waters probably are there as a result of the decay of the same plants and animals that were the source of petroleum.

Shales, sandstones, and carbonates contain about 100, 35, and 20 ppm, respectively, of boron. Sea water contains about 4.8 mg/l, and subsurface oilfield water contains from trace amounts to more than 100 mg/l. Fig. 5.13 is a plot of chloride versus boron concentrations of some oilfield brines taken from some sediments of Tertiary, Cretaceous, and Jurassic age. The plot


---I- 200 Normal evaporite curve, / %

T T

a 50

J 0

I " 30 / c C " T "k/~ J c T

BORON,mg/I

Fig. 5.13. Comparison of the boron concentrations of some Tertiary (T), Cretaceous (C), and Jurassic (J) age formation waters from Louisiana with an evaporating sea water.

P I

BORON, mg/ l

Fig. 5.14. Comparison of the boron concentrations of some waters from Pennsylvanian (P) and Mississippian (M) age sediments with an evaporating sea water.

indicates that the majority of these brines are enriched in boron relative to a normal evaporite-formed brine, and that the samples that were depleted in boron may have contained dissolved halite. Fig. 5.14 is a similar plot for some samples taken from some Pennsylvanian and Mississippian age sediments. Boron is one of the elements whose concentration in the aqueous phase increases as a brine is evaporated, as illustrated in Table 5.11.

ALUMINUM 155

Aluminum

Aluminum is the third most abundant element in the earth’s crust, but its concentration in natural waters usually is less than 1 mg/l. The ionic radius of trivalent aluminum is 0.57 a (Goldschmidt, 1958), and it usually behaves as a cation when 6-coordinated with oxygen compounds. However, when 4-coordinated, it usually acts like the central atom of an anion. The 4-coordination usually, but not exclusively, is associated with minerals formed at high temperatures, but the 6-coordination is associated with minerals formed at low temperatures, which includes most sediments in the petroleum environment.

The clay minerals illite, kaolinite, and montmorillonite often contain about 13.5, 21, and 11% aluminum, respectively. Quartzites, sandstones, limestones, and shales contain about 0.7, 3.0, 0.6, and 10% aluminum, respectively. During weathering silica will leach out and leave aluminum hydroxide behind (Pirsson and Knopf, 1947), and sedimentation processes leave only about 0.4 mg/l aluminum in sea water.

According to Hem (1970), the cation AP3 predominates in solutions with a pH of 4.0 or less. Above pH 4.5, polymerization gives rise to an aluminum species with a gibbsite (aluminum hydroxide) structural pattern. Above pH 7.0, the dissolved form is the anion A1 (OH),-.

The pH of the water is the main control of the amount of alumium that is likely to be present in natural waters. A water with a pH less than 4.0 may contain 1% or more of aluminum; for example, waters associated with acid mine drainage. Oilfield waters contain trace amounts to more than 100 mg/l of aluminum.

A 1 ha 1 in ity

Alkalinity is defined as the capacity of a solution to neutralize an acid, usually to a pH of 4.5. A solution with a neutral pH of 7.0 may have a considerable amount of alkalinity; therefore, alkalinity is a capacity function, in contrast to pH, which is an intensity function. The alkalinity-pH ranges originally coincided with methyl orange and phenolphthalein color end points. The potentiometric titration produces more accurate alkalinity results, and it utilizes an end point where the most abrupt pH change occurs while specific increments of a standard acid are added.

Alkalinity usually is caused by the presence of bicarbonate, carbonate, or hydroxyl ions in a water; however, the weak acids such as silicic, phosphoric, and boric can contribute titratable alkalinity species. Carbon dioxide, which is dissolved in circulating waters as bicarbonate or carbonate as a result of the carbon cycle, is the prime source of alkalinity in shallow ground waters. However, in deep subsurface brines, additional carbon dioxide probably is dissolved as a result of diagenesis of inorganic and organic compounds.

Most oilfield waters contain no hydroxyl ions, and most of them contain


no carbonate ions, but they do contain bicarbonate ions. Some oilfield waters in the Rocky Mountain area are alkaline and contain both primary and secondary alkalinity, where primary alkalinity is that associated with the alkali metals and secondary alkalinity is that associated with the alkaline earth metals. For example, the Green River formation waters that are in or near trona beds may contain more than 20,000 mg/l of carbonate and 5,000 mg/l of bicarbonate. Most oilfield waters from other areas contain from about 100 to 2,000 mg/l of bicarbonate.

Acidity

The basis of acidity is the solvated hydrogen ion H30+ , which is found in nature. Volcanic emanations produce HF, HCl, and H2 SO4, probably formed by reactions between water and constituents associated with the magma. Waters associated with peat may contain organic acids, rain waters may contain carbonic acid, and waters associated with reducing conditions and anaerobic bacteria may contain H2 S.

Acidity, as contrasted to alkalinity, is the capacity of a solution to neutralize a base, usually from below pH 4.5 to pH 7.0. Most oilfield brines normally do not contain acidity. New wells or reworked wells often are acidified or "acidized" with a strong mineral acid or a combination of mineral and organic acids. This treatment causes the produced water to contain a certain amount of acidity until all of the acid is neutralized or diluted. Because of the large quantities of acids used in some treatments, it may take 6 months or more for the water produced from a treated well to return to normal. Organic acids and organic acid salts commonly are found in oilfield waters, and the concentration ranges from trace amounts to more than 3,000 mg/l.

Silica

Silicon is the second most abundant element in the earth's crust, which contains about 27 wt.% of it (Fleischer, 1962). It always occurs in a combined form. Most of the silicon compounds involve structures with oxygen, and there are about a thousand silicate minerals in the earth's crust; however, those which are predominant are relatively few in number.

The solubility of silica in water is a function of temperature, pressure, pH, and other ions in solution. Most silica in natural water probably is in the form of monomolecular silicic acid, H4 Si04 or Si(OH)4. Collins (196913) studied the solubility of a serpentine in solutions of calcium chloride and sodium chloride a t temperatures from 30" to 200°C and pressures from 176 to 1,055 kg/cm2. The solubility calculated as silicon molarity in solution increased with increasing concentrations of sodium chloride, increasing pressure, and increasing temperature up to about 125°C. Between about 125" and 2OO0C, the solubility decreased with increasing temperature. The solu-

AMMONIUM NITROGEN 157

bility of silicon in the presence of calcium chloride solutions decreased with increasing Concentration of calcium chloride and with increasing temperature above about 100°C. The solubility increased with increasing pressure and with increasing temperature between 30' and about 100°C. Subsurface petroleum-associated brines usually contain less than 30 mg/l of dissolved silica; Rittenhouse et al. (1969) report that their silica content ranges from about 1 to 500 ppm as silicon, and that some low salinity waters contained a higher median content of silica than more saline waters in other areas.

Ammonium nitrogen

Ammonium contains nitrogen in the N-3 oxidation state, a reduced form. Nitrogen can occur in all of its states of oxidation, ranging from -3 to +5. Oxidation of the reduced forms produces nitrogen gas, N 2 , and other nitrogen species up to nitrate, NO3-. Ammonia, NH3, forms during the anaerobic decay of organic nitrogenous material. The petroleum genetic environment produces ammonia, which transforms to ammonium, NH4, in many petroleum-associated waters because the redox potential is too low to oxidize the ammonia to nitrate. The ammonium ion is too weak to be successfully titrated; however, Collins et al. (1969), developed a technique using formaldehyde, whereby a produced strong acid can be titrated.

TABLE 5.V

Ammonium content of 10 subsurface brine samples

Sample State Formation

1 2 3 4 5 6 7 8 9 10

Utah Utah Utah Okla. Okla. Utah Utah Okla. Okla. Okla.

Navaho Green River Lower Green River Morrow Rue Uinta Surface, Green River Green River Hunton Oswego Chester

30-143 852-1,719 914-1,737

2,713-2,715 1,958-1,963

717-1,111 68 1-1,5 5 6

2,696-2,77 1 1,928-1,951 2,408-2.437

0 71 91

0 116

2,069 5

434 233 23

The NH4N content of several oilfield brines was determined and a wide variation in concentration was found. Table 5.V illustrates the amounts of NH4N found in 10 samples taken from subsurface rocks in Oklahoma and Utah.


Phosphorus

Phosphorus occurs in the earth’s crust almost exclusively as the ion, and a large percentage of it is contained in the apatite group of minerals, which primarily are related to igneous rocks. The crust of the earth contains about 0.12 wt.% of phosphorus. I t is a member of the V A group of elements with oxidation states ranging from -3 to +5. In contrast to nitrogen, phosphoric acid and phosphates are not oxidizing agents.

The phosphorus species present in most natural waters probably is the phosphate anion, and it usually is reported as an equivalent amount of the orthophosphate ion (PO4 )-3, the final dissociation product of phosphoric acid, H3 PO4. This dissociation occurs in four steps, giving four possible phosphate forms: H3 PO4, H2 PO4-, HP04-2, and P 0 4 - 3 . In the alkalinity titration, any HP04-2 is converted to H2P04- and appears as bicarbonate.

Shales, sandstones, and carbonates contain about 700, 170, and 400 ppm, respectively, of phosphorus. Sea water contains about 0.07 mg/l. A detailed study of the content of phosphorus in subsurface brines has not been made, but of the few that have been analyzed, most have contained less than 1 mg/l.

Arsenic

Arsenic is a member of the V A group of elements and probably occurs in nature mainly in the form of arsenides and sulfarsenides; it rarely occurs in its elemental form. It is comparatively rare, and the earth’s crust contains about 0.0005 wt.% of it (Fleischer, 1962). In an acidic environment, the oxidized ion, A s O ~ - ~ , is mobile, and mineral arsenates tend to be solubilized. The arsenates usually are formed in oxidation zones in contact with atmosphere and free oxygen, and arsenic will precipitate with ferric iron hydroxide. Glauconitic sediments have been found which contain up to 70 ppm of arsenic (Goldschmidt, 1958).

Subsurface oilfield brines may contain arsenic as HAs02 - or H2 As04, depending upon the Eh and pH. A low Eh may favor the HAs02- form.

Shales, sandstones, and carbonates contain about 13, 1, and 1 ppm, respectively, of arsenic (Mason, 1966). Sea water contains about 0.003 mg/l and subsurface oilfield brines contain from 0 to 10 mg/l. Compounds containing arsenic sometimes are used in corrosion inhibitors; therefore, information concerning well treatments should be obtained before assuming that any arsenic found occurs naturally.

Oxygen

Oxygen is the most abundant element in the earth’s crust, which contains about 49 wt.% of it (Fleischer, 1962). I t is capable of existing in many types of combinations, and even though it is highly active, it occurs extensively in

SULFUR 159

the free form. Most combined oxygen is ionic; however, it forms a covalent molecule with hydrogen, namely water. It also forms complex oxy-salts with various metals. The oxygen content of rocks decreases with depth.

The solubility of oxygen in water is primarily a function of temperature and pressure, and surface waters at ambient conditions may contain 7.63 mg/l a t 3OoC and 11.33 mg/l at 10°C (Hem, 1970). The amounts of dissolved oxygen in subsurface petroleum-associated waters is usually low, and in most in situ conditions it is undetectable because of the low redox potential of the environment. It can cause corrosion problems in the well pipes, but in most cases it is atmospheric oxygen that mixes with the produced brine during production operations that causes oxygen corrosion.

Sulfur

Sulfur is a member of the VI A group of elements and is widely dispersed in sedimentary and igneous rocks as metallic sulfides. The crust of the earth contains about 0.05 wt.% of sulfur (Fleischer, 1962). Free sulfur often is related to volcanic activity and can be deposited directly as a sublimate. Many commercial deposits, however, are associated with sedimentary gypsum, and probably result from biogenic activity such as that. of anaerobic bacteria. Large deposits of sulfur are found in caprocks of anhydrite overlying some salt domes.

Hydrogen sulfide, often found in oilfield waters, is formed by anaerobic bacteria. One such species of bacteria is the Desulphouibrio, which obtains its oxygen from sulfate ions, causing them to be reduced to hydrogen sulfide.

Sulfur in surface water usually occurs in the form (S6) complexed with oxygen as the sulfate anion S04-2. As previously mentioned, the conversion of oxidized sulfur to a reduced form commonly involves a biogenic process, and such a reduction may not occur unless these bacteria are present. The Eh of subsurface oilfield brines usually is somewhat reducing, and the sulfur species in such environments can include hydrogen sulfide (H2 S), sulfite

and thionates (S406-’). Detailed studies of the sulfur species in subsurface brines have not been made, and it is likely that other forms of sulfur are present in some brines. The temperature, pressure, Eh, pH, and other constituents in solution all influence the types of dissolved sulfur that occur in oilfield brines.

Shales, sandstones, and carbonates contain about 2,400, 240, and 1,200 ppm, respectively, of sulfur (Mason, 1966). Sea water contains 900 mg/l of sulfur as sulfate, and subsurface oilfield brines contain from none up to several thousand milligrams per liter. The amount of sulfate in the brine is influenced by bacterial activity and by how much calcium, strontium, and barium is present. If these three cations are present in relatively high concentrations, the amount of sulfate present will be low. However, some brines containing high concentrations of magnesium and low concentrations of the other alkaline earth metals may contain high concentrations of sulfate.


Selenium

Selenium is a member of the VI A group of elements and occurs in -2,0, +4, and +6 valence states, respectively. I t is a scarce element with an abundance of about 9 x 10" wt.% of the crust of the earth (Fleischer, 1962). Large areas of North America are underlain by seleniferous rocks and soils. These seleniferous rocks are of sedimentary origin and range in age from Late Paleozoic to Holocene. Selenium is the only known element that can be absorbed by plants in sufficient amounts to make them lethal when eaten by animals (Trelease, 1945). Fig. 5.15 illustrates the distribution of seleniferous vegetation.

Sandstones, shales, and carbonates contain about 0.6, 0.05, and 0.08 ppm, respectively, of selenium. Sea water contains about 0.004 mg/l of selenium. A few subsurface oilfield brines from areas where selenium is present in soils were analyzed at this laboratory, but no selenium was detected in the brines analyzed. Most brines are present in a petroleum environment under reducing conditions, and in such an environment, selenium likely is reduced to the element and precipitated. However, in areas where outcrop water flows through petroleum-bearing formations, it is possible that selenium in the form of t)e anion Se03-2 may be present.

1;

Fig. 5.15. Distribution of seleniferous vegetation in the United States.

FLUORINE 161

Fluorine

Fluorine is a member of the VII A group of elements and is the most electronegative of all the elements. Its ionic radius is 1.33 A, which is about the size of OH- and O-*; therefore, it enters a variety of minerals. The earth’s crust contains about 0.03 wt.% of fluorine (Fleischer, 1962). In solutions, fluorine usually forms the fluoride F- ion; at a low pH, the HFo form might occur. I t also can form strong complexes with aluminum, beryllium, and ferric iron.

Fluorine occurs in several minerals, but the only common industrial source is fluorspar (CaF2). I t occurs as HF or SiF in volcanic emanations, and even as the free element in (stinkfluss) “stinking fluorspar” of Wolssen- dorf, Bavaria. The solubility of calcium fluoride (fluorite) in water at 25OC is about 8.7 ppm of fluoride (Aumeras, 1927); this solubility could be affected by other dissolved constituents. Sodium fluoride is very soluble, and magnesium fluoride is more soluble than calcium fluoride; therefore, a petroleum- associated water that is deficient in calcium and has been in contact with rocks containing fluoride minerals will contain appreciable quantities of fluoride.

Shales, sandstones, and carbonates contain about 740, 270 and 330 ppm of fluorine, respectively (Mason, 1966). Sea water contains about 1.3 mg/l, and natural waters with a dissolved solids concentration of less than 1,000 mg/l usually contain less than 1 mg/l of fluoride. However, concentrations up to 50 mg/l have been reported (Hem, 1970). Not many subsurface petroleum-associated brines have been analyzed for fluoride, but a few are known t o contain up t o 5 mg/l.

Chlorine

Chlorine is a member of the VII A group of elements and is the most important member of the group with respect to water. The crust of the earth contains about 0.19 wt.% of chlorine (Fleischer, 1962); some estimates place the fluorine abundance above the chlorine abundance. Volcanic activity produces the gas hydrogen chloride and sometimes chlorine, but much less frequently. The caliche evaporite deposits in Chile contain the perchlorate ion C104-; however, the mechanism by which it formed is not clear. Several minerals contain the chloride ion.

The chloride ion does not form low-solubility salts. I t is not easily adsorbed on clays or other mineral surfaces. I t is not significant in oxidation and reduction reactions, and it forms no important solute complexes.

Chloride is very mobile in the hydrosphere, yet it is relatively scarce in the earth’s crust. It is the predominant anion in sea water and in most petroleum-associated waters. It is found in all natural waters, and its average concentration in rainwater is about 3 mg/l (Hem, 1970). Chloride salts are


very soluble; therefore, chloride is usually not removed from solution except during freezing or evaporation processes and in hyperfiltration, as water moves through some types of clay beds (White, 1965).

Shales, sandstones, and carbonates contain about 180, 10, and 150 ppm, respectively, of chloride. Sea water contains about 19,000 mg/l of chloride, the principal anion in the sea. The chloride content of the hydrosphere is much greater than can be accounted for by weathering of rocks, and it has been postulated that the primordial atmosphere may have been rich in chlorine compounds. The volcanic emission of chlorine gases appears a more plausible explanation, however.

Oilfield brines usually contain relatively high concentrations of chloride; in some brines the concentration may be 200,000 mg/l or more. Chloride usually is the predominant anion in oilfield brines. Table 5.1 illustrates how its concentration can increase in an evaporite-associated brine. Evaporation probably is the only geochemical process which appreciably affects the chloride content of the seas.

Bromine

Bromine is a member of the VII A group of elements and it behaves somewhat similarly to chlorine. The crust of the earth contains about 0.0005 wt.% of bromine (Fleischer, 1962). It usually occurs as the ion bromide Br-, and it does not form its own minerals when sea water evaporates (Valyashko, 1956). It forms an isomorphous admixture with chloride in the solid phases. The order of crystallization (see Table 5.1) is halite (NaCl), sylvite (KCl), carnallite (MgC12 -KC1*6H2 0), and/or kainite (MgS04 *KC1=3H2 0), and at the eutectic point, bischofite (MgCl? -6H2 0). Each of these chlorides entrains bromide in the solid phase. This distribution accounts for the relative enrichment of bromide in the liquid phase because with each crystallization more bromide is left in solution than is entrained in the solid phase.

Mun and Bazilevich (1962) reported that, in fresh-water lakes, bromide accumulates in the muds, that its concentration is proportional to the organic-matter concentration in the sediments, and that it is not influenced by the pelitic fraction. In muds of salt lakes, the higher the bromide concentrations in the brine, the higher it is in the muds. In general, the bromide content in the pore solutions increased with depth, but the bromide content in muds decreased with depth, owing to more complete decomposition of organic bromine compounds.

Bromide is two to three times more concentrated in carnallite than in sylvite and five to ten times more than in halite (Myagkov and Burmistrov, 1964). Apparently, concentration and dilution are responsible for the complex distribution of bromide in rocks of a carnallite zone. The determining factor in the replacement of chloride by bromide is the mineral composition rather than the bromide concentration in the brine.

BROMINE 163

Braitsch and Herrmann (1963) found that the absolute bromide content of rocks can be used to determine primary and secondary paragenesis. Distribu- tion of bromide between solution and crystals of halite, sylvite, carnallite, and bischofite, and the effects of other ions plus temperatures between 25" and 83OC, confirm this. This method was also applied to determine the temperature of primary potash deposits. An investigation of the bromide/ sodium chloride relation in salt deposits revealed that bromide can be used to determine the stratigraphy of evaporite-salt deposits (Baar, 1963).

Derivation of theoretical profiles of bromide thickness versus salt thickness indicated that, with constant inflow, evaporation, and reflux, the thickness profiles were all monotomic logarithmic functions. The irregular and high bromide concentrations of some salt deposits were attributed to inflow of bromide-rich bitterns from an adjacent potash basin (Holser, 1966).

Shales, sandstones, and carbonates contain about 4, 1, and 6 ppm, respectively, of bromide (Mason, 1966). Sea water contains about 65 mg/l of bromide, and subsurface petroleum-associated brines contain from less than 50 to more than 6,000 mg/l of bromide. Fig . 5.16 illustrates the bromide concentration plotted versus the chloride concentration for some subsurface brines taken from Tertiary, Cretaceous, and Jurassic age sediments. This plot indicates that the waters from these Tertiary age sediments are depleted in bromide relative to a normal evaporite brine, whereas those from the Cretaceous and Jurassic age sediments are enriched'in bromide.

C

BROMIDE, mg / I

Fig. 5.16. Comparison of the bromide concentrations in some formation waters from Tertiary (T), Cretaceous (C), and Jurassic (J) age sediments from Louisiana with an evaporating sea water.



P M

PI I 300 1,000 3000 10

BROMIDE, mgl l

Fig. 5.17. Comparison of the bromide concentrations in some formation waters from Pennsylvanian (P) and Mississippian (M) age sediments from Oklahoma with an evaporating sea water.

Fig. 5.17 is a similar plot for some brines taken from some Pennsylvanian and Mississippian age sediments. The bromide concentrations in these brines do not appear to be significantly different.

Brines containing 1,500 to 8,000 mg/l of bromide, with calcium and magnesium chloride as the major constituents, are formed by evaporation of sea water and associated sedimentation rather than by dissolution of salts. Increase in temperature causes a phase shift in the solid and brine phases, resulting in an increase of bromide in solution.

Iodine

Iodine is a member of the VII A group of elements, and of the four members discussed in this chapter, it is the least abundant, since it comprises only about 3 x lo-' wt.% of the earth's crust (Fleischer, 1962). I t forms three minerals of its own; namely, iodoargyrite (AgI), iodoembolite [Ag(Cl,Br,I)], and miersite [(Ag,Cu)I]. Marine plants, such as kelp and plankton algae, concentrate iodine.

The distribution of iodide in marine and oceanic silts and interstitial waters indicates that near-shore ocean Sediments contain more iodide than deep-sea sediments. Red clays and calcareous sediments contain less iodide than organic-bearing argillaceous sediments. The iodide concentration in the marine and oceanic sediments decreases with depth, but the iodide concen-

IODINE 165

tration in the interstitial waters increases with depth (Shishkina and Pavolva, 1965).

The iodide in bottom water layers and in the interstitial water of muds in some Japanese lakes was found to be selectively captured by flocculated iron, manganese, and aluminum hydroxides which sank to anaerobic layers (Sugawara et al., 1956). Reduction of the hydroxides releases iodide to the bottom waters. However, the release of iodide is incomplete, and the flocculates reach the bottom muds where the Eh is even more negative, resulting in high accumulation of iodide in interstitial water of muds.

The primary source of organic matter in marine and oceanic basins is photosynthesis by plankton algae. Algae are directly or indirectly the food resource of all the remaining life in the basins, and the proliferation rate differential and the types of feeding organisms influence the sediment deposition rate as well as the amount of iodide and bromide in the sediment (Bordovskii, 1965).

Shales, sandstones, and carbonates contain about 2.2, 1.7, and 1.2 ppm, respectively, of iodide (Mason, 1966). Sea water contains about 0.05 mg/l, and most subsurface petroleum-associated brines contain less than 10 mg/l; however, some have been found to contain up to 1,400 mg/l.

Fig. 5.18 is a plot of the chloride concentrations versus the iodide concentrations for some brines taken from some Pennsylvanian and Mississippian age sediments. Iodide is tremendously enriched in all of these brines compared to the normal evaporite-associated brine. Some mechanisms such as leaching or solubilization of iodine, iodate, or iodide compounds, ion filtration, anion exchange, and desorption had to occur, to account for this enrichment of iodide in the aqueous phase. A similar plot for some waters taken from Tertiary, Cretaceous, and Jurassic age sediments gave similar results except that these particular brines were not as heavily enriched in iodide.

The iodide concentration of some subsurface waters is dependent on the proximity of argillaceous deposits containing organic matter, rather than on dissolved mineralization. Gas may play an important part in the accumulation of iodide in subsurface waters. Some gas structures are bounded by iodide-rich waters, and the iodide content is depleted at a distance from the gas structure (Ovchinnikov, 1960).

Studies of some reservoirs, Holocene to Miocene in age, in lagoonal sedimentary basins of thick sediments with wide areal extent, indicate that a genetic relation exists between iodide in the formation waters and the accompanying natural gas (Marsden and Kawai, 1965). Possibly the high concentrations of iodide are the result of concentration by algae and other marine organisms from ancient sea waters; their remains became part of the sediments, and later the iodide was solubilized. However, because the iodide usually is strongly incorporated in the sediment, such sediments must contain large quantities of iodide, and other mechanisms must operate to solu- b i k e the iodide in associated waters.


1 , 5 0 0 3

/ / /1

, /-

/

/ ~ w m i evaporite CUM , ' 1,200

I#OOO

cn 500 w'

- \

2 200 s O t I l o o t vs

20 50E M M F P

M P P

MM

M

MhP

IODIDE, mg/l

Fig. 5.18. Comparison of the iodide concentrations of some formation waters from Pennsylvanian (P) and Mississippian (M) age sediments from Oklahoma with an evaporating sea water.

Theoretically, only iodate is thermodynamically stable in sea water (SillCn, 1961). The exact form of iodine in oilfield brines has not been investigated. These forms probably will vary with the salinity, Eh, and other factors. Sugawara and Terada (1957) established that both iodide and iodate are present in comparable amounts in sea water. Biologists found that iodine-concentrating algae ultilize only the iodate form (Shaw, 1962).

Significance of some physical properties

Redox potential

The redox potential often is abbreviated as Eh, and may also be referred to as oxidation potential, oxidation-reduction potential, or pE. It is expressed in volts, and at equilibrium it is related to the proportions of oxidized and reduced species present. Standard equations of chemical thermodynamics express the relationships.

Eo is the standard potential of a redox system when unit activities of participating substances are present under standard conditions. Eo is related to standard free energy change in a reaction by the equation:

where n is the number of unit negative charges (electrons) shown in the

PHYSICAL PROPERTIES 167

redox reaction and f is the Faraday constant in units that give a potential in volts (94,484 absolute coulombs). Standard free energy values are given in texts such as that of Latimer (1952).

When the system is not under standard conditions, the redox potential is expressed by the Nernst equation:

R T (oxidized species) n f (reduced species) Eh = Eo + - log

where R is the gas content (1.987 cal. degree mole), and T is the temperature in degrees Kelvin. Geochemical literature and biochemical literature, such as that of Pourbaix (1950), present increasing positive potential values to represent increasing oxidizing systems and decreasing potential values to represent reducing systems. The sign of Eh used in this manner is opposite to standard American practice in electrochemistry.

Zobell (1946) established basic procedures for measuring the Eh of geologic-related materials. The Zobell solution containing 0.003M potassium ferrocyanide and 0.003M potassium ferricyanide in a 0.1M potassium chloride solution has an Eh of 0.428 V at 25OC. Minor temperature variations can be calculated using the equation:

Eh = 0.428+).0022 ( t - 25)

where t = temperature of the sample in degrees Celsius. Garrels and Christ (1965) describe procedures for determining Eh

equilibria of mineral substances. Particularly useful are the procedures described for constructing diagrams showing fields of stability for various mineral substances as functions of pH and Eh. Fig. 5.19 is an Eh/pH diagram. Such stability field diagrams might be constructed for the substances comprising petroleum and should be of considerable help in understanding the mechanisms of origin, accumulation, and chemical stability of petroleum. Unfortunately, this approach does not yield simple results because most oxidation reactions involving hydrocarbons and other petroleum constituents are not reversible in the usual sense. Furthermore, thermodynamic data are available for only a small fraction of the large number of reactions and products that are possible.

Attempts to obtain useful results from Eh measurements in natural media involve numerous difficulties. In a natural medium, such as petroleum- associated water, there are many variables, none of which is controlled, which individually or collectively may have little or great influence on Eh measurements made on the water. Many chemical substances, such as ferric or ferrous ions, various organic oxidation-reduction systems, sulfides, and sulfates, may be present in the water in large or small amounts. Even controlled systems in the laboratory often produce unaccounted-for variances. In the field, the lack of knowledge of actual participating species may seriously impair proper interpretation of Eh readings. Eh measurements made

168

< 400- z W

200

INORGANIC CONSTITUENTS AND PHYSICAL PROPERTIES

I /Modern sea water

I

I - Acid I Alkaline

Fa++

1,200 - H2O

000 - I

600 1

on poorly poised media (media with poor Eh stability), such as some oilfield waters, involve additional uncertainties. Response of electrodes in such solutions is sluggish, and electrodes are easily contaminated with trace amounts of substances which will produce invalid readings.

In the natural environment, reactions occur that involve protons and electrons, such as:

FeS04 + 2H2 0 * S04-2 + FeO-OH + 3H+ + e-

Such reactions depend upon both the pH and the Eh of the system, and the equilibrium line of such reactions is Eh = E o - 59 a/n pH mV, where a is the number of protons.

Knowledge of the redox potential is useful in studies of how compounds such as uranium (Naumor, 1959), iron, sulfur (Hem, 1960), and other minerals (Cloke, 1966; Pirson, 1968) are transported in aqueous systems. The solubility of some elements and compounds is dependent upon the redox potential and the pH of their environment. The Eh/pH diagram shown in


Fig. 5.19 can be used to predict that ferrous ions are the more common form of dissolved iron and that ferric ions will precipitate in an oxidizing environment if the pH is above 1. Similar diagrams can be drawn for other constituents.

Some water associated with petroleum is “connate” water, and Fig. 5.19 indicates that such water has a negative Eh; this has been proven in various field studies (Buckley et al., 1958). The Eh of some petroleum-associated waters in the Anadarko Basin ranged from -270 mV to -300 mV (Collins, 1969a).

Knowledge of the Eh is useful in determining how to treat a water before it is injected into a subsurface formation (Ostroff, 1965). For example, the Eh of the water will be oxidizing if the water is open to the atmosphere, but if it is kept in a closed system in an oil-production operation, the Eh should not change appreciably as it is brought to the surface and then reinjected. In such a situation, the Eh value is useful in determining how much iron will stay in solution and not deposit in the well bore.

Organisms that consume oxygen cause a lowering of the redox potential. In buried sediments, it is the aerobic bacteria that attract organic constituents which remove the free oxygen from the interstitial water. Sedi- ments laid down in a shoreline environment will differ in degree of oxidation as compared to those laid down in a deep-sea environment (Pirson, 1968). For example, the Eh of the shoreline sediments may range from -50 to 0 mV, but the Eh of deep-sea sediments may range from -150 to -100 mV.

The aerobic bacteria die when the free oxygen is totally consumed; the anaerobic bacteria attack the sulfate ion, which is the second most important anion in the sea water. During this attack, the sulfate reduces to sulfite and then to sulfide; the Eh drops to -600 mV; H2S is liberated, and CaC03 precipitates as the pH rises above 8.5 (Dapples, 1959).

The term pH means the logarithm (base 10) of the reciprocal of the hydrogen-ion concentration, and the pH of pure water at 25OC is 7.0, which means that there is lo-’ ‘mole per liter of H+ in solution. When other constituents are solubilized by water, the pH probably will change because the chemical equilibrium shifts as new ions combine with H+ or OH-. The presence of slightly dissociated acids or bases will tend to buffer the solution, and the addition of H+ or OH- will shift the pH only a small amount until the acids or bases are changed to salts.

The pH of oilfield waters usually is controlled by the carbon dioxide- bicarbonate system. Because the solubility of carbon dioxide is directly proportional to temperature and pressure, the pH measurement should be made in the field if a close-to-natural-conditions value is desired. The pH of the water is not used for water identification or correlation purposes, but it will indicate possible scale-forming or corrosion tendencies of a water. The

170 INORGANIC CONSTITUENTS A N D PHYSICAL PROPERTIES

pH also may indicate the presence of drilling-mud filtrate or well-treatment chemicals.

A detailed study indicates that virtually no environment exists on or near the earth’s surface where the pH/Eh conditions are incompatible with organic life (Baas Becking et al., 1960). Because COz is the main byproduct of organic oxidation and the building material of plant and much bacterial life, it must be expected to play a dominant role. It dissolves in HzO, producing the bicarbonate ion and a free hydrogen ion. The concentration of the hydrogen ion is 1 x moles per liter (pH 7) at 25OC in pure water, but when saturated with COz, it rises to 1 x lo-’ moles per liter (pH 5). The equilibrium conditions of carbon dioxide, carbonic acid, and the bicarbonate ion are:

Hz 0 + COz * Hz CO, * HC03- + H+ * 2H+ + C03-’

and the pH of each equilibrium in ocean water is pH 5, pH 6.3, and pH 10.3. This reaction moves to the right with increasing temperature in a closed system. In the presence of organic constituents, the equilibria are modified, and the pH range can extend from 2 to 12.

Fig. 5.20. Changes in pH as a result of the addition of carbonate ions to distilled water and water solutions containing sodium and chloride ions.

The pH of concentrated brines usually is less than 7.0, and the pH will rise during laboratory storage, indicating that the pH of the water in the reservoir probably is appreciably lower than many published values. Addition of the carbonate ion to sodium chloride solutions will raise the pH, as illustrated in Fig. 5.20. If calcium were present, calcium carbonate would precipitate. The reason why the pH of most oilfield waters rises during storage in the laboratory is because of the formation of carbonate ions as a result of bicarbonate decomposition.


Ionic radii

Table 5.VI contains data concerning the radii of the nonhydrated ions, the hydrated ions, the ionic potential, and the polarization. The size of the ions is of interest concerning the mobilities or the relative transport coefficient of a given ion through a clayshale membrane system or the replacement coefficient in a clay ion-exchange system. The ionic potential is of interest because elements with low ionic potentials are the most likely to remain in true solution. The polarization, which is equivalent to the valency divided by the ion radius, is of interest because the larger the polarization, the lower the replacing power in an exchange system (Collins, 1970).

The ionic potentials of the constituents involved in the diagenesis are important (Hem, 1960). Those that stay in true ionic solution to rather high pH levels include Na+, K+, Mg+’, Fe+’, Mn+’, Ca+’, Sr+*, and Ba+’ ; they are the soluble cations, and their ionic potentials range from 0.3 to 1.3, where the ionic potential is the ratio between the ionic charge and the ionic radius. Constituents that are precipitated by hydrolysis are those with ionic potentials of 3-12 and include such ions as A P 3 , Fe+3, SP4 , and M r P 4 . Constituents which form soluble complex ions and usually go into true ionic solution include B+3, C4, N + 5 , P+’, S 6 , and Mn+’ ; their ionic potentials are over 12. In general, the hydroxides of the soluble cations possess ionic bonds; therefore, they are soluble. The hydrolysates, or those ions precipitated by hydrolysis from hydroxyl bonds, and the soluble complex ions both have hydrogen bonds.

TABLE 5.VI

Radii, valence, ionic potentials, and polarization

Constituents Nonhydrated Valence Hydrated Ionic Polarization radius (A) radius (A) potential

Lithium Sodium Potassium Calcium Magnesium Strontium Barium Boron Chloride Bromide Iodide Sulfate

0.60 0.95 1.33 0.99 0.65 1.13 1.35 0.23 1.81 1.95 2.16 2.90

+1 +1 +1 +2 +2 +2 +2 +3 -1 -1 -1 -2

3.82 3.58 3.31 4.12 4.28 4.12 4.04

3.32 3.30 3.31 3.79

-

0.60 0.95 1.33 0.50 0.33 0.57 0.68 0.08 1.81 1.95 2.16 1.45

1.67 1.05 .75 2.02 3.08 1.77 1.48

0.55 0.51 0.46 0.69

-


Density

Equations that were developed for sea water can be applied to oilfield waters to obtain approximate values for engineering studies. The density values (ao) at O°C and atmospheric pressure are related to the chlorinity (CZ) as follows:

-0.069 + 1.4708 CZ - 0.00157 C12 + 0.0000398 C13 = UO

where CZ = chlorinity (see Table 3.111). The density is very dependent upon temperature:

where D = a complex function of ao, and temperature and D values can be obtained from Knudsen’s Hydrographic Tables (Knudsen, 1901).

Vapor pressure

The relative lowering of the vapor pressure of oilfield water can be calculated with the following equation:

Ap/po = 0.538 x S

where p o = the vapor pressure of distilled water at the same temperature, and S = the salinity (see Table 3.111) (Kellog and Company, 1956, 1966, 1968).

Boiling point

A first approximation of the boiling point elevation can be calculated from:

At = 0.0158 S

where S = the salinity.

Freezing point

An empirical equation which can be used to estimate the freezing points is :

t = 4.0086 - 0.064633 ((TO) - 0.0001055 ( 0 0 ) ~

See “Density” for an explanation of terms.


Viscosity

The viscosity will increase with decreasing temperature and with increasing salinity. The viscosities of sodium chloride solutions of the same ionic strength can be used to estimate oilfield water vicosities.

Osmotic pressure

A relationship between osmotic pressure ( P o ) and the depression of the freezing point at 0°C is (in atmospheres):

The osmotic pressure at other temperatures can be estimated (Kellog and Company, 1956,1966,1968):

Po x (1 + 0.00367t)

Specific heat

The values for the specific heat, cp , of oilfield waters can be approxi- mated from the values of an equivalent sodium chloride solution.

Thermal conductivity

The thermal conductivity coefficient, A, can be calculated from thermal capacities because the ratio of thermal conductivities of two materials is the same as that of the thermal capacities of equal volumes. The values for X at various temperatures are available in a “Saline Water Conversion Technical Data Book” (Kellog and Company, 1956,1966,1968).

Surface tension

The surface tension of an oilfield water increases with decreasing temperature and with increasing salinity. An empirical formula which can be used to calculate it is:

75.64 - 0.144t + 0.0399 Cl = surface tension (dynes/cm*)

where t = temperature in Celcius, and CZ = the chlorinity (see Table 3.111; Kellog and Company, 1956,1966,1968).


References

Ahrens, L.H., 1965. Distribution of the Elements in Our Planet. McGraw-Hill, New York, N.Y., 110 pp.

Aumeras, M., 1927. Studies of ionic equilibria, 11. Equilibrium of calcium fluoride in dilute hydrochloric. J. Chem. Phys., 24:548-571.

Baar, C.A., 1963. How to use the bromine test to determine the stratigraphical position in rock salt series. Neues Jahrb. Mineral. Geol. Palaontol., Monatsh., 7( 1): 145-153.

Baas Becking, L.G.M., Kaplan, I.R. and Moore, D., 1960. Limits of the natural environment in terms of pH and oxidation-reduction potentials. J. Geol., 68:243-284.

Bordovskii, O.K., 1965. Source of organic matter in marine basins. Mar. Geol. , 3( 1/2):5-31.

Braitsch, 0. and Herrmann, A.G., 1963. Zur Geochemie des Broms in Salinaren Sedi- menten, Teil I. Experimentelle Bestimmung der Br-Verteilung in verschiedenen naturlichen Salzsystemen. Geochim. Cosmochim. Acta, 27 :361-391.

Brasted, R.C., 1957. The halogens. In: M.C. Sneed, J.L. Lewis and R.C. Brasted (Editors), Comprehensive Inorganic Chemistry, 3. Van Nostrand, New York, N.Y., 250 pp.

Buckley, S.E., Hocott, C.R. and Taggart, Jr., M.S., 1958. Distribution of dissolved hydrocarbons in subsurface waters. In: L.G. Weeks (Editor), Habitat of Oil. American Association of Petroleum Geologists, Tulsa, Okla., pp.850-882.

Burst, J.F., 1969. Diagenesis of Gulf Coast clayey sediments and its possible relation to petroleum migration. Bull. Am. Assoc. Pet. Geol., 53:73-93.

Cloke, P.L., 1966. The geochemical application of Eh-pH diagrams. J. Geolog. Ed. , 14: 140-1 48.

Collins, A.G., 1969a. Chemistry of some Anadarko Basin brines containing high concentrations of iodide. Chem. Geol. , 4:169-187.

Collins, A.G., 1969b. Solubilities of some silicate minerals in saline waters. U.S. Off. Saline Water Res. Dev. Progr. Rep. , No. 472, 27 pp.

Collins, A.G., 1970. Geochemistry of some petroleum-associated waters from Louisiana. US. Bur. Min. Rep. Invest., No.7326, 31 pp.

Collins, A.G., Castagno, J.L. and Marcy, V.M., 1969. Potentiometric determination of ammonium nitrogen in oilfield brines. Environ. Sci. Technol., 3:274-275.

Dall’Aglio, M., 1968. The abundance of mercury in 300 natural water samples from Tuscany and Latium (Central Italy). In: L.H. Ahrens (Editor), Origin and Distribution o f the Elements. Pergamon Press, Oxford, p.1065-1081.

Dapples, E.C., 1959. The behavior of silica in diagenesis. In: H.A. Ireland (Editor), Silica in Sediments - SOC. Econ. Paleontol. Mineral., Spec. Publ., No.7, pp.36-55.

Davis, J.W. and Collins, A.G., 1971. Solubility of barium and strontium sulfates in strong electrolyte solutions. Environ. Sci. Technol., 5:1039-1043.

Fleischer, M., 1962. Recent estimates of the abundances of the elements in the earth’s crust. U.S. Geol. Surv. Circ., No.285, 9 pp.

Garrels, R.M. and Christ, C.L., 1965. Solutions, Minerals, and Equilibria. Harper and Row, New York, N.Y., 450 pp.

Goldberg, E.D., 1963. The oceans as a chemical system. In: M.N. Hill (Editor), Composi- tion of Sea Water: Compamtive and Descriptive Oceanography. Interscience, New York, N.Y., 2:3-25.

Goldschmidt, V.M., 1958. Geochemistry. Oxford University Press, London, 730 pp. Hem, J.D., 1960. Some chemical relationships among sulfur species and dissolved iron :

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Karasik, M.A., Goncharov, Yu. and Vasilevskaya, A.Ye., 1965. Mercury in waters and brines of the Permian salt deposits of Donbas. Geochem. Int. , 2:82-87.

Kazmina, T.I., 1951. The boron-chloride coefficient in oilfield waters. Dokl. Akad. Nauk S.S.S. R . , 77 :301.

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Chapter 6. ORGANIC CONSTITUENTS IN SALINE WATERS

Water is a peculiar solvent and has been considered to possess at ambient temperature a quasi-crystalline, open structure which will allow solute molecules to fill the space between the lattice points (Eley, 1939). As a nonpolar molecule dissolves in water at ambient temperature, the structure of the water in its immediate vicinity becomes more crystalline, or a microscopic “iceberg” surrounds the solute (Frank and Evans, 1945). Water also has been considered to be an equilibrium mixture of an icelike and a close-packed structure, and with a molecule of gas as a solute, it reacts with the icelike structure filling one of the cavities to form a gas-hydrate and shifting the equilibrium from the close-packed structure to the icelike structure (Namoit, 1961).

Another theory is that water is composed of clusters of highly hydrogen- bonded molecules which are surrounded by a closely packed structure of monomeric water. These flickering clusters form and dissolve perpetually as a result of local energy fluctuations. Therefore, a water molecule can have a solute molecule as a neighbor along with its four H-bonded water neighbors. Interactions between the solute and water molecules will depress the energy level of the tetrabonded water molecule. However, large numbers of water molecules surround an unbonded molecule, and if it acquires a solute neighbor after the latter replaces a water molecule, the energy level is raised. Changes in the energy levels cause a shift of water molecules between various levels in accordance with the Boltzmann distribution law, giving an increase in the “icelikeness” and an increase in the clusters of water molecules near the surface of the solute molecule (Nemethy and Scheraga, 1962).

When a hydrocarbon molecule transfers from the pure liquid to the solution hydrocarbon-water, interactions are established while hydrocarbon- hydrocarbon interactions are broken. The amount, kind, and state (suspended, dissolved, or colloidal) of organic matter in petroleum-associated waters is important in determining the origin and migration of petroleum, and in problems concerning pollution of fresh waters by petroleum- associated waters. Probably the most plausible theory concerning the origin of petroleum is that it originated from organic constituents which are recognized as remnants or degradation products of living organisms of past ages; these organic source materials entered fine-grained aquatic sediments where biochemical and chemical conversions and fractionations occurred (Erdman, 1965). As increased sedimentation took place, the resulting overburden pressure and compaction caused the interstitial water, which con-

178 ORGANIC CONSTITUENTS IN SALINE WATERS

tained minute quantities of hydrocarbon, to be squeezed out of the con- solidating sediments, and subsequently the oil was accumulated in sands and left behind in structural traps (Kidwell and Hunt, 1958). Obviously, the waters associated with petroleum play a very important part in the origin, migration, accumulation, and subsequent production of petroleum - the accumulation and production of petroleum being totally dependent upon hydraulic flow in response to geostatic and hydrostatic pressures.

Consider briefly that 99% of the oil found and produced typically occurs within the pore spaces of sedimentary rocks (Hedberg, 1964). About 59% of the production comes from sandstone reservoirs, 40% from carbonates, and 1% from other types of rock. Petroleum in igneous and metamorphic rocks occurs primarily in fracture pore spaces and probably has migrated to these rocks from its place of origin.

The solubilities of petroleum hydrocarbons in water increase with temperature and decrease as the salinity of the water increases. A temperature drop from 150” to 25°C reduces the solubility of petroleum in water by a factor of 4.5-20.5. Such a mechanism can account for the accumulation of petroleum because as upward moving subsurface waters containing dissolved hydrocarbons decrease in temperature and pressure and meet more saline waters, they will release dissolved hydrocarbons (Price, 1973).

Information concerning dissolved organic matter in sea water was published as early as 1892 (Duursma, 1965). Palmitic acid, stearic acid, acrolein, and organic nitrogen were tentatively identified. The dissolved organic matter was found to be about 2 mg/l in the open sea, increasing to about 15 mg/l in water taken near the coast of Greece, all of which was attributed to saponification of the fats of dead organic organisms. Phyto- plankton organisms comprise most living marine organic matter, 10% of which eventually becomes animal matter. The bulk of the organic particulate matter in the sea results from dead animal matter, but the dissolved organic constituents appear to be derived from dead phytoplankton and detritus rather than excretions from living cells.

Decomposition of organic matter results primarily from the activities of heterotrophic bacteria. Organic matter decomposes more rapidly in a near- shore environment, where there is an abundance of such matter and bacteria, than in a deep-sea environment, where both the matter and bacteria are diluted. The dissolved organic matter can be classified into groups as follows: (1) nitrogen-free (for example, carbohydrates); (2) nitrogen-containing (for example, proteins); (3) lipids (for example, esters of fatty acids); and (4) complexes comprised of mixtures of the preceding three groups (for example, humic acids).

Nitrogen-free organic compounds

Many petroleum-associated waters contain methane; however, in Japan, there is a type of natural-gas deposit called “suiy6sei-tenynengasuy’, a dry gas,

NITROGEN-FREE ORGANIC COMPOUNDS 179

which is found dissolved in subsurface brines (Marsden and Kawai, 1965). The major reservoirs in which it is found are marine or lagoonal sedimentary basins with thick sediments and of wide areal extent. Some of the associated brines contain more than 80 mg/l of iodide, which is the only commercial source of iodine in Japan. Some of these brines also contain dissolved ethane, propane, isobutane, butane, isopentane, and pentane.

An interesting note is that large Soviet deposits of natural gas in a solid state totaling about 15 trillion m3 were reported to the U.S.S.R. Committee for Inventions and Discoveries. According to U.S.S.R. investigators, molecules of ground water attract molecules of natural gas and convert them to a hydrate, which resembles silvery-grey ice, where the pressure is 250 atm and the temperature 25°C or less. 1 m3 of the hydrate contains up to 200 m3 of natural gas. These solid hydrate deposits are found in permafrost zones at depths to 2,500 m. Because of the high electrical resistance, they are discoverable by geophysical methods. The hydrate can be converted to gas by sinking a well and reducing the pressure and/or pumping a catalyst such as methyl alcohol into it (Anonymous, 1970).

The solubility of the hydrocarbons benzene, toluene, o-xylene, rn-xylene, p-xylene, naphthalene, biphenyl, diphenylmethane, and phenanthrene was found to increase with increasing silver-ion concentration, indicating that a slightly soluble 1-1 complex formed (Andrews and Keefer, 1949). Evidence was obtained that two water-soluble complexes formed with silver and each aromatic hydrocarbon tested. Potassium nitrate causes a reduction in the solubility of aromatics in aqueous solutions (salting-out effect), but silver nitrate increases the solubility of toluene about 73% compared to its solubility in pure water. Apparently this effect with silver ions results from the formation of n-complexes between the benzene ring and the cation.

Benzene hydrocarbons exhibit a minimum solubility in water near 18°C which corresponds to a zero heat of solution. The actual volume occupied by a hydrocarbon with one benzene ring in water solution apparently influences its degree of solubility, and the larger the molecule the less soluble it is in water (Bohon and Claussen, 1951). However, naphthalene and biphenyl, which are larger in size and are multiring compounds, were 7 to 10 times more soluble, indicating that some property of the benzene ring may influence the solubility. I t was postulated that a positive heat of solution resulted in the heat of cavity formation, while a negative heat of solution resulted from the formation of icelike structures around the dissolved hydrocarbons and/or a n-electron complex of the aromatic nucleus where the n-electrons functioned as a base and the water as an acid. The heat of cavitation would predominate above 18°C and would cancel the negative heat reaction at 18°C , and below 18°C the negative heat would be larger.

A study of the effect that the salts sodium fluoride, sodium chloride, lithium chloride, ammonium chloride, sodium iodide, cesium chloride, tetramethylammonium bromide, etc., have upon the activity coefficient of benzene in aqueous solutions indicates that the salting-out effect varies con-


siderably among the electrolytes (McDevit and Long, 1952). A limiting law for determining the influence of electrolytes on the activity of nonpolar solutes was developed, which related the magnitude of the salt effect to the volume changes associated with salt and water mixing.

Molecular hydrogen was found in oilfield waters in the Lower Volga region (Zinger, 1962). Up to 43% of the dissolved gas in these waters was hydrogen; other gases dissolved in the waters were methane, ethane, butane, pentane, carbon dioxide, nitrogen, helium, and argon. The pH of these waters was as low as 3.4, and the iron content was as high as 1,100 ppm.

The solubility of methane increases with pressure and decreases with increased salt concentration at ambient temperature in NaC1-H2 0 and CaC12-H20 systems (Duffy et al., 1961). From the experimental data, it was estimated that 1 cubic foot of sedimentary rock with 20% porosity buried 300 m deep and saturated with a brine containing 50,000 ppm of NaCl could accommodate 0.3 mole of methane in solution.

A gas-liquid partition chromatographic technique was used to determine the solubilities of C1 -C9 paraffin and branched-chain paraffins, four cycloparaffins, and five aromatic hydrocarbons in water (McAuliffe, 1963). Later this study was extended to seventeen paraffins, seventeen olefins, nine acetylenes, seven cycloparaffins, seven cycloolefins, and six aromatic hydrocarbons (McAuliffe, 1966). The data indicated that the solubilities of the hydrocarbons in water increased as unsaturate bonds were added to the molecule, with ring closure, with addition of unsaturate bonds in the ring, and with addition of bonds which decreased the hydrocarbon molar volume. Branching increased the solubility in water for paraffin, olefin, and acetylene hydrocarbons but not for the cycloparaffin, cycloolefin, and aromatic hydrocarbons. Plots of the log of the solubility in water were a linear function of hydrocarbon molar volume for each homologous series of hydrocarbons.

A capillary-cell method was used to measure the diffusion of methane, ethane, propane, and n-butane in water (Witherspoon and Saraf, 1964). At 25OC, the results indicated that the diffusion coefficients times los cm2/sec were 1.88, 1.52, 1.21, and 0.96, respectively, for methane, ethane, propane, and n-butane. The coefficients increased with higher temperatures.

Near the critical solution temperature and about 300 atm, the solubility versus pressure curves for some hydrocarbon-water systems show a sharp maximum. However, pressure has a negative effect on solubility beyond this maximum, and a second two-phase region appears. The five binary hydrocarbon-water systems studied were benzene, n-heptane, n-pentane, 2-methyl-pentane, and toluene (Connolly, 1967).

The accommodation of CI2-C& n-alkanes in distilled water was determined as a function of hydrocarbon supply, settling time, filtration pore- size, and mode of introduction (Peake and Hodgson, 1967). Apparently it is possible to accommodate hydrocarbons in water at levels higher than solubil-

NITROGEN-FREE ORGANIC COMPOUNDS 181

ity levels, and such accommodation systems are stable for several days. Preferential accommodation of alkanes in the C16-C20 range was found at the expense of other 'alkanes with lower and higher carbon numbers.

A gas chromatographic method for the determination of petrol in water was developed whereby the petrol was extracted from the water into nitrobenzene and the extract was analyzed using a column polyethylene glycol 1,500 on silanized Chromosorb W (Jeltes-and Veldink, 1967). The methods were sensitive to 0.1 mg/l, and for concentrations > 0.5 mg/l the precision was about 5% for the major components.

Low-molecular-weight hydrocarbons in the C1 -C4 range were detected in sea water. Generally the concentration tended to decrease with depth (Swinnerton and Linnenbom, 1967). Methane was the most abundant hydrocarbon found, but smaller amounts of ethane, ethylene, propane, propylene, n-butane, isobutane, and some butenes also were detected and measured.

Hundreds of drill-stem samples of brine from water-bearing subsurface formations in the Gulf coastal area of the United States were analyzed to determine their amounts and kinds of hydrocarbons (Buckley et al., 1958). The chief constituent of the dissolved gases usually was methane, with mea- surable amounts of ethane, propane, and butane present. The concentration of the dissolved hydrocarbons generally increased with depth in a given formation and also increased basinward with regional and local variations. In close proximity to some oilfields, the waters were enriched in dissolved hydrocarbons, and up to 14 standard cubic feet of dissolved gas per barrel of water was observed in some locations.

The ratio of toluene to benzene in 27 crude oils from various sources ranged from 2.0 t o 11.3. Toluene is less soluble than benzene in distilled water, where the ratio is about 0.3 (McAuliffe, 1966). A method of prospecting for petroleum, utilizing information concerning the amount of benzene dissolved in subsurface waters, was patented (Coggeshall and Hanson, 1956). Gas chromatographic methods proved to be good for determining the amount of benzene and other hydrocarbons in the petroleum- associated waters (Zarrella et al., 1967). Collected information indicates that the concentration of benzene in petroleum-associated water varies with different types of hydrocarbon accumulations, that the benzene concentration decreases with increasing distance from the hydrocarbon accumulation, and that benzene is specific for detecting the occurrence of petroleum hydrocarbon accumulation in a given geologic horizon. A brine sample taken from a horizon separated by 27 m of shale from an oil pool contained 0.02 ppm of benzene, indicating that low-permeability shale prevents movement of hydrocarbons.

Chromatographic techniques were developed for the determination of sugars and phenols in sea waters and in sediments (Degens and Reuter, 1964). Biogeochemical differences were observed between the sugars in the sea and in the sediments.


Wilson e t al. (1970) found that ethylene, propylene, and carbon monoxide are produced in illuminated sea water to which dissolved phytoplankton was added. Higher saturated gaseous hydrocarbons and methane were not produced.

Bonoli and Witherspoon (1968) measured the diffusion coefficients of methane, ethane, propane, n-butane, n-pentane, benzene, toluene, ethyl- benzene, cyclopentane, methylcyclopentane, and cyclohexane in pure water at temperatures ranging from 2" to 60°C using the capillary-cell method. The effect of sodium chloride was studied, and the largest decrease in diffusion coefficients was found for the paraffin hydrocarbons. They attributed the decrease to the effects of ions in water acting as structure breakers as well as obstacles to diffusion because of obstructions and hydrations.

Hydrocarbons containing nitrogen

Chromatographic techniques were developed for determining humic acids, amino acids, and indoles in saline waters and in sediments (Degens and Reuter, 1964). Arginine was found in the particulate matter in sea water and decreased in concentration with depth. Relatively abundant concentrations of ornithine, serine, and glycine were found in sea water.

The total concentrations of amino acids found in some petroleum- associated waters ranged from 20 to 230 pg/l (Degens et al., 1964). In general, the amino acid content increased with salinity. Adjustment of the salinity of the brines to that of modern sea water indicated a similarity between the amino acid spectra in the two. High concentrations of serine and the presence of threonine and phenylalanine and glutamic and aspartic acids were found in the petroleum-associated waters. It was postulated that the amino acids occurred in the petroleum waters in a combined state as nonproteinaceous acid complexes and that the solubility of these complexes probably is a function of salinity. This postulate was based on information which indicated that serine is thermally unstable. More recent information indicates that serine, lysine, threonine, glycocol, histine, isoleucine, and leucine are fairly stable up to 180°C (Califet and Louis, 1965).

Liquid-exchange chromatography was used to determine the amounts of amino acids in some saline waters (Siege1 and Degens, 1966). The results indicated the bulk of the amino acids dissolved in the sea are tied up in complexes and are not in a free form.

A study of the organic solutes in sea water led to the conclusion that coprecipitation methods are the most versatile for their isolation (Chapman and Rae, 1967). Some of the organics that can be isolated by this method include glucose, glutamic acid, aspartic acid, citric acid, succinic acid, glycol- late, glycine, and lysine. The percent of recovery of these solutes by this method varied from 16 to 90%. The method involved the coprecipitation of these organic solutes with iron or copper.

Most of the nitrogen in humic acid is located in the large and intermediate

FATTY ACIDS 183

size molecules, with the smallest molecules being practically nitrogen-free. This is attributed to the fact that the link involving nitrogen is more susceptible to oxidation than the rest of the molecule. Amino acids can be released from humic acid by acid hydrolysis, alkaline hydrolysis, and reduction with sodium amalgam (Piper and Posner, 1968).

A widely used procedure for concentrating and recovering trace organics is the carbon-adsorption method developed by Braus et al. (1951). A modification of this method by Robinson et al. (1967) allowed recovery of organics using three activated carbon filters in series, with the final two receiving acidified water.

Krause (1962) investigated the decomposition of organic matter in natural waters and found that immediately after the death of an organism that amino acids and keto acids appeared in the water. After 24 hours of aerobic decomposition, a qualitative and quantitative maximum was reached by both groups, and the amino acids present were alanine, aspartic, glutamic, glycine, leucine, lysine, methionine, phenylalanine, serine, tyrosine, and raline; and the keto acids present were pyruvic, oc-ketoglutaric, oxaloacetic, and glyoxylic. After 10 days, the only acids that remained of the amino group were glutamic, glycine, lysine, and serine; and of the keto group, pyruvic and oc-ketoglutaric.

Litchfield and Prescott (1970) analyzed sea water, and pond water, and spent algal media and found aspartic acid in all of the samples. Other amino acids frequently found were serine, glycine, alanine, and arginine. Techni- ques employed in the analysis were dansylation, extraction, and thin-layer chromatography . Fatty acids

Ralston and Hoerr (1942) determined the solubilities of the normal saturated fatty acids from caproic to stearic acid, whose number of carbon atoms ranges from 6 to 18 in water, ethanol, acetone, 2-butanone, benzene, and glacial acetic acid from 0' to about 60'C. In general, the solubilities increased with increasing temperature.

Free fatty acids and hydroxyl ions form when soaps hydrolyze. The rate and percentage of hydrolysis is pH dependent, generally the potassium soaps are more hydrolyzed than the corresponding sodium soaps, and free fatty acid never separates as such from pure soap solutions unless reacted with an excess of acid such as carbon dioxide (McBain et al., 1948).

Quantitative recovery of organic constituents from saline waters without alteration is difficult. Temperature and pressure changes, bacterial actions, adsorption, and the high inorganic/organic constituents ratio in most petroleum-associated waters are some reasons why quantitative recovery is difficult. Some of these factors apply also to sea waters, and Jeffery and Hood (1958) evaluated five methods which proved effective for isolation of portions of the soluble organic compounds in sea water. They were: (1)


dialysis or electrodialysis; (2) ion exchange;, (3) solvent extraction; (4) coprecipitation; and (5) carbon adsorption. Their results showed that the total organic material was most efficiently removed by electrodialysis or by coprecipitation with ferric hydroxide.

A study of the differential uptake of organic compounds by montmorillonite and kaolinite revealed that montmorillonite adsorbed the compounds more efficiently than kaolinite. The compounds studied were aspartic acid, alanine, glucose, and sucrose (Williams, 1960). Approximately 13% of the aspartic acid was removed from solution by montmorillonite, while kaolinite removed only about 2%.

The following saturated, monosaturated, and diunsaturated long-chain fatty acids were found in sea water: saturated Cl0, C12, CI4, C16, CIS, CzO, and CZ2; diunsaturated CIS; and monounsaturated CI6 and c18 (Emery and Koerner, 1961). Also isolated were CIS, C1,, and C19 acids which might or might not have been originally present.

A gas chromatographic method was developed for the determination of trace amounts of the following fatty acids in water: n-valeric, isovaleric, n-butyric, isobutyric, propionic, and acetic (Emery and Koerner, 1961). The gas chromatograph was equipped with a flame ionization detector and a column of Tween 80 on Chromosorb W.

The fatty acids lauric, myristic, palmitic, stearic, hyristoleic, palmitoleic, oleic, linoleic, and linolenic were identified in sea water using solvent extraction, esterification, and gas-liquid chromatography (Slowey et al., 1962). Samples of deep-sea water contained less unsaturated acids and shorter-chain acids than surface samples.

Saturated straight-chain fatty acids were found in petroleum-associated waters from two reservoirs. The carbon numbers were CI4 through C30. The same acids were identified in a shale-core sample from a petroleum reservoir. The even-numbered acids predominated over the odd-numbered acids in the amounts found in every case. The identification methods consisted of extraction by refluxing, esterification, gas chromatography, and mass spectrometry (Cooper, 1962).

A gas chromatographic method capable of separating unesterified fatty acids was developed (Metcalfe, 1963). Acids up to CzO were identified using a thermal conductivity detector and a column composed of phosphoric acid- treated ethylene glycol succinate polyester on Chromosorb W.

Bordovskii (1965) studied the sources of organic matter in marine basins, the sedimentation of organic matter in water, and the transformation of organic matter in sediments and its early diagenesis. He also pointed out that the organic matter in water is present in true solution, as colloidal organic detritus, and as live organisms in suspension. Bacteria play an important part in altering the composition of the organic material in the aqueous phase as well as in the sediments.

Wangersky (1965) found that organic carbon was present in freshly distilled water and that it survived triple distillation and distillation from

NAPHTHENIC AND HUMIC ACIDS 185

alkaline permanganate. He correlated this with algal growth in city reservoirs and suggested that the organic carbon content of distilled water must be considered by anyone growing organisms in distilled water. He also found that bubbling sea water caused organic compounds to form aggregates on the surface and further theorized that such reactions may be related to the origin of life.

Kabot and Ettre (1963) developed gas chromatographic methods capable of determining free fatty acids. They analyzed different mixtures of the normal fatty acids using both packed and Golay columns in conjunction with a flame ionization detector. They concluded that the quantitative analysis of free fatty acids is possible.

Naphthenic and humic acids

Davis (1968) examined the organic fractions of artesian well waters from a Texas oil-bearing Eocene age aquifer, using infrared and chromatographic methods. He found that the water coproduced with oil contained 1,000 times more naphthenic acids than water located updip from the oil. He also found a phthalic acid ester dissolved in the petroleum-associated water but concluded that it may be common t o ground waters in general.

Shaborova et al. (1961) state that “the presence in subsurface waters of organic acids in the form of salts of various metals or in a free state indicates a current process of leaching of organic matter from the enclosing rock. The presence of organic acids in subsurface waters is one of the evidences for the existence in the earth’s crust of chemical processes of decomposition of preserved organic matter. In turn, the organic acids are broken down into simpler compounds by decarboxilization. I t is known that decarboxilization of organic acids is accompanied by the formation of hydrocarbons. In nature, this process is a real geochemical factor. Consequently, the organic acids and their salts that are dissolved in subsurface waters can be regarded as one of the sources for the generation of hydrocarbons.”

Using a steam distillation method, organic acids were found in concentrations from 663 to 2,242 mg/l in subsurface waters taken from a Kazhim stratigraphic well. The average molecular weight of the acids was from 46 to 58, and the waters taken from Devonian age sediments contained higher concentrations of the acids than waters taken from Carboniferous age sediments.

Lochte et al. (1949) analyzed waters produced with high-pressure gas wells and identified the following acids: acetic, propionic, isobutyric, n-butyric, isovaleric, n-valeric, n-hexanoic, and other C6 isomers. Crude oils were treated with ammonia solution followed by electroprecipitation of the aqueous phase to remove naphthenic acids (Agaev, 1961). Further isolation of the naphthenic acids was accomplished by heating the aqueous phase to decompose the ammonium salts and remove ammonia and water.

Oden (1919) recognized fulvic acid, humus acid, and hymatomelanic acid


in soils. Later, Page and Dutoit (1930) modified the name humus acid to humic acid. Sestini (1898) demonstrated that the humic acids are of complex composition and contain ethereal and anhydride components in addition to alkyl, hydroxyl, and ketonic groups.

Burges (1960) suggested that humic acid is a single chemical substance or a group of similar substances, and that primarily it is nonnitrogenous. Steelink et al. (1960) fused soil humic acids and found the following degradation products: catechol, profocatechuic acid, and resorcinol. Steelink and Tollin (1962) determined the presence of two free-radical species in humic acid using an electron paramagnetic-resonance spectrometer. They believed that one could be a semiquinone radical and the other a quinhydrone radical.

Fulvic acids, humic acids, and hymatomelanic acids have been found in natural waters (Wilson, 1959; Black and Christman, 1963; Packman, 1964). The brown color, characteristic of many natural waters, is attributed to complex organic compounds which probably are derived from water-soluble peptizable components of soil humus.

A method that can be used to determine the organic acids in petroleum- associated waters was published by the Natural Gasoline Association of America (1953). The water is treated with lime water to convert the organic acids to their calcium. salts, which are titrated with a standard mineral acid.

Determination of oil in water

The following method was developed by Nalco Chemical Company (1971) and is applicable to waters and brines where the oily matter is hydrocarbons or hydrocarbon derivatives and all liquid or unctuous substances that have a boiling point above 90°C and are extractable from waters or brines at pH 5.0 or lower using benzene, chloroform, or carbon tetrachloride.

The sample is extracted with a fluorocarbon solvent which is evaporated off in a specially designed vessel and the residual oil measured volumetrically in a microsyringe.

Pear-shoped lop, capacity opprox.17 m l , o f f s e t oddit ionol opening so th0t"popped" somple w i l l be reto ined

S y r i n g e , 500 kl, 10-pl divisions

Fig. 6.1. Microsyringe-evaporating flask.

DETERMINATION OF OIL IN WATER 187

Apparatus. The necessary apparatus consists of: (1) Microsyringe - evaporating flask (see Fig. 6.1): this assembly consists

of a single-neck flask of approximately 20 ml volume which tapers opposite and slightly offset to the neck into a microsyringe equipped with a gas-tight Teflon-tipped plunger and calibrated to measure 0-500 pl.

(2) 1,000-ml pear-shaped separatory funnel. (3) Hotplate or hot-water bath: capable of being controlled in the range of

(4) 500-ml Berzelius, tall form beaker. 45O-55'~ at * ~ O C .

Reagents. The necessary reagents are: (1) 50% hydrochloric acid solution, reagent-grade. (2) pH paper indicating strip or pH meter. (3) 1,1,2-trichlorotrifluoroethane (Freon TF) reagent-grade, purified,

48OC boiling point.

Sampling. Collect a composite or spot sample representative of stream to be measured. Volume to be taken will be dependent on content of oily material and should be in the range of 1-5 liters. Sample should be caught in glass container.

Procedure. Extraction: adjust pH of entire sample to pH 5 or below using hydrochloric acid added in small increments. Thoroughly mix the sample and allow it to stand 15 minutes. Measure the volume of entire sample and transfer to separatory funnel. Add portion of 1,1,2-trichlorotrifluoroethane extraction fluid (see Note 1) to sample container, thoroughly rinsing any adhering oil material. Add this and balance of fluorocarbon to separatory funnel. Shake thoroughly for 5 minutes and let stand to separate layers. Draw off fluorocarbon layer into suitable beaker, filtering any entrained solids, if necessary, and warm gently to boiling point (see Note 2). Continue boiling until volume remaining can be contained in measuring flask.

Transfer to measuring flask with fluorocarbon rinse of beaker, and immerse the flask and contents into 500-ml beaker partially filled with water and warmed to 65°C on hotplate or in hot-water bath. Be sure open neck of flask is clear of upper edge of beaker (can be maintained by extension of syringe piston). Continue until volume is reduced to that of syringe volume.

Draw fluid into syringe and increase heat slowly to remove last traces of solvent, indicated by lack of bubbles forming in the syringe column.

Measure amount of oil material in graduated syringe using graduations midway in syringe.

Note 1: for single extractions fluorocarbon volume should be one-tenth of the original sample volume. In double extractions for better accuracy and reproducibility use two volumes of fluorocarbon, each onetwentieth of the original sample volume.

Note 2: although fluorocarbon is essentially considered nontoxic, the


evaporation of the solvent should be done in a well-ventilated area or under an exhaust hood with adequate draft to handle high-density vapors.

Calculation :

1-11 measured c = mg/l oily matter mi sampIe

Organic acids in oilfield brines

This method measures the bulk of the organic acid salts in oilfield waters.

Reagents and apparatus. Acetone; NaOH, 0.02N; HC1, 0.05N; acetic acid, 10 mg/l; a hotplate; and a standard pH meter.

Procedure. Pipet 25 ml of filtered brine into a 250-ml beaker; add 25 ml of acetone and adjust the pH to precisely 6. Titrate the sample to a pH of 3.5, and record the amount of 0.05N HC1, used in the adjustment from pH 6 to 3.5. Boil the solution for 5 minutes. Cool and titrate back to pH 6 with 0.02N NaOH. Make a blank determination for NaOH and HC1. To calculate, subtract blank from NaOH and HC1 titrations.

Calculation:

x 60,030 = mg/l organic acids (ml HC1 x HC1 N ) - (ml NaOH x NaOH N ) ml sample as acetic acids.

References

Agaev, A.A., 1961. Separation of ammonium salts of naphthenic acids from crude oil in an electric field. Izv. Vyssh. Uchebn. Zaved., Nef t Gaz, 4:95-98 (in Russian).

Andrews, L.J. and Keefer, R.M., 1949. Cation complexes of compounds containing carbon-carbon double bonds, 11. The solubility of cuprous chloride in aqueous maleic acid solutions. J. Am, Chem. Soc., 71 :2379-2380.

Anonymous, 1970. Solid natural gas discovered. Ind. Res., 12:70. Black, A.P. and Christman, R.F., 1963. Chemical characteristics of fulvic acids. J. A m .

Water Works Assoc., 55:897-912. Bohon, R.L. and Claussen, W.F., 1951. The solubility of aromatic hydrocarbons in water.

J. A m . Chem. Soc., 73:1571-1578. Bonoli, L. and Witherspoon, P.A., 1968. Diffusion of paraffin, cycloparaffin, and aromat-

ic hydrocarbons in water and some effects of salt concentration. In: Advances in Or- ganic Geochemistry - Proc. 4th Int. Meet. Org. Geochem., Amsterdam. Pergamon Press, New York, N.Y., 9:16-18.

Bordovskii, O.K., 1965. Accumulation and transformation of organic substance in marine sediments. Mar. Geol., 3:3-114.

Braus, H., Middleton, F.M. and Walton, G., 1951. Organic chemical compounds in raw and filtered surface waters. Anal. Chem., 23:1160-1164.

REFERENCES 189

Buckley, S.E., Hocott, C.R. and Taggart, Jr., M.S., 1958. Distribution of dissolved hydrocarbons-in subsurface waters. In: L.G. Weeks (Editor), Habitat o f Oil. American Association of Petroleum Geologists, Tulsa, Okla., pp. 850-882.

Burges, A., 1960. The nature and distribution of humic acid. Sci R o c . R . Dublin SOC. Ser. A , 4:53-51.

Califet, Y. and Louis, M., 1965. Contribution to the knowledge concerning the stability of amino acids contained in sedimentary rocks. Compt. Rend., Acad. Sci. Fr., 261 :3645-3646.

Chapman, G. and Rae, A.C., 1967. Isolation of organic solutes from sea water by coprecipitation. Nature, 214:627-628.

Coggeshall, N.D. and Hanson, W.E., 1956. Method of geochemical prospecting. US. Patent, No. 2,767,320.

Connolly, J.F., 1967. Solubility of hydrocarbons in water near the critical solution temperatures. J. Chem. Eng. Data, 11:13-16.

Cooper, J.E., 1962. Fatty acids in recent and ancient sediments and petroleum reservoir waters. Nature, 193:744-746.

Davis, J.B., 1968. Distribution of naphthenic acids in an oil-bearing aquifer. Presented at Annual Geol. SOC. A m . and Assoc. SOC. Meet., Mexico, D.F., November, 1968. Program, p. 7 1.

Degens, E.T. and Reuter, J.H., 1964. Analytical techniques in the field of organic geochemistry. In: U. Colombo and G.F. Hobson (Editors), Advances in Organic Geochemistry. Pergamon Press, New York, N.Y., pp.377-402.

Degens, E.T., Hunt, J.M., Reuter, J.H. and Reed, W.E., 1964. Data on the distribution of amino acids and oxygen isotopes in petroleum brine waters of various geologic ages. Sedimentology, 3 : 199-225.

Duffy, J.R., Smith, N.O. and Nagy, B., 1961. Solubility of natural gases in aqueous salt solutions, I. Liquidus surfaces in the System CH4-Hz O-NaC1-CaCl2 at room temperatures and at pressures below 1,000 psia. Geochim. Cosmochim. Acta, 24:23-31.

Duursma, E.K., 1965. The dissolved organic constituents of sea water. In: J.P. Riley and G. Skirrow (Editors), Chemical Oceanography. Academic Press, New York, N.Y., 1:433-475.

Eley, D.D., 1939. Solubility of gases, 1. Inert gases in water. Trans. Faraday SOC., 35 :1281-1293.

Emery, E.M. and Koerner, W.E., 1961. Gas chromatographic determination of trace amounts of the lower fatty acids in water. Anal. Chem., 33:146-147.

Erdman, J.G., 1965. Petroleum - its origin in the earth. In: A. Young and J.E. Galley (Editors), Fluids in Subsurface Environments - A m . Assoc. Pet. Geol., Mem. 4 , pp.20-52.

Frank, H.S. and Evans, M.E., 1945. Free volume and entropy in condensed systems. J. Chem. Phys., 13:507-532.

Hedberg, H.G., 1964. Geologic Hspects of origin of petroleum. Bull. A m . Assoc. Pet. Geol., 48 (11):1755-1803.

Jeffery, L.M. and Hood, D.W., 1958. Organic matter in sea water; an evaluation of various methods for isolation. J. Mar. Res., 17:247-271.

Jeltes, R. and Veldink, R., 1967. The gas chromatographic determination of petrol in water. J. Chromatogr., 27:242-245.

Kabot, F.J. and Ettre, L.S., 1963. Gas chromatography of free fatty acids, 111. Quantita- tive aspects. J. Gas Chromatogr., 1:7-10.

Kidwell, A.L. and Hunt, J.M., 1958. Migration of oil in sediments. In: L.G. Weeks (Editor), Habitat of Oil. American Association of Petroleum Geologists, Tulsa, Okla., pp.7 90-8 17.

Krause, H.R., 1962. Investigation of the decomposition of organic matter in natural waters. F A 0 Fish. Biol. Rep. , No.34, 14 pp.


Litchfield, C.D. and Prescott, J.M., 1970. Analysis by dansylation of amino acids

Lochte, H.L., Burnam, C.W. and Meyer, H.W.H., 1949. Organic acids produced by high

Marsden, S.S. and Kawai, K., 1965. "Suiy6sei-Ten'nengasu" - a special type of Japanese

McAuliffe, C., 1963. Solubility in water of C l - C g hydrocarbons. Nature, 200:1092-1093. McAuliffe, C., 1966. Solubility in water of paraffin, cycloparaffin, olefin, acetylene,

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Values of pH and the absence of fatty acid as free liquid or solid. J. A m . Oil Chem. SOC., 2 5:7 7-84.

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Metcalfe, L.D., 1963. The gas chromatography of fatty acids and related long chain compounds on phosphoric acid treated columns. J. Gas Chromatogr., 1 :7-11.

Nalco Chemical Company, 1971. Analytical Method for the Determination o f Oil in Water. Unpublished method (permission obtained through H.C. Noe).

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Univ. of Calif., Los Angeles, Calif., 74 pp.

Chapter 7. ORIGIN OF OILFIELD WATERS

The five spheres of the earth are the lithosphere (rocks), the pedosphere (soils, till, and other surficial materials), the hydrosphere (natural waters), the atmosphere (gases), and the biosphere (living organisms). Oilfield waters are a part of the hydrosphere, and petroleum is a product of the biosphere.

The total volume of water in the hydrosphere is about 1,338 x 10'' liters, and about 8.4 x 10" liters is ground water (Skinner, 1969). Most of the water, 1,300 x 10" liters, is in the oceans. Less than 50% of the total ground water is in strata below 1 km. The total amount of water in sedimentary rocks and associated with liquid and gaseous hydrocarbons is less than 1.3 x 1 O I 8 liters.

All of the petroleum recovered to date has been taken from oil wells drilled into the upper 8 km of the earth's crust. The average thickness of the

0 k m I 7 k m

4 0 0 k m

1,000 k m

2 . 9 0 0 k m

5 , 0 0 0 k m

6,371 k m

Fig. 7.1. Regions of the interior of the earth.

194 ORIGIN OF OILFIELD WATERS

earth’s crust is about 17 km, ranging from 5 km under the oceans to about 35 km under the continents (Clark and Ringwood, 1964). Fig. 7.1 illustrates the various regions of the interior of the earth, with the distance from the surface of the crust to the center of the inner core being 6,731 km. In this discussion we are concerned only with the crust to a distance of 0.08% of the depth to the center of the earth.

Hydrocarbons are believed to have originated from organic material in sedimentary material which was produced by weathering and erosion of the earth’s surface. This eroded material is carried away by water, ice, or wind and redeposited, ultimately forming sedimentary rocks. The major sedimentary, minerals are clays, quartz, calcite, gypsum, anhydrite, dolomite, and haiite. Most of the large bodies of sedimentary rocks were formed in marine environments; smaller sedimentary deposits formed in lakebeds and river floodplains.

Definitions of some water terms

Meteoric water. White (1957) defined it as water that was recently involved in atmosphere circulation and further that “the age of meteoric groundwater is slight when compared with the age of the enclosing rocks and is not more than a small part of a geologic period.”

Sea water. The composition of sea water may vary somewhat, but in general will have a composition relative to the following (in mg/l): chloride - 19,375, bromide - 67, sulfate - 2,712, potassium - 387, sodium - 10,760, magnesium - 1,294, calcium - 413, and strontium - 8.

Table 7.1 (Anonymous, 1964) gives a more comprehensive picture of the constituents found in sea water. The analyses given in Table 7.1. are in parts per million.

Interstitial water. Interstitial water is the water contained in the small pores of spaces between the minute grains or units of rock. Interstitial waters are: (1) syngenetic (formed at the same time as the enclosing rocks); or (2) epigenetic (originated by subsequent infiltration into rocks).

Connate water. The term connate implies born, produced, or originated together, connascent. Therefore, connate water probably should be considered to be an interstitial water of syngenetic origin. White (1957) called connate water of this definition a fossil water, i.e., water that has been out of contact with the atmosphere for at least a large part of a geologic period. As White (1957) pointed out the implication that connate waters are only those “born with” the enclosing rocks is an undesirable restriction.

Diagenetic water. Diagenetic waters are those waters that have changed chemically and physically, both before, during, and after sediment consolida-

SEDIMENTARY ROCKS 195

TABLE 7.1

Average composition of sea water

Element Amount Element Amount Element Amount (PPm) (PPm 1 (PPm)

Chlorine Sodium Magnesium Sulfur Calcium Potassium Bromine Carbon Oxygen Strontium

Boron Silicon Fluorine Nitrogen Argon Lithium

Rubidium Phosphorus Iodine Barium Indium Aluminum Iron

18,980 Zinc 10,560 Molybdenium 1,270 Selenium 880 Copper 400 Arsenic 380 Tin 65 Lead 28 Uranium 8 Vanadium 8 Manganese

Titanium 4.8 Thorium 3.0 Cobalt 1.3 Nickel 0.8 Gallium 0.6 Cesium 0.2 Antimony

Cerium 0.12 Yttrium 0.07 Neon 0.05 Krypton 0.03 Lanthanum 0.02 Silver 0.01 Bismuth 0.01 Cadmium

0.01 0.01 0.004 0.003 0.003 0.003 0.003 0.003 0.002 0.002 0.001 0.0007 0.0005 0.0005 0.0005 0.0005 0.0005 0.0004 0.0003 0.0003 0.0003 0.0003 0.0003 0.0002 0.0001

Tungsten Germanium Xenon Chromium Beryllium Scandium Mercury Niobium Thallium Helium Gold Praseodymium Gadolinium Dysprosium Erbium Ytterbium Samarium Holmium E uro pi um Thulium Lutetium Radium Protactinium Radon

1 lo4 1 lo4 1 lo4 5 x 10- 5 10-~

3 x 10- 1 1 10-~

2 x 2 2 2 2 2

4 x

5 x 10" 4 x lod

8 x 4 x 4 x 4 x 3 x lo-" 2 x lo-'* 9

tion. Some of the reactions that occur in or to diagenetic waters include bacterial, ion exchange, replacement (dolomitization), infiltration by permeation, and membrane filtration.

Formation water. Formation water as here defined is water that naturally occurs in the rocks and is present in them immediately before drilling (Case, 1955).

Juvenile water. Water that is in primary magma or derived from primary magma is juvenile water (White, 1957).

Sedimentary rocks

At least a portion of the water found in petroleum reservoirs consisting of sedimentary rocks was deposited with the sediments before they were transformed into rock. As the sediment compacted to form rock, the composition


TABLE 7.11

Average composition of igneous and some types of sedimentary rocks (ppm)

Element Igneous rocks Sedimentary rocks Evaporites (halite)

resistates hydrolyzates precipitates

Si A1 Fe Ca Na K

Ti P Mn F S C c1 Rb Sr Ba Cr Zn Ni c u Li N Sn co Pb Th cs Be As U B Br I Cd Se Hg Ra

Mg

277,200 367,500 272,800 24,200 90 81,300 25,300 81,900 4,300 20 50,000 9,900 47,300 4,000 11

25,900 11,000 27,000 2,700 800

36,300 39,500 22,300 304,500 930 28,300 3,300 9,700 370 325,000

20,900 7,100 14,800 47,700 460 0.8 4,400 960 4,300 -

1,180 350 740 175 1,000 trace 620 385 1 600-900 - 510 250 20 520 2,800 2,600 1,100 770 320 13,800 15,300 113,500 70 314 trace 200 586,000 310 27 3 300 0 300 < 26 170 425-765 - 250 170 460 120 2 200 68-200 410-680 2

-

- -

- 132 < 20 200-1,000 < 50 1 80 2-8 24 0 0

192 20.2 3 70 65 17 46 < 26 46

40 40 23 0 8 0 16 20 20 5-1 0 2 11.5 (? ) 6.1 10.1 1.1 < 0.2

12 7 < 4 0 - 5

6 (3 5 4 1.2 1.2 1.3 0.01 3 9-31 310 3 < 2

60 < 0.2 1.62 0.07-0.55 < 2 0.3

0.15 0 0.3 0.09 0.08-0.5 0.1 0.3 0.03 -

1.3 x 0.7 x 1.08 x lod 0.42 x lod -

- -

- - - - - - -

-

- - - - -

- - -

- - - -

- - 0.6 < 0.1 < 0.5 -

of the interstitial water changed because of reactions with the rock. A simplistic view of sedimentary rocks and their relation to oilfield waters should include consideration of weathering; erosion; transportation mechanisms; sorting of weathered products; depositional environments of clastics, carbonates, evaporites, organic matter, and silica; sediment com- pactions; sediment diagenesis; and petroleum and natural gas.


The volume of the earth is about 1,100 billion km3 and the volume of the oceans is about 1.3 .billion km3; however, the oceans with an area of 360 million km2 cover 70% of the surface of the earth. The average composition of some of the igneous and sedimentary rocks of the earth’s crust is shown in Table 7.11, which was taken from Clarke and Washington (1924) and Rankama and Sahama (1950). The resistate rocks referred to in Table 7.11 are composed of residues not chemically decomposed in the weathering of the parent rocks. Hydrolyzate rocks are the insoluble products formed by chemical reactions during weathering of parent rocks. Precipitate rocks are those formed by chemical precipitation of minerals from aqueous solution. Evaporite rocks are marine evaporites which were produced when the water in which they were dissolved was evaporated.

Sedimentary rocks comprise about 5% of the lithosphere, while the igneous rocks form 95%. The three main types of sedimentary rocks are shale, sandstone, and iimestone, and their relative abundance determined from geochemical data ranges from 70 to 83% shale, from 8 to 16% sandstone; and from 5 to 14% limestone (Pettijohn, 1957). Levorsen (1966) noted that oil and gas are found in reservoir rocks consisting primarily of sandstones, limestones, and dolomites.

Weat hering

Weathering is a most important factor in producing the source material for the creation of sedimentary rocks. Processes that cause weathering are chemical, physical, and biological (Ross, 1943).

The weathering of rock by physical methods includes temperature changes brought about by climate changes. Examples are the breaking of rock by thermal expansion (heat), the breaking of rock by the expansion of freezing water in the pores or cracks, or the mechanical breaking of rock as a glacier moves over it. Breaking the rock causes the surface area to become larger without significantly changing the chemical composition.

Biological weathering includes the cracking of rock as a result of plant roots and the action of acids derived from plants, animals, and bacteria. The biotic factor includes bacteria, algae, protista, protozoa, higher animals and plants, during both life and subsequent necrotic decomposition which furnish Ht ions, colloids, complexing agents, and dispersants.

Chemical weathering involves the action of water upon the parent rock and upon the products of physical and biological weathering. In chemical weathering the composition of the source rock is changed by solution, hydrolysis, oxidation, and reduction reactions. The Ht ion when concentrated in aqueous solution is a very important energy factor because it will cause rapid chemical reactions with parent rocks. The redox potential influences the rate of removal of elements, such as iron and manganese from the parent rock, and if it is a reducing potential, these elements are more likely to remain in solution after solubilization.


Erosion

Erosion is the opposite of deposition (the processes are reversible), but erosion must occur before deposition can proceed. The products of weathering are eroded and transported to a new location by the action of water and wind. The water serves to transport the majority of these products, and it can transport them by dissolution, suspension, or pushing of larger particles.

Transpor ta t ion mechanisms

Both wind and water can transport the products of weathering, however, this discussion will consider only water. The transport mechanisms considered are chemistry, physics, and hydraulics.

Perhaps the primary solvents of weathered products are carbonated water, organic acids, and sulfate solutions. Elements that dissolve readily in carbonated waters are lithium, sodium, potassium, magnesium, calcium, strontium, iron, manganese, phosphorus, and others. The organic acids will dissolve iron and manganese, while sulfate solutions will dissolve copper, iron, and manganese compounds.

The chemistry of the water is a prime factor in the dissolution of the rock; if the pH is acidic, the transition group metals are more likely to dissolve, while if it is basic, elements such as silica are more likely to dissolve. Salts of the alkali and alkaline earth metals will dissolve if the pH is either acidic or basic; however, if the pH is above 10, some of the alkaline earths such as magnesium will precipitate. The pH of the water is influenced by the dissolution of carbon dioxide. For example, as carbon dioxide dissolves in water, the pH will change. The pH of pure water in equilibrium with carbon dioxide can be calculated and is 5.65 (Hem, 1970). The pH is calculated using the mass-law equations in which the activity of water is unity in dilute solution, and h, = constant equal to the product of the activities of H+ and OH-.

Introduction of another phase such as calcite into the water carbon dioxide system will change the pH. Garrels and Christ (1965) calculated that such a system in equilibrium with the atmosphere will have a pH of 8.4. Additional ions such as those found in ocean water will produce other pH values. For example, if the system is ocean water in equilibrium with carbon dioxide, the pH at each equilibrium step is approximately:

H 2 0 + C 0 2 * H2C03 7PH 5) H2 co3 (PH 6-31 A - HC03-+H+ HC03+H+ =+ 2H++C03-2 (pH 10.3)

Some chemicals when dissolved in water act as buffers, where a buffer is defined as something that .produces an effect which inhibits a large pH change when an acid or a base is added to the water. Therefore, as a water


600

400- r W

200

becomes more concentrated with certain dissolved solids, the pH can be more stable because of buffer effects.

A solution containing an activity of orthosilicic acid greater than its solubility product ( K ) is oversaturated and SiOz will precipitate. If the activity

s.p of orthosilicic acid is less than its K s p , SiQz can dissolve until (H4Si0,) = Ksp. The same applies for other constituents.

Complex compounds and ion pairs are important chemical transport mechanisms. An example of a complex compound is a metal chelate such as copper chelated with ethylenediamine tetraacetate, with the interacting ligands immediately adjacent to the metal cation. An ion pair is formed if the coordinated water is retained in forming the complex (Stumm and Morgan, 1970).

The redox potential (Eh) also influences the transport of metals in solution. Most surface waters in contact with the atmosphere will have an oxidizing potential, Fig. 7.2. However, many subsurface waters have low redox potentials, and metals such as iron and manganese are transported as reduced species.

-

-

I I I /M,odern sea water

Acid I Alkaline

I Fe++

-400 -

-600 -

I I I I I H2, I -eooo 2 4 6 8 10 12 14

PH

Fig. 7.2. Diagram of some EhlpH relationships.


Sorting of weathered products

Products of weathering are transported by water by rolling along the streambed, by suspension of the smaller particles, and by solution of soluble components. As the larger rocks and pebbles roll along the streambed, they are abraded by bumping against each other and by abrasive action with the rocks in the streambed. The size of the clastics, which are detritus transported mechanically to the point of sedimentation and portions solubilized by water before sedimentation, decreases in the downcurrent direction (Pettijohn, 1957), and this change in grain size is primarily a sorting effect. The effect is noted in both fluvial and marine deposits.

Mobile belt f

Geosynclinal trough Borderland r

For eland (stable) Shelf area

Fig. 7.3. Idealized depositional basin. (After Moore, 1969.)

Knowledge of the sorting of the clastics is used in reconstructing the ancient environment (Visher, 1965).This knowledge can be applied to exploration for petroleum and other valuable minerals. A simplistic depositional basin is shown in Fig. 7.3; the deposited clastics will be found on the borderland side of the basin and not on the foreland side.

Depositional environments of clastics

Depositional environments of the clastics include eolian, fluvial, regressive marine, transgressive marine, deltaic, bathyal-abyssal, and lacustrine. Eolian deposits are sands that are drifted and arranged by currents of air or wind. Fluvial deposits are those related to streams, rivers, and ponds. Water in these environments usually contains less than 10,000 mg/l of dissolved solids.

Regressive marine deposits are land-derived sediments that are transported seaward and settle in the ocean. The salinity of the water transporting these sediments will vary, it is fresher at its source and becomes more brackish as it nears the sea. The dissolved solids in contemporary sea water are about 35,000 mg/l, while some estuary waters contain about 20,000 mg/l of dissolved solids.

Transgressive marine deposits usually are small in volume compared to fluvial and regressive-marine deposits. Such deposits are formed mainly by


erosion and redeposition of sediment deposits. The salinity of the sea may change somewhat during transgression but probably not much.

Deltaic deposits result from a combination of environmental factors and are related to both fluvial and regressive marine processes. During flood times the rivers transport tremendous volumes. of material, both clastic and organic, into delta areas. Deltaic deposition is a very important factor in the formation of petroleum because of the tremendous amount of organic material deposited.

Bathyal-abyssal deposits are formed in deep-water areas in the sea, and turbidity currents are responsible for most of the clastic deposition (Emery, 1960). Lacustrine deposits are those that are formed in lakes. If the lake is a fresh-water lake, the dissolved solids may be less than 1,000 mg/l; in a salt-water lake, the dissolved solids may be greater than 35,000 mg/l.

Consider a simplistic sedimentation area where the borderland area is the prime source of sediments. The coarse- to fine-grained clastics which are weathering products of the high-mountains borderland are deposited near their source. The clastics are detritus transported mechanically to the point of sedimentation and are not solubilized by the water before deposition. Primarily they are the sandstones and shales (clays). They will not be found on the for.eland side of a depositional basin. Clay deposition can be detrital or authigenic; illite often is detrital. There are at least two dozen clay minerals, many of which occur in very minute grains and most of which cannot be resolved by high-power petrographic microscopes. The electron microscope, X-ray diffraction, and differential thermal analysis are used to determine the type of clay.

The clays are very important in relation to petroleum and gas because they are the major component in the shales from which petroleum and gas are generated. The clays also possess base exchange properties which will react with constituents in water and petroleum. The detrital clays settle in low-energy waters and they settle more rapidly from a saline water than from a fresh water.

Depositional environments of the carbonates

Limestones and dolomites are the dominant carbonate reservoir rocks, while the sandstones are the dominant clastic reservoir rocks (Ham, 1962). The carbonates were precipitated at the place where the rocks first formed, while clastics were primarily transported grains.

Plumley et al. (1962) classified the carbonates according to an energy index of the water from which they precipitated. They divided them into five types. Type I is deposited in quiet water; it consists of calcite, 15-5096 clay, and < 5% detrital quartz. Type I1 is deposited in intermittently agitated water and consists of calcite, < 25% clay, and < 50% detrital quartz. Type I11 is deposited in slightly agitated water and it consists of calcite with up to 50% detrital quartz. Type IV is deposited in moderately agitated water


and consists of calcite with up to 50% detrital quartz. Types I11 and IV are similar in percentage of minerals; however, they are further differentiated according to grain size, sorting, roundness, and fossils, as are the other types. Type V is deposited in strongly agitated (high-energy) water and it consists of calcite, < 5% clay, and < 25% detrital quartz.

The calcium in the carbonates is released during rock weathering and goes into solution as bicarbonate. The solubility of calcium carbonate in water is also dependent upon the amount of carbon dioxide in solution. If the amount of dissolve carbon dioxide decreases, calcium carbonate is precipitated; therefore, the amount of calcium carbonate precipitation increases in warm water because the amount of carbon dioxide in solution is less than in cold water. Considerable amounts of carbonate precipitation occur in warm environments (Illing, 1954). Aquatic plants also absorb carbon dioxide and cause carbonate precipitation. The deposited carbonates can be pure or mixed with sand, clay, iron, manganese, and organic matter.

Modern carbonate deposition occurs as deep-water oozes, and reefs, and on shallow shelves. The deepwater oozes form along the flanks of ocean basins at depths of less than 6,000 m. They do not form at depths greater than 6,000 m because the calcium carbonate solubility increases with the increased pressure. On the flanks of the basins, terrigenous material mixes with the calcium carbonate. Often the mixture is 65--89% percent calcium carbonate with silt making up the remainder (Gevirtz and Friedman, 1966).

Reef carbonates develop in open oceans on shallow platforms forming atolls, as isolated patches on the ocean shelves, or along the margins of shelf areas as fringing reefs. Fringing reefs generally occur in tropical regions on the western side of the ocean basin. Reefs form as a result of living organisms which form the framework of the sediment (Ginsburg and Lowenstam, 1958).

Present-day shelf carbonates are developing in Florida Bay, on the Bahama Banks, on the Australian shelf, and on shelves off British Honduras, Yucatan, and India. The precipitation often occurs as shallow carbonate mud banks. The sediment in the shallow shelf areas often consists of about 10% skeletal material mixed with oolites, mud aggregates, grapestone, aragonite needles, calcareous algae, etc. The average rate of carbonate accumulation on the Bahama Banks is 50 mg cm-2 yr-I (Broecker and Takahashi, 1966). The salinity of the water ranges from 36,000 mg/l of dissolved solids to 46,500 mg/l. The more saline waters occur in lagoonal areas. The pH ranges from about 8.0 to 8.2 and is lowest at the end of the day because of C02 extraction from the water by marine plants.

In the simplistic depositional basin shown in Fig. 7.3 (Moore, 1969), limestones and reef limestones will be deposited on the foreland side, formed from water soluble constituents that precipitated from the saline solutions.


Depositional environments of evaporites

Calcium carbonate precipitates from sea water after it begins to evaporate (Usiglio, 1849). Removal of calcium ions from solution increases the Mg/Ca ratio in the residual brine, and the precipitated calcium carbonate reacts with the magnesium enriched brine to form dolomite (Deffeyes et al., 1964). The common order of evaporite deposition in a basin cut off from the open sea is limestone > dolomite > gypsum > halite > potash. Evaporite deposition can be stopped in a basin by a change in climatic regimen or tectonism. If it were changed and new water were allowed to enter, the already deposited salts probably would be effectively protected by the superadjacent high-density brine, and the lighter waters either meteoric or sea water would float on top, developing euxinic conditions similar to a situation found in the Black Sea.

Toxic conditions in euxinic areas tend to preserve deposited organic matter. The preserved organic matter later can be transformed to hydrocarbons and petroleum. Hypersaline lagoons often are very prolific in the production of organic matter (Phleger and Ewing, 1962). Algal pads and an abundance of organic organisms are characteristic of a high-pH, high-salinity environment (Carpelan, 1957) such as exists before euxinic conditions develop.

The deposition of evaporites occurs when water evaporates under restricted environmental conditions. The restrictions usually are caused by tectonism such as an uplift, regression of the strand line leaving a relict sea, or biological building of a reef.

Sloss (1953) outlined five environments from which evaporites deposit; they are normal marine, euxinic, penesaline, saline, and supersaline. Primary carbonates and dolomitized carbonates precipitate from the normal marine environment where the water contains about 35,000 mg/l of dissolved solids. Limestones rich in organic matter and black shales often are related to euxinic environments.

In the penesaline environment carbonates and primary dolomite form. The salinity of the water is toxic to normal marine life but not sufficiently saline so that halite precipitates. The dissolved solids in the water range from about 250,000 mg/l to 350,QOO mg/l.

From a saline environment carbonates, sulfates, and halites will precipitate. From a supersaline environment potassium compounds will precipitate, and the amount of dissolved solids in the solution will be about 500,000

A simplistic model of an evaporite basin is a closed basin initially filled with sea water and evaporated to dryness. In the isochemical system a layer of calcium carbonate is deposited over the entire basin floor as evaporation proceeds. Next, gypsum is deposited and when the water is reduced to about 10% of the original volume, halite precipitates. Halite will deposit only in the deeper parts of the basin and if the solution goes to dryness the more soluble salts will deposit in any remaining depressions and on top of the halite.

mg/l.


Deffeyes et al. (1964) proposed that dolomitization of limestone results from the evaporation of sea water and precipitation of gypsum causing the ratio of magnesium to calcium in the water to increase. The concentrated water flows downward, because it is more dense, into the underlying sediments where it reacts with limestone to form dolomite.

Modern evaporite deposits are thin and cover relatively small areas of the earth; however, the ancient environments indicate that these depositions were widespread in the United States (Krumbein, 1951) and in the world (Lotze, 1938). The majority of the major evaporite bodies are of marine origin, and range in age from Cambrian to Tertiary. They form in arid marine climates where water lost by evaporation equals or exceeds that supplied by rainfall, rivers, or the open sea. They also form in deep-water environment (Brongersma-Sanders, 1971 ).

The data in Table 7.111 illustrate how the concentrations of some of the dissolved constituents change as sea water is evaporated to dryness (Collins, 1969a). As sea water is evaporated to dryness and the chloride concentration approaches 178,000 mg/l, calcium sulfate precipitates. Halite precipitates when the chloride concentration approaches 27 5,000 mg/l, magnesium sulfate precipitates during the next stage as the chloride concentration approaches 277,000 mg/l. The concentrations of the ions in solution at these various stages approximate those shown in Table 7.111. The data in Table 7.111 indicate that, as sea water evaporates, the concentrations of lithium, magnesium, boron, chloride, bromide and iodide in the residual liquor increase, and that the concentrations of sodium, potassium, rubidium, calcium, and strontium decrease. In most depositional areas, the brines never reached the concentration necessary for the deposition of potassium and magnesium

TABLE 7.111

Concentration changes during evaporation of sea water and brine

Element Sea water CaS04.l NaCl 4 MgS04.l KCI 4 MgClz.1

Lithium Sodium Potassium Rubidium Magnesium Calcium Strontium Boron Chloride Bromide Iodide

0.2 11,000

350

1,300 400 7 5

19,000 65

0.1

0.05

2 98,000 3,600

1 13,000 1,700

60 40

178,000 600 2

11 140,000 23,000

6 74,000

100 10 300

275,000 4,000

5

12 70,000 37,000

8 80,000

10 1

310 27 7,000 4,300

7

27 13,000 26,000

14 130,000

0 0

750 360,000 8,600

8

34 12,000 1,200

10 153,000

0 0

850 425,000 10,000

8

Total 295,000 517,000 469,000 538,000 602,000


salts; or if they did, these salts were later removed by leaching so that their occurrence is relatively rare.

Holser (1963) analyzed some brine inclusions in halite from Permian age evaporites. He found that the Br/Cl and Mg/Cl ratios in many of the brine inclusions are similar to those found in the late stages of halite deposition. He concluded that some of the inclusions were connate bitterns with few diagenetic changes, and that the Br/Mg ratio of sea water has remained relatively constant since Permian time. Some diagenetic changes were evident in a few of the inclusions in which a large ratio of Ca/C1 and a low ratio of SO4 /Cl compared to sea water were found.

Sediments commonly associated with evaporites are red beds, quartzose sandstones, subgraywacke sandstones, carbonate rocks, and marine shales (Krumbein, 1951). Normal marine evaporite successions are found in inter- cratonic basins such as the Michigan and Williston Basins. Euxinic black shales sometimes are associated with evaporites. Low redox potentials have been found in modern evaporite (Morris and Dickey, 1957; Quaide, 1958). Examples of modern depositional evaporites are the Karaboghaz Gulf on the eastern side of the Caspian Sea, the Great Bitter Lake of Suez, the Rann of Cutch in northwest India (Grabau, 1920), and the Persian Gulf sabkhas (Evans et al., 1963; Butler, 1969).

Deposition of organic matter

The organic matter can be biogenic (produced by living systems) or abiogenic (not produced by living systems). The source of biogenic matter can be both terrestrial and marine; for example, considerable plant and animal debris is collected from the land by streams and rivers and carried to the sea, while in the sea large quantities of plant and animal matter live and die.

The organic matter that is deposited with sediment usually decomposes if the conditions are right; however, if the environment is reducing some of it may be preserved. The preserved organic matter is transformed into other organic compounds (Kvenvolden, 1964). During sediment diagenesis the organic matter is transformqd to insoluble organic matter (kerogen) and soluble petroleum hydrocarbon (Hunt and Jamieson, 1958). Chemical, bacterial, and catalytic reactions are involved in these conversions. Tempera- ture and pressure affect the reaction rates. Some of the chemical reactions are as follows:

(1) Oxidation : C2Hm + 0 2 -+ nC02 + '/znH,O (2) Reduction: R'OH + H2 + R'H + H 2 0 (3) Elimination: R'COOH + R'H + co2 (4) Polymerization: (small units) + big molecule (5) Cracking: c-c-c-c-c-c~oc-c-c- + c-c


The organic matter produced by photosynthesis in the oceans is estimated to be sufficient to produce 11 million metric tons of hydrocarbon precursors annually (Riley, 1944). A very small amount of this organic material preserved in sedimentary rocks each year through geologic time would supply all of the known oil and gas fields plus many undiscovered giant fields.

Shales consisting of organic material, siltstones, claystones, and limy mud mixtures are found in the trough of a basin (Fig.7.3.). A simplistic idealized view of the trough area is that organic matter deposited in the trough is preserved in the stagnant low-Eh environment. If rapid subsidence occurs, the organic material later is transformed into hydrocarbons which move up and out of the trough into stratigraphic traps on the foreland side or structural traps on the borderland side of the basin.

The time interval between deposition of the organic material and conversion to petroleum is millions of years, during which time the trough or ocean basin is filled with sediment and buried, and the sediment is compacted to rock. Some of the water in which the sediments deposited will remain in the rocks as interstitial water.

Deposition of silica

Most of the silica in sediments is of the detrital variety but some is authigenic. Silica is dissolved by waters with high pH potentials and precipitated from water with a low pH. The precipitated silica often acts as a cement.

Sediment compact ion

Sediments compact or consolidate in response to an imposed load, and in the natural environment, the load is the weight of overlying sediments (Weller, 1959). Compaction of a sediment results in a reduction of the interstitial volume concurrent with expulsion of interstitial water and deformation of the sediment skeleton (the solid granular framework exclusive of bound interstitial water). The grains and the interstitial water are almost incompressible, and the rate of expulsion of interstitial water is about identical with the rate of compaction (Taylor, 1956).

Terzaghi and Peck (1968) studied the expulsion of pore water from un- consolidated clays, and determined that the rate at which clay compaction occurs is dependent upon the clay permeability, its volume compressibility, and the square of the thickness of the bed which is compacted. Shales decrease in porosity when compacted; for example, their porosity can decrease about 80% as they compact during burial.

White (1957) noted that very large quantities of water are removed from sediments during their compaction. For example, water-saturated shale decreasing in porosity from 20 to 10% loses 10" liters of water per km3 of sediment. Such sediment could yield per km3 a water supply of 20 liters per


minute for 10,000 years. Compaction water is further considered in a subsequent chapter concerned with the accumulation of petroleum.

The resistance to flow of bound interstitial water is greater than the resistance to deformation of the sediment framework during the first stages of compaction. As pressure is increased and sediment compacts, the sediment framework increases resistance to deformation, which also governs the deformation rate of the bound-water films and the outflow of the interstitial water. Rosenqvist (1962) found that bound water has a higher viscosity than unbound insterstitial water. Permeability decreases with compaction, and this together with the increased water viscosity leads to additional resistance to expulsion of bound interstitial water during subsequent compaction.

Porosity decreases during compaction, and at infinite depth it would become infinitely small. Porosity and permeability are two important factors in determining the amount of petroleum and/or water that can be recovered from a given reservoir or aquifer (Pollard and Reichertz, 1952; Caraway and Gates, 1959). The porosity of an aquifer indicates how much fluid the aquifer can hold, and the permeability indicates how fluid can move through the aquifer. If the porosity is high but the permeability is low, the reservoir may contain large amounts of oil, gas, or water, but they cannot be recovered unless special techniques are used to increase the permeability.

Sediment diagenesis

Mineralogical and chemical changes occur in the sediments as they compact. The mineralogic composition of recent marine sediments and ancient marine sedimentary rocks are different, as is the composition of the interstitial water in the recent sediments compared with the waters in ancient stratigraphic units. Chemical reactions occur between the sediments and their interstitial water (Chave, 1960). It has been shown that chemical changes can be measured in recent sediments, e.g., below the sediment- water interface, changes in pH and Eh result from degradation of sulfate ions by bacteria (Emery and Rittenberg, 1952).

Numerous chemical inhomogeneities occur within a single core sample of recent sediments (Degens and Chilingar, 1967). The magnesium concentration in the interstitial w&er decreases slightly with depth, while the concentrations of calcium and potassium increase (Siever et al., 1965). The interstitial waters from continental shelf sediments have higher chloride concentrations and higher ratios of Ca/C1, K/Cl, and Rb/C1 than the overlying sea water; the ratios of Li/Cl and Mg/Cl are about the same as in the overlying sea water except that the Li/C1 ratios are higher in the innershelf samples than in the outershelf samples. The Sr/Cl ratio is higher in the overlying sea water, while the pH and Eh values are lower in the sediments than in the overlying sea water (Friedman et al., 1968).

A detailed study indicates that virtually no environment exists on or near the earth’s surface where the pH/Eh conditions are incompatible with


organic life (Baas Becking et al., 1960). Because COz is the main byproduct of organic oxidation and the building material of plant and much bacterial life, it plays a dominant role. Carbon dioxide dissolves in water, producing the bicarbonate ion and a free hydrogen ion. The concentration of the hydrogen ion is lo-’ equiv./l (pH 7) at 2OoC in pure water, but when saturated with COz it rises to lo-’ (pH 5). This reaction moves to the right with increasing temperature in a closed system. In the presence of organic constituents, the equilibrium is modified, and the pH range can extend from 2 to 12.

The ionic potentials of the constituents involved in diagenesis are important (Cloke, 1966). Those that stay in true ionic solution up to rather high pH levels are Na+, K+, Mg+’, Fe+’, Mn+2, Ca+’, Sr+’, Ba+’, etc.; they are the soluble cations, and their ionic potentials range from 0 to 3, where the ionic potential is the ratio between the ionic charge and the ionic radius. Constituents that are precipitated by hydrolysis are those with ionic potentials from 3 to 12 and include such ions as AP3, Fe+3, S P 4 , and Constituents that form soluble complex ions and usually go into true ionic solution include B+ 3 , V 4 , N+ ’, P+’ , S6, and Mn+’ ; their ionic potentials are over 12. In general, the hydroxides of the soluble cations possess ionic bonds; therefore, they are soluble, the hydrolysates or those precipitated by hydrolysis form hydroxyl bonds, and the soluble complex ions have hydrogen bonds.

Organisms that consume oxygen cause a lowering of the redox potential, and in buried sediments it is the aerobic bacteria that attract the organic constituents and remove the free oxygen from the interstitial water. Sedi- ments laid down in a shoreline environment often differ in degree of oxidation from those laid down in a deep-sea environment (Pirson, 1968). For example, the Eh of the shoreline sediments may range from -50 to 0 mV while the Eh of deep-sea sediments may range from -150 to -100 mV. The aerobic bacteria die when the free oxygen is totally consumed, and the anaerobic bacteria attack the sulfate ion which is the second most important anion in the sea water. During this attack, the sulfate is reduced to sulfite and then to sulfide. Also the Eh drops to -600 mV (Fig.7.2). Sulfide is liberated and CaC03 precipitates as the pH rises above 8.5 (Dapples, 1959). Sulfur has two stable isotopes, * S and S, with a mass differential of 6%. The isotopes are fractionated during the change of S04-2 to Sv2, and SZ is enriched in the more energetic 32S isotope. The average ratio of 3zS/34S in normal sea water sulfate is about 21.76 (Ault, 1959). The sulfate isotopes are useful in interpreting ancient diagenetic stages.

Reactions occur during sediment diagenesis and affect the composition of the interstitial water. Calcite is precipitated if the pH is high, or it is dissolved if the pH is low. Dolomitization occurs as follows:

2CaC03 + MgClz * CaMg(C03)2 + CaClz


Other exchange reactions occur, whereby montmorillonite transforms to illite (Burst,‘1969). Ions are adsorbed by negatively charged clays from the sea water (Krauskopf; 1956). Dissolved salts hydrolyze; e.g., olivine hydrol- yzes to serpentine as follows:

2Mg2 SiO, + 3H2 0 =+ 3Mg * 2Si02 2H2 0 + Mg(OH)2

Hydration and dehydration reactions occur, such as the gypsum-anhydrite relation :

CaS0, + 2 H 2 0 + CaSO, * 2 H 2 0

As depth of burial increases, many mineralogical changes take place in the sediments. In the Gulf Coast Tertiary, the clay mineral montmorillonite gradually disappears at depths between 2,500 and 3,000 m (Burst, 1969). It is replaced by mixed layer and illitic clay minerals. This change involves chemical alteration and also the release of water of crystallization. This change appears to be temperature dependent with the reactions starting at about 100°C.

Other mineral changes occur in the sandstones such as the deposition of secondary silica overgrowths on the quartz grains causing resultant loss in porosity. Available data differ on the loss of porosity with burial depth (Atwater and Miller, 1965; Philipp et al., 1963). Much of the silica may come from outside the porous sand, such as from shales whose pore water is traversing the sand as a result of compaction. Authigenic clay minerals such as kaolinite also form in the pores.

Interstitial water in deeply buried sediments sometimes is at a pressure close to the weight of the overburden. This pressure may be sufficient to burst the rock and allow the water to move out through the fissures which it forms. These fissures are principally vertical and extend upward into zones of lower temperature. The water forming and subsequently filling the fissures usually is a mixture of salty interstitial sedimentary pore water and water from the clay minerals released by their recrystallization. If it is hot, and saturated with silica and other minerals, it could force its way upward and as it cools deposit quartz, feldspar, calcite, and other minerals. Possibly many hydrothermal ore veins were formed by interstitial sedimentary waters rather than by “juvenile” waters.

These hydrothermal veins contain metallic minerals composed of compounds containing copper, zinc, lead, gold, and silver. The process is a geothermal convection cell and it is able to concentrate and segregate useful minerals. The process has many points of resemblance to the concentration and segregation of petroleum - the principal difference being that the geothermal convection cells operate at higher temperatures.


Petroleum and natural gas

The total amount of organic matter dispersed in the sedimentary rocks of the earth has been estimated to be about 2,700 trillion metric tons; of this amount 50 trillion metric tons are dispersed petroleum hydrocarbons, of which 0.5 trillion metric tons exist in petroleum reservoirs (Hunt, 1968). The types of hydrocarbons in a petroleum often indicate its origin; for example, if it contains predominately odd-numbered n-alkanes in the low molecular-weight range, it probably was formed from marine organisms. Petroleums from the Uinta Basin contain a predominance of odd-numbered hydrocarbons in the vax fraction, indicating a nonmarine organic source. Waxes derived from land plants contain a predominance of hydrocarbons with carbon numbers of C27, CZ9, and C31, while hydrocarbons derived from marine plankton may contain more hydrocarbons with carbon numbers of

The water in the sediments containing the organic matter contains many dissolved organic constituents such as salts of the humic, fatty, and naphthenic acids, sugars, heterocyclics, and aromatic oxygen compounds. Degens et al. (1964) observed that as the salt concentration in petroleum- associated waters increases, the concentration of dissolved amino acids increases.

Petroleum is generated in organic-rich shales, but the mechanisms whereby it migrates from the shales and concentrates in porous reservoir rocks are not understood. Petroleum precursors leave the shale with the water as the water is expelled by compaction.

As burial proceeds, pressures and temperatures increase. With increasing temperature, chemical changes in the solids are accelerated and the organic matter first generates petroleum, which ultimately is converted to methane and finally graphite. The clay minerals continue their recrystallization, and finally metamorphism to slates, phyllites, and schists occurs: These processes involve a continuing loss of porosity with the release of additional pore water.

The solubility of petroleum hydrocarbons in water increases with increasing temperature and pressure. However, at ambient temperature and pressure the solubility in pure water is rather low (McAuliffe, 1969). Water- wet shale has no permeability to immiscible fluids such as gas or oil, so the petroleum or petroleum precursors probably do not move as droplets. Peake and Hodgson (1966) report “accommodations” of specific hydrocarbons in water up to about 30 ppm. Cartmill and Dickey (1970) found that a colloidal suspension was able to pass through water-wet sands, but the tiny droplets coalesced at points where the grain size decreased. Neruchev and Kovacheva (1965) offered some evidence that the amount of extractable hydrocarbon decreases in shales for the first few meters away from the reservoir rocks, as if removed by some flushing action.

Bruderer (1956) suggested that oil deposits originated from sea water

c17, and c19.

SEDIMENTARY ROCKS 21 1

containing dissolved hydrocarbons, which subsequently deposited them in sedimentary reservoir ,rocks. Al’tovskii et al. (1961) believe that petroleum forms in subsurface formation waters and moves to traps as an emulsion or in aqueous solution. Movement of hydrocarbons from the source bed to the reservoir via aqueous solution or as molecular films was postulated by Brod (1960). Baker (1960) suggested that, as the sediments compact, the expressed water may contain solubilizers capable of releasing sediment hydrocarbons into aqueous colloidal solution, and subsequent changes in the aqueous equilibria cause the colloids to become oil droplets in reservoirs.

The soluble salts of adenosine triphosphate are capable of solubilizing numerous inorganic and organic compounds in neutral or slightly alkaline medium and of keeping these compounds in solution (Mandl et al., 1952). Hydrocarbon solubilization processes are essential to the migration of petroleum and acquired evidence indicates that nature provides solubilizing agents. Numerous solvents are evaluated by Mandl (1953), many of which are useful agents for solubilizing relatively insoluble inorganic and organic compounds.

Organic as well as inorganic compounds will enter the aqueous phase to the limit of their solubilities. Interactions of the solubilized compounds affect the solubility product of other solubilized compounds. For example, the presence of dissolved sodium chloride may inhibit or increase the solubility of a normal alkane. For any given system, equilibria of all components will be attained only at a given temperature and pressure. If the temperature changes, if the pressure changes, or if more inorganic or organic constituents are added or subtracted, the equilibria will change causing solubilization or deposition.

Hydrocarbons can exist in the aqueous phase as emulsions or colloids, as suspended particles, or in true solution. Suspended particles will settle from an aqueous phase because of gravity, whereas colloids will remain in suspension. Suspended particles possess colligative effects, but colloidal sols do not (Van Nostrand Press, 1958). A dissolved particle usually is smaller than 5 mp, while colloidal particles usually range in size from 0.25 mp to 6 mp.

Phenols and alkalinaphthenates capable of acting as emulsifying agents and causing oil-in-water emulsion to migrate have been detected in crude oils and in the associated brines (Neumann and Jobelius, 1967). It has been demonstrated that finite amounts of paraffinic, aromatic, napthenic hydrocarbons and other organic derivatives are dispersed in recent marine sediments (Smith, 1954). Surfactant organic acids stabilize hydrocarbon particles of relatively large size and contribute to solubilization and subsequent migration of hydrocarbons from sediments (Baker, 1960). A shift in the equilibria caused by a pH or Eh change, adsorption of the surfactant, etc., results in deposition of the pseudo-soluble hydrocarbon. Therefore, solubilization and mobilization of hydrocarbons from sediments into the aqueous phase occurs when the equilibria are shifted to the correct conditions. Subsequent migration of the hydrocarbons in the aqueous phase


occurs if the equilibria in the aqueous phase remain constant while the water moves through the sedimentary rocks. Deposition or accumulation of hydrocarbons occurs if the equilibria in the aqueous phase shifted, causing desolubilization or precipitation of the hydrocarbons.

Temperature gradients in sedimentary basins usually are about 1°C per 46 m of depth, and the rate of heat flow to the surface is approximately 1.2 x loV6 cal cmV2 sec-I (Birch, 1954). Temperature is believed to be a primary cause in the conversion of organic matter in rocks to petroleum (Philippi, 1965), it is also believed that lipids are the major precursors of petroleum and that most petroleum is generated by chemical reactions occurring at temperatures above 115°C.

Nonmarine sources are recognized for many crude oils, in contrast to the once general belief that such sources are unfavorable for the generation of petroleum. Perhaps the best known examples in the United States are the nonmarine sequences in the Eocene of the Uinta Basin in Utah. Other examples of oil and gas with continental source sediments are basins such as the Dzungaria, Tsaidam, Tarim, Turfan, Ordos, Pre-Nan Shan, and Sungliao of China (Meyerhoff, 1970). There is considerable nonmarine Tertiary age strata in the Cook Inlet-Kena Basin in coastal Alaska.

TABLE 7.IV

Tertiary system - highest concentration of a constituent found, average concentration. and number of samples analyzed

Constituent Concentration (mg/l) Number of samples

highest average

Lithium Sodium Potassium Rubidium Cesium Calcium Magnesium Strontium Barium Boron Copper Chloride Bromide Iodide Bicarbonate Carbonate Sulfate Organic acid

as acetic Ammonium

27 103,000

1,200 0.6 0.4

38,800 5,800

420 240 450

1 201,300

1,300 35

3,600 300

8,400

1,900 2,700

4 39,000

2 20 0.24 0.20

2,530 530 130

60 36

64,600 85 28

560 75

3 20

0.63

140 230

169 379 176

11 9

37 6 368 142 140 170

3 380 323 322 3 64

8 139

53 64

COMPOSIDION OF OILFIELD WATERS 213

TABLE 7.V

Cretaceous system - highest concentration of a constituent found, average concentration, and number of samples analyzed


highest average

Lithium 13 4 26 Sodium 88,600 31,000 987 Potassium 580 130 38 Rubidium 0.10 0.10 1 Cesium 0.10 0.10 1 Calcium 37,400 7,000 987 Magnesium 8,000 900 987 Strontium 980 200 39 Barium 67 0 40 34 Boron 70 20 38 Chloride 187,000 62,OOb 987 Bromide 1,760 550 173 Iodide 190 25 172 Bicarbonate 1,660 260 864 Sulfate 7,100 280 776 Ammonium 35 23 2

Composition of oilfield waters

To illustrate the variety of oilfield waters found in subsurface petroleum- bearing formations, samples were taken, and analyzed, from formations of the following ages: Tertiary, Cretaceous, Jurassic, Permian, Pennsylvanian, Mississippian, Devonian, Silurian, Ordovician, and Cambrian. Insufficient samples from Triassic age strata were available. These data are given in Tables 7.IV-XIII, and all of the samples were taken from sedimentary basins in the United States. Each table gives the highest value found in this study in milligrams per liter for a given constituent, the average values, and the number of samples used to estimate the average value. The constituents determined for most of the brines include lithium, sodium, potassium, rubidium, cesium, calcium, magnesium, strontium, barium, boron, copper, chloride, bromide, iodide, bicarbonate, carbonate, sulfate, organic acid as acetic (actually organic acid salts but calculated as acetic acid), and ammonium.

Comparison of the lithium content in the samples from Tertiary age strata (Table 7.IV) with the lithium content of sea water (Table 7.1), indicates that the average lithium content of 169 oilfield waters is enriched by a factor of 20. At least one sample of oilfield water contained 27 mg/l of lithium or an enrichment factor of 135 compared t o sea water. Table 7.11 indicates that igneous rocks contain up to 65 ppm of lithium and sedimentary rocks contain up to 46 ppm of lithium.

21 4 ORIGIN OF OILFIELD WATERS

TABLE 7.VI

Jurassic system - highest concentration of a constituent found, average concentration, and number of samples analyzed


highest average -

Lithium 400 10 80 Sodium 120,000 57,300 85 Potassium 900 140 9 Rubidium 0.10 0.10 1 Cesium 0.10 0.10 1 Calcium 56,300 25,800 85 Magnesium 5,200 2,500 84 Strontium 2,080 320 9 Barium 50 10 7 Boron 50 13 9 Chloride 210,000 141,000 85 Bromide 6,000 1,200 80 Iodide 40 16 8 Bicarbonate 2,640 140 72 Sulfate 1,480 21 0 78 Organic acid

as acetic 12 12 1

TABLE 7.VII

Permian system - highest concentration of a constituent found, average concentration, and number of samples analyzed

Constituent Concentration (mg/l) Number of samples -

highest average

Lithium 6 3 3 Sodium 109,000 47,000 54 Potassium 40 5 170 3 Rubidium 2 0.80 3 Cesium 0.20 0.13 3 Calcium 22,800 8,600 54 Magnesium 5,800 2,000 53 Strontium 10 7 3 Boron 20 8 3 Copper 0.88 0.88 1 Chloride 177,000 92,700 64 Bromide 68 46 3 Iodide 3 3 1 Bicarbonate 281 77 49 Carbonate 36 36 1 Sulfate 3,400 7 30 41 Organic acid

as acetic 2 20 170 2 Ammonium 24 24 3

COMPOSITION OF OILFIELD WATERS 21 5

TABLE 7.VIII

Pennsylvanian system - highest concentration of a constituent found, average concentration, and number of samples analyzed


Lithium Sodium Potassium Rubidium Cesium Calcium Magnesium Strontium Barium Boron Manganese Chloride Bromide Iodide Bicarbonate Carbonate Sulfate Organic acid

as acetic Ammonium

highest average

35 101,000

710 2.30 8.50

205,000 15,000

4,500 640

70 105

270,000 3,900 1,410 1,200

70 5,400

2,300 3,300

7 43,000

170 0.55 0.15

9,100 1,900

600 30 15 60

87,600 490 210 130

40 430

430 300

45 951

57 25 19

9 50 947

70 41 54

2 950

57 52

897 2

7 56

44 51

Table 7.V indicates that oilfield water samples taken from Cretaceous age strata were enriched in lithium with respect to sea-water. The highest lithium concentration found in 26 samples was 13 mg/l.

Table 7.VI indicates that oilfield waters taken from Jurassic age strata contain up to 400 mg/l of lithium, which, compared with sea water (Table 7.1), represents a concentration factor of 2,000. Compared to the hydrolyzates in sedimentary rocks (Table 7.11), the concentration factor is about 9.

The lithium concentration in oilfield waters taken from Permian age strata averaged 3 mg/l (Table 7.VII). Only three samples were available for use in determining this average.

Table 7.VIII indicates that the lithium concentration averaged 7 mg/l in 45 samples taken from Pennsylvanian age strata. This represents a concentration factor of 35 compared with sea water (Table 7.1).

Table 7.IX indicates that the lithium concentration in oilfield waters taken from Mississippian age strata is enriched by a factor of 45 compared with sea water. Table 7.X indicates a similar enrichment factor of 250 for oilfield waters taken from Devonian age strata. For waters from Silurian age strata (Table 7.XI) the enrichment factor found was 185; for the Ordovician


TABLE 7.IX

Mississippian system - highest concentration of a constituent found, average concentration, and number of samples analyzed


highest average

Lithium Sodium Potassium Rubidium Cesium Calcium Magnesium Strontium Barium Boron Copper Manganese Chloride Bromide Iodide Bicarbonate Carbonate Sulfate Organic acid

as acetic Ammonium

55 115,800

5,000 5 2

37,800 11,200

3,390 20

240 3

36 206,000

1,800 620

1,590 450

3,500

3,070 700

9 41,500

430 1 0.40

8,900 1,600

630 5

40 3

12 85,000

410 110 185 450 5 40

370 210

81 210

80 47 37

209 202

52 44 86

2 5

210 88 89

198 1

191

84 83

age (Table 7.XII), it was 100; and for the Cambrian age (Table 7.X111), it was 85.

The data in Tables 7.VI-XI11 indicate that waters taken from sediments that formed during the various geologic ages do not all have the same chemical composition and that the waters have evolved considerably in comparison to modern sea water composition (Table 7.1). The manner whereby this evolution occurred is not completely understood; however, recent studies have shed some light on the problem. Note the amount of organic acid as acetic found in waters taken from the sedimentary rocks (Tables 7.VI-XIII). The organic acids are present in the oilfield waters as organic acid salts. These organic compounds possibly are a precursor of petroleum and serve as a transportation mechanism for migration. The exact composition of each organic acid salt has not been determined. Knowledge of the composition of these organic acid salts would aid in geochemical studies of petroleum.

Rittenhouse et al. (1969) studied the minor elements in 823 oilfield-water samples taken from subsurface formations in the United States and Canada. The data that they found are shown in Table 7.XIV as 25% quartiles, median concentrations, and 75% quartiles. The dissolved solids are given in grams per

COMPOSITION OF OILFIELD WATERS 217

TABLE 7.X

Devonian system - highest concentration of a constituent found, average concentration, and number of samples analyzed


highest average ~~

Lit hi um Sodium Potassium Rubidium Cesium Calcium Magnesium Strontium Barium Boron Copper Manganese Chloride Bromide Iodide Bicarbonate Carbonate Sulfate Organic acid

as acetic Ammonium

170 101,000

11,600 11

129,000 26,000

2,300 120

90 2

200 259,000

3,500 120

1,000 60

1,700

67 0 560

1.4

50 48,000

3,100 4 0.5

18,000 2,900 1,000

40 30

2 175

115,000 1,060

30 155

30 450

130 110

29 85 30 12 11 85 82 8 7

30 1 2

85 32 32 67

2 74

27 32

liter, the data followed by p are given in parts per billion (ppb), and the other data are given in parts per million. They analyzed samples from several basins as illustrated in Table 7.XIV, and the elements analyzed included lithium, magnesium, manganese, nickel, cobalt, chromium, copper, potassium, tin, strontium, titanium, vanadium, and zirconium.

Rittenhouse et al. (1969) concluded that elements in oilfield waters commonly are present in the following concentrations:

5% Na, C1 5% or ppm Ca, SO4 > 100 ppm K, Sr 1-100 ppm ppb (most oilfield waters) ppb (some oilfield waters)

Al, B, Ba, Fe, Li Cr, Cu, Mn, Ni, Sn, Ti, Zr Be, Co, Ga, Ge, Pb, V, W, Zn

They found no relationship between the constituents in the brine and the minerals in the aquifer rocks except for potassium. They postulated that exchange reactions occurred between the clays in the rocks and potassium in the water to control the dissolved potasssium.


TABLE 7.XI

Silurian system - highest concentration of a constituent found, average concentration, and number of samples analyzed


highest average -

Lithium 90 37 8 Sodium 89,000 49,100 14 Potassium 8,400 1,900 11 Rubidium 8 4 2 Cesium 0.4 0.4 2 Calcium 41,000 21,000 14 Magnesium 12,000 4,300 12 Strontium 880 7 30 2 Barium 15 15 1 Boron 90 30 10 Chloride 195,000 122,000 14 Bromide 1,700 520 11 Iodide 30 17 10 Bicarbonate 27 0 115 11 Sulfate 3,500 830 13 Organic acid

as acetic 220 90 9 Ammonium 20 0 80 10

TABLE 7.XII

Ordovician system - highest concentration of a constituent found, average concentration, and number of samples analyzed


Lithium Sodium Potassium Rubidium Cesium Calcium Magnesium Strontium Barium Boron Manganese Chloride Bromide Iodide Bicarbonate Carbonate Sulfate Organic acid

as acetic Ammonium

highest average

70 89,100

2,890 6 0.5

39,000 10,900

900 10 80 56

205,600 7 20

70 2,260

60 7,600

3,300 630

20 31,000

990 2 0.2

6,100 1,300

340 6

20 56

62,000 300

25 270 25

1,070

5 20 140

15 609

15 11 9

609 607

12 10 18 1

609 19 16

598 26

583

14 16

RESEARCH STUDIES 21 9

TABLE 7.XIII

Cambrian system - highest concentration of a constituent round, average concentration, and number of samples analyzed

Constituent Concentration (mg/l) Number of samples _______--__ ~- - ~ __

highest average ._____ ~ _ _ _

Lithium 40 17 8 Sodium 43,000 23,400 23 Potassium 2,000 440 10 Rubidium 3.3 3.3 1 Cesium 0.6 0.6 1 Calcium 14,500 4,000 23

Strontium 3 60 125 7 Boron 13 7 5 Chloride 95,000 46,100 23 Bromide 1,170 520 5 Iodide 40 18 3 Bicarbonate 790 260 23 Sulfate 2,600 1,170 22 Organic acid

as acetic 50 30 3 Ammonium 120 60 3

Magnesium 8,800 1,300 22

Compared with sea water the 823 brines were enriched in manganese, lithium, chromium, and strontium, and depleted in tin, nickel, magnesium, and potassium. Generally the silicon content varied inversely with the dissolved solids content. This agrees with a study of the solubilities of silicate minerals where Collins (1969b) found that in general the silicon solubilities decreased with increasing concentrations of dissolved salts at ambient conditions.

Research studies related to the origin of oilfield brines

Tables 7.IV-XIV indicate that the compositions of oilfield brines are not consistent, and that they are not formed by the simple evaporation or dilution of sea water. Oilfield brines are found in deep formations that sometimes contain fresher water nearer surface outcrop areas, in formations containing evaporites or in close proximity to soluble minerals, and in formations close to surface saline waters.

The amounts and ratios of the constituents dissolved in oilfield waters are dependent upon the origin of the water and what has occurred to the water since entering the subsurface environment. For example, some subsurface waters found in deep sediments were trapped during sedimentation, while other subsurface waters have infiltrated from the surface through outcrops.

N ES 0

TABLE 7.XIV

Minor elements in 823 oilfield brine samples in United States and Canada*'

Number Lithium Magnesium Manganese Nickel Tin of samples q25 md q75 q25 md q75 q25 md q75 q25 md q75 q25 md q75

Illinois Basin Louisiana and Texas Gulf Coast East Texas North Texas West Texas and New Mexico Permian only Pennsylvanian only Silurian and Devonian only Ordovician and Cambrian only Anadarko Basin*' Williston Basin, post- Paleozoic Williston Basin, Paleozoic Powder River Basin Other Wyoming Colorado California Sea Water Estimated detection limit

22

79 88 24

148 74 34

15

21 118

25

55 22 28 18

116

- -

10

ND ND ND

3 2 3

4

10 ND

ND

18 ND ND ND ND

15 25

ND 4 ND ND ND 15

15 25 10 25 10 20

10 25

15 25 10 35

ND 10

35 50 ND 2 ND 45 ND ND ND ND 0.1

2

3,000

15 150

3,000

500 500 50 0

200

500 900

10

300 10 20

< 10 35

6,000

250 250

5,000

1,000 1,000 1,000

400

800 1,550

250

600 40

100 30 90

1,272

10

8,000

550 800

6,000

1,650

1,500

560

1,000 3,000

2,000

2,000 225 200 300 175

2,000

8Op 175p 750p

8OOp 3.5 >5,OOOp 1 ,800~ 3.3 >5,OOOp

25 45 90

2OOp 1.8 >5,OOOp 18Op 1.7 >5,OOOp 500p 2.8 >5,OOOp

30p 300p >5,OOOp

150p 400p >5,OOOp 600p 5.6 >5,OOOp

9Op 300p 450p

2OOp 660p 1 , 2 0 0 ~ 300p 450p 2 ,000~ 60p 300p 1,000~ 9Op 300p 750p

300p 950p 2 ,800~ lp-lop

1P

ND ND ND

< l p < 3p ND < 1P 3p ND

15p 150p ND

< l p < l p ND < 1P 3p ND < l p < l p <Ip

< l p < l p ND

< l p < l p <1 6p 15p ND

< 3p < 3p ND

ND < 3p ND < 3p < 3p ND ND 3p ND < 3p < 3p ND

lop 35p ND 5.4p

1P

< 1P 5P

< 1P 1P 3P 1 lP

< 1P 3P < 1P 3P < 1P 3P

IP 5P

IP 4P 2P 4P

< l p < l p

< l p < l p < l p < l p < l p < l p <lop <lop

3P

1P

12p 25p

2 . 5 ~ 4 . 5 ~

_ _ _ ~ - ___ *' Medium (md - Rittenhouse et al., 1969) and quartile (9) concentrations in each area; ND = below detection limits; p = concentration in ppb, otherwise ppm. ** No data, less sensitive methods of analysis used. *3 Includes Oklahoma Platform and Ardmore Basin.

TABLE 7.XIV (continued)*'

Illinois Basin Louisiana and Texas Gulf Coast East Texas North Texas West Texas and New Mexico Permian only Pennsylvanian only Silurian and Devonian only Ordovician and Cambrian only Anadarko Basin*3 Williston Basin, post- Paleozoic Williston Basin, Paleozoic Powder River Basin Other Wyoming Colorado California Sea water Estimated detection limit _ _ - .-.

Number Dissolved solids (gll) of samples

22

79 88 24

148 74 34

15

21 118

25

55 22 28 18 116 -

-

70

30 27 173

61 70 80

42

53 51

9

115 3 4 3 5

md

98

69 66

222

111 143 115

55

67 137

59

173 5 5 5 18 35

-

-

- q75

Cobalt

119

131 116 24 1

173 215 168

72

128 203

88

296 11 11 15 30

ND

ND

ND

ND ND ND

ND

ND ND

ND

ND

ND ND ND

N D * ~

<5P

md

ND

ND

ND

ND ND ND

ND

ND ND

~

N D * ~

<5P

<5P

<5P

ND

ND

ND 0.27~

1P

q75 ~

ND

<5P N D * ~ ND

ND ND ND

ND

<5P

<5P

ND <5P ND <5P 2P

ND

Chromium

~

~

q75

Copper Potassium

md q75

- q25 md q75

3P

< 2P 2P 35P

4P 4P 4P

4P

3P

< 2P

< 6~

2 5 ~

1 5 ~

20

<lop

< 1P 25P

<25p

ND ND ND

< 1P N 4 < 1P <25p

ND <25p ND

lop 75p

<25p <25p < 1 < 1 150p 450p

1P 10P 2P 10P

< 1P 5P

4~ 1 5 ~

4~ 1 5 ~ lop 25p

<25p 2Op

3P 5P <25p 70p ND 30

180 300 400

160 300 400 ND <50 300 ND 300 1,000

120 350 500 160 400 750 200 300 400

170 300 450

200 400 650 20 250 500

200 300 400

.400 800 <5,000 200 300 400 ND 300 700

ND < 6; <25p <25p <25p 200 300 400 5p 15p 2p 5p 2Op ND 45 70

0.04~-0.07~ lp-15p 380

IP 1P 50 ~~

* ' Medium (md - Rittenhouse et al., 1969)and quartile (4) concentrations in each area; ND = below detection 1imits;p = concentration in ppb, otherwise ppm. *' No data, less sensitive methods of analysis used. *3 Includes Oklahoma Platform and Ardmore Basin.

to to to

Illinois Basin Louisiana and Texas Gulf Coast East Texas North Texas West Texas and New Mexico Permian only Pennsylvanian only Silurian and Devonian only Ordovician and Cambrian only Anadarko Basin Williston Basin, postPaleozoic Williston Basin, Paleozoic Powder River Basin Other Wyoming Colorado California Sea water Estimated detection limit

~ -

Number Strontium Titanium Vanadium of samples q25 md q75 q25 md q75 q25 md

__. ~ _____. -

22

79 88 24

148 74 34

15

21 118

25

55 22 28 18

116 -

-

140

45 75

150

1 5 65

180

75

100 90

20

50 ND

10 7

ND

300 400 < lop

85 200 ND 350 750 ND 450 700 <lop

200 400 ND 90 300 ND

300 450 ND

90 300 < lop

250 400 ND 300 650 ND

100 200 ND

95 450 <lop 25 50 <lop 20 45 ND 20 60 <lop

1 3

16

10 22 <lop

<1 op

<lop

7P

<lop <lop <lop

<lop

<lop <lop

ND

ND

< lop < lop < lop <1 op < lop

10P

present

-.

<lop

< lop < 1P 2OP

<lop <lop <lop

<lop

<lop <lop

<lop

25P <lop <I op < lop

7P

ND

ND ND ND

ND ND ND

ND

ND ND

ND

ND ND ND ND ND

Zirconium

q25 md q75

ND <lop <lop

<lop <lop < lop ND ND ND ND <lop l o p

ND ND ND ND ND <lop ND ND ND

ND ND ND

ND ND ND ND <lop 2Op

ND ND ND

ND ND <lop

ND ND ND ND <lop <lop ND ND ND

ND

<lop <lop <lop

1OP

*' Medium (md; from Rittenhouse et al., 1969) and quartile (4 ) concentrations in each area; ND = below detection limits; p = concentration

** No data, less sensitive methods of analysis used. *3 Includes Oklahoma Platform and Ardmore Basin.

in ppb, otherwise ppm.

RESEARCH STUDIES 223

Some waters are mixtures of the infiltration water and trapped ancient sea water.. Also, the rocks containing the waters often contain soluble constituents which dissolve in the waters or contain chemicals which will exchange with chemicals dissolved in the waters causing alterations of the dissolved constituents.

The amounts of dissolved constituents found in oilfield waters range from less than 10,000 mg/l to more than 350,000 mg/l. This salinity distribution is dependent upon several factors including hydraulic gradients, depth of occurrence, distance from outcrops, mobility of the dissolved chemical elements, soluble material in the associated rocks, ion exchange reactions, and clay membrane filtration.

Concentration of sea water can occur by surface evaporation, and there are at least three independent processes that can cause major changes in buried, isolated sea water:

(1) Dilution with meteoric or fresher waters which have entered outcrops. (2) Reactions with minerals in the sediments and sedimentary rocks (the

(3) Membrane filtration through clays and shales as a result of pressure reactions are often temperature and pressure dependent).

and osmosis.

Playa deposits

Jones et al. (1969) studied the composition of brines in shallow, fine- grained playa deposits in the Great Basin. The concentrations of dissolved solids in the water in these sediments often were as much as five times greater than in the water in the associated lakes. They attributed the concentration processes to capillary evaporation and entrapment of fossil brines when the salinity of the lake water was greater (lake nearly dry).

Continental Slope drill holes

Manheim and Bischoff (1969) analyzed pore waters from drill holes on the Continental Slope of the northern Gulf of Mexico. A relationship between the salinities of the waters and the proximity of diapiric structures was found. This indicated that salts are leached from salt-bearing sediments to increase the salinities of the pore waters. In some samples the high bromide and potassium concentrations suggested that late-stage evaporitic minerals such as carnallite and polyhalite were leached from salt bodies. They postulated that molecular diffusion is a major mechanism which influences the distribution of salt in the pore waters. Similar conclusions have been made for saline waters in other areas.

Relation to petroleum accumulations

Van Everdingen (1968) suggested that major circulation systems of for-


mation water exist in the Western Canada Sedimentary Basin, that the flow systems affected accumulations of hydrocarbons in the basin, and further that pressure and salinity variations might be explained by membrane properties of the shales. He saw a need for studies of the hydrodynamics of the basin.

Hydrodynamics and geochemistry of the Paradox Basin were studied by Hanshaw and Hill (1969). The ground-water movement in the basin is generally southwestward from the high outcrop areas in western Colorado, flowing toward the Colorado River discharge areas. Hydrodynamic conditions exist in lower Paleozoic strata which are favorable to accumulations of petroleum in stratigraphic traps. Paleozoic aquifers in northwestern New Mexico have very high potentiometric surfaces and these aquifers may be the outflow receptors of an osmotic membrane system operating within the San Juan Basin. This regional study was excellent and of value in exploration for petroleum and gas.

Parker (1969) studied brines and waters in five aquifers of Cretaceous age in the East Texas Basin. He found that the composition of the waters in the older, more deeply buried aquifers were modified more than waters in younger, less deeply buried aquifers. Most of the modifications were made by exchange reactions, dilution by meteoric waters, and loss of sulfate because of bacterial reduction. Hydrodynamic movement of the waters in the Woodbine formation contributed to the giant oil accumulation in the East Texas Basin. Much of the stratigraphic trapped oil probably was trapped in part because of this type of flow.

Sabkha sediments and transport of valuable ores

Bush (1970) discussed the origin of chloride-rich brines from Sabkha sediments and how they are related t o inclusion brines and lead-zinc deposits of the type found in the Mississippi Valley. He noted that Helgeson (1964) and Barnes and Czamanske (1967) have shown that chloride-rich scrlutions can transport lead and zinc as chloride complexes. According t o Bush (1970), Sabkha brines free of sulfur are expelled by sediment compaction, migrate, and become enriched in base metals until they contact a zone of higher temperature and pressure. In this zone, sulfides are present as a result either of inorganic reduction of sulfate, anaerobic reduction, or hydrocarbon reduction of anhydrite. The sulfides cause the base metals to precipitate.

Formation brines are the medium in which several metals, in addition to hydrocarbons, migrate prior to deposition in ore deposits. A current theory is that the metals travel primarily as chloride complexes in solutions that are depleted in reduced sulfur species (Dunham, 1970). The metals subsequently are precipitated when a source of reduced sulfur is met. An example of a source of reduced sulfur is an area where anaerobic bacteria are reducing sulfate. This occurs in waters near petroleum-bearing formations, and such waters in carbonate reservoirs often contain considerable amounts of sulfide.


Brine classification

A study of the evolution of subsurface brines in Israel by Bentor (1969) led him to classify brines into four groups. The first group consists of brines similar to sea water except for an increased concentration of calcium and a decreased concentration of magnesium, which he attributed to dolomitization. The second group was similar t o sea water but contained two to three times higher concentrations of dissolved salts, deficient in sulfate and magnesium, and enriched in bromide and iodide. The sulfates were lost by organic reduction, the magnesium was lost by exchange reactions with clays, and bromide and iodide were added by organic sources. The third group was a high-salinity calcium chloride-type brine formed by surface evaporation and later modified in the subsurface by differential ultrafiltration, The fourth group was a highly saline, calcium chloride type with Ca/Na ratios greater than one. This group was divided into two subgroups where the first subgroup is a highly saline and highly differentiated Early Paleozoic brine, while in the second subgroup they are old Paleozoic brines which were submitted t o an additional cycle of surface concentration by evaporation.

Ion association

Truesdell and Jones (1969) studied ion association in brines and found that, except for the chloride ion, the major simple ions form ion pairs, while the minor and trace metals in brines form coordination complexes. Selective ion electrodes can be used to determine directly the ionic activities of sodium, potassium, chloride, fluoride, and sulfide in brines. Experimental data were used t o calculate chemical models for ion association and coordination complexes in brines. These models are useful in explaining the chemical behavior of brines.

Relation to lithology

Kramer (1969) used factor analysis to study the relationships of the brines to the type of rock from which they were taken. His results indicated that the major ions in most brines are sodium, calcium, and chloride; brines are enriched in calcium and bicarbonate and are deficient in magnesium and sulfate relative to sea water. The factor groupings did not reflect the lithology of the rocks from which the brines were taken, indicating that such a relationship does not exist or is difficult to detect. The brine analyses used in the study were primarily macro analyses and did not include pH, minor, or trace constituents. A study of this type would benefit significantly if the following conditions were met: (1) use only the best available sampling methods; (2) use field analysis techniques; (3) use positive lithology identification; and (4) use only the best available laboratory methods of analysis.


Kramer (1969) did not have these controls because he used only the published data of various laboratories.

Carpenter and Miller (1969) used statistical and thermodynamic methods in an effort to determine the origin of the dissolved chemical constituents in saline subsurface waters in north-central and northwestern Missouri. Statisti- cal analysis of scatter diagrams indicated that the concentrations of lithium, sodium, potassium, and bromide and the ion activity ratios of K+/H+, Ca+’/Mg+*, and Sr+’ /Ba+’ in the waters are influenced by reactions with constituents in the aquifer rocks. They concluded that the ion ratios are of little value in determining the origin of the waters because the concentrations of the dissolved constituents in the waters had reacted with minerals in the aquifer rocks. This study was excellent because it did show that the concentrations of constituents in the water are controlled to some extent by reactions with the aquifer rocks. Additional work of this kind is needed in the study of deep brines.

A study of brines from the Sylvania formation in the Michigan Basin indicated that evaporation and dolomitization were two dominant controls for their dissolved concentrations of calcium, magnesium, sodium, strontium, and bromide (Egleson and Querio, 1969). Mechanisms responsible for concentrations of elements such as potassium, lithium, rubidium, ammonia, boron, and iodide were believed to be reactions with sedimentary rocks, leaching of organic constituents, and bioconcentration.

Relation to depth and salinity

A study of the chemical composition of some selected Kansas brines indicated that in general the concentrations of calcium, sodium, and chloride increase with increasing salinity, while the sulfate concentrations decrease (Dingman and Angino, 1969). However, the Ca/C1 ratio, concentrations of calcium and salinity, did not generally increase with geologic age or with depth of the aquifer.

Dickey (1969) surveyed the analyses of oilfield waters from many areas of the United States and concluded that in general the Ca/Mg ratio increases with increasing salinity while the ratio Na/(Ca + Mg) decreases irregularly with increasing. salinity and depth. This observation is compatible with the findings of several investigators. The dominant anion in subsurface waters usually changes with depth; in near-surface waters, it is sulfate; at depths exceeding 520 m it is bicarbonate; and in deep brines, it is chloride (Chebotarev, 1964). The Ca/Na ratio usually increases with depth and age of the associated rocks, while the Mg/Na ratio decreases.

Iodide

Collins (1969a) studied the chemistry of some oilfield brines from the Anadarko Basin which contain high concentrations of iodide. The concen-


trations of bromide in many of these brines are lower than the iodide which is unusual. Localized sedimantary rock deposits enriched in organic iodine are the source of the high iodide concentrations in these brines (Collins et al., 1971).

Hot brines

Hot brines containing minor and trace amounts of several metallic elements in addition to macro concentrations of some alkalies, alkaline earths, and chloride are found in drill holes in southern California, in the Caspian Sea, and in deeps in the Red Sea. These brines were formed from evaporites dissolved by meteoric water, and the metallic elements were leached from country rocks by the hot brines (Tooms, 1970). Laboratory reactions of 2M and 4M sodium chloride with andesite and shale at 300"-500°C have produced solutions containing metallic elements in concentrations similar to the hot brines (Ellis, 1968).

Comparison of oilfield brines with evaporated sea water

Bromide does not form its own minerals when sea water evaporates. I t forms an isomorphous admixture with chloride in the precipitates (Valyashko, 1956; Braitsch and Herrmann, 1963). As sea water evaporates, the carbonates precipitate first, followed by the sulfates. Little or no bromide precipitates, or if it does, it is occluded with these.

Halite (NaCl) begins to precipitate when the chloride concentration is about 275,000 mg/l (Table 7.111) compared with that of normal sea water, 19,000 mg/l. Some bromide is entrained with chloride in the precipitate.

300

.- C

Normal evaporite curve/ c 2oo t

Fig. 7.4. Use of the bromide ion to differentiate some Tertiary (T), Cretaceous (C), and Jurassic (J) age brines.


TABLE 7 .XV

Bioconcentrated bromide and iodide in seaweeds and corals

Bromide (ppm) Iodide (ppm)

Seaweed Laminaria digitata (dry matter) 1,380 Laminaria saccharina (dry matter) 340 Desmaresta (ash) 6,800

Corals* Gorgonia uerrucosa Gorgonellidae Isididae

16,200 19,800 7,400

5 10-8,000 2,000 5,200

69,200 22,100 20,300

* After Vinogradov (1953).

However, with each crystallization, more bromide is left in solution than is entrained in the precipitate.

Sylvite (KC1) begins to precipitate when the chloride concentration is about 360,000 mg/l (Table 7.111), followed by carnallite (MgC12 *KCI *6H2 0) and bischoffite (MgC12 *6H, 0). During evaporation the concentration rate of bromide in solution increases. The change in the slope of the curve in Fig. 7.4 illustrates this approximately.

Other concentration mechanisms operate to account for the high bromide concentrations (6,000 mg/l and up) found in some brines. One of the mechanisms is related to bioconcentrators such as seaweeds and corals. The seaweeds and corals concentrate the bromide, they die, and are buried with the sediments. Later the bromide is leached by the surrounding waters. Table 7.XV illustrates some of the concentrations of bromide and iodide that Vinogradov (1953) found in various seaweeds and corals.

Laboratory experiments have demonstrated that bromide is accommodated in the halite crystal lattice and replaces chloride in solid solution (Borchert and Muir, L964). The weight percentage of bromide in solid solution in the halite lattice is related to its weight percentage in the parent brine as :

wt.% Br (in halite) wt.% Br (in solution)

where C = the pa@ition coefficient. In most natural environments C = 0.14 (Braitsch and Herrmann, 1964).

In a marine salt sequence the wt.% Br/NaCl rises from about 0.007 wt.% at the bottom to 0.02 wt.% at the beginning of potassium precipitation. How- ever, the bromide concentration with a given natural halite sequence may vary considerably, even though theoretically it should increase continuously

C =


from the bottom to the top of the depositional strata. These variations can be attributed to inflow of fresh sea water during the deposition or subsequent leaching after deposition. Rittenhouse (1967) developed a method to classify oilfield waters based upon the bromide concentrations.

Fig. 7.4 is a log-log plot of chloride versus bromide concentrations for some Louisiana oilfield waters. The T, C, and J on the figure refer to Terti- ary, Cretaceous, and Jurassic, indicating the ages of the rocks from which the waters were taken. The normal evaporite curve was plotted by using data from Table 7.111. The data in the figure indicate that most of the Tertiary waters are deficient in bromide when compared to an evaporite water, whereas the Cretaceous and Jurassic waters are enriched in bromide (Collins, 1967).

The Tertiary waters contain dissolved halite, which accounts for their low bromide concentration, while the waters that are enriched in bromide contain bitterns or have leached bromide from sediments that were enriched in bioconcentrated bromide.

The bromide content of oilfield brines can be used t o distinguish between brines that originated because of evaporation of sea water and those formed by the dissolution of evaporite minerals. This can be done by using Fig. 7.4. If the bromide concentration falls to the right of the normal evaporite curve, the brine contains evaporated sea water, while if it falls to the left of the curve, it contains dissolved evaporite minerals.

Fig.7.5 illustrates how closely the concentration of sodium of some Louisiana oilfield waters taken from Tertiary, Cretaceous, and Jurassic age rocks follow the sodium concentration of a brine associated with normal evaporation (Collins, 1970).

300 0 ,

200

- 100

W Normal evaporite curve

- 50

0 J

20

1 500

lo 5,000 10,000 20,000 ' &bob I llob!OOO

' 300

SODIUM, m g / l

Fig. 7.5. Relationships of the chloride concentrations to sodium concentrations in a normal evaporite brine to oilfield brines taken from formations of Tertiary (T), Cre- taceous (C), and Jurassic (J) age in the United States,


Ion exchange

Ion exchange reactions on clay minerals are reversible and they follow the law of mass action. The number of exchange sites governs the reaction, and other important factors include temperature, pressure, solution concentrations, and bonding strength of exchangeable ions. Ion exchange between clay minerals and a brine will stop when equilibrium is attained.

As the waters move in their subsurface environment, their dissolved ions have a tendency to exchange with those in the rocks. There are two extreme types of adsorption in addition to intermediate types of adsorption. The extreme types are: (1) a physical adsorption or Van der Waals adsorption with weak bonding between the adsorbent and the constituent adsorbed; and (2) a chemical adsorption with strong valence bonds.

Cations can be fixed at the surface and in the interior of minerals. These fixed cations can exchange with cations in the water. Under the right physical conditions of the adsorbent, similar exchange can occur with the anions. Some of the constituents in formations that are capable of exchange and adsorption are argillaceous minerals, zeolites, ferric hydroxide, and certain organic compounds.

Particle size influences the exchange rates and capacities if the solids are clays such as illite and kaolinite. The rate increases with decreasing particle size. However, if a larger mineral has a lattice, the exchange can easily occur on the plates. The concentration of exchangeable ions in the adsorbent and in the water is important. More exchange usually occurs when the solution is highly concentrated.

According to Grim (1952), the replacing power of some ions in clays is:

(1) In NH, , kaolinite:

Cs > Rb > K > Ba > Sr > Ca > Mg> H > Na > Li

(2) In NH, , montmorillonite: Cs > Rb > K > H > Sr > Ba > Mg> Ca> Na > Li

These two clays often are present in sedimentary rocks and the replacing order indicates that lithium and sodium are more likely to be left in solution, while cesium and rubidium are more likely t o be removed from solution.

Fig. 7.6 is a plot of the chloride content versus the lithium content of some oilfield waters taken from the Smackover formation. The .lithium enrichment results at least in part from exchange reactions on clays. Lithium has a small radius, a low atomic number, a larger hydrated radius than sodium, and a larger polarization than sodium. Because of these, its replacing power in the lattices of clay minerals is low (Kelley, 1948). Other ions such as barium, strontium, calcium, magnesium, cesium, rubidium, potassium, and sodium will preferentially replace lithium in clay minerals, thus releasing lithium to solutions. Furthermore, the solubility products of most lithium

RESEARCH STUDIES

1,000 C

A Louisiana

A Alabama o Arkansas

Texas

000

600 Mississippi

400

-

-

-

0 0

0

V

40 - 0

0

2 0 -

10 I I 1 I I , I I I I I I I I O I , I I 1 I I

d

23 1

3 0 0

2 0 0

- 100 m

w 2 5 0 0 4

3 30

2 0

\

19 5 0 0 1,000 2,000 5,000 10

POTASSIUM, mg/ I

, I 1 I I I , ] I 1 1 1 I I I L

C- J T

T

3 100 200 100

Fig. 7.7. Relationships of the concentrations of chloride and potassium in a normal evaporite-formed brine to oilfield brines taken from formations of Tertiary (T), Creta- ceous (C), and Jurassic (J) age in the United States.

compounds are higher than those of other alkalies and alkaline earths. There- fore lithium tends to stay in solution.

Fig. 7.7 compares the potassium concentration of some Louisiana oilfield waters with those of waters subjected to evaporation. All of these waters are depleted in potassium with respect to a brine subjected to evaporation, indicating that potassium was lost to the associated sediments during


diagenesis. It has been shown that a tendency exists for potassium to be adsorbed and fixed by clay minerals, mica, and potassium feldspar in normal low-temperature processes (White, 1965; Khitarov and Pugin, 1966; Grim, 1952).

The data in Tables 7..III-XIV indicate that the concentration of calcium in oilfield waters generally is enriched relative to sea water. Cation exchange reactions with clays accounts for some of this enrichment:

2Na+ (solution) + Ca (clay) + Ca+* (solution) + 2Na (clay)

Collins (1972) found that the ratio Na/(CL + Mg) tends to decrease as the dissolved solids concentration increases in some oilfield waters from the East Texas Basin. This depletion of sodium with respect to calcium plus magnesium was attributed to diagenesis of the waters and it correlated with an index of base exchange (Schoeller, 1955), indicating that the alkali metals in the waters exchanged with alkaline earth metals on the argillaceous minerals to decrease the dissolved alkali metals and increase the dissolved alkaline earth metals.

Fig . 7.8 is a plot of the calcium concentration in some oilfield waters taken from the Smackover formation. All of these waters are enriched in calcium relative to the evaporated sea water.

Krejci-Graf (1963) found that solutions predominantly concentrated in chloride can force an exchange of calcium and bromide from clay minerals for sodium and chloride from the solution. If this type of reaction occurred

3

Fig. 7.8. Relationships of the concentrations of chloride to calcium in an evaporite- formed brine to oilfield brines taken from the Smackover formation in five states of the United states.


1,000 000 600

400

- 200 \ 0

w 0 100, 5 80 I 60

40 V

20

- - 6 Louisiana - Mississippi - A Alabama - 0 Arkansas

0 Texas -

101I<I I I I I 1 1 1 1 1 1 ' I ' I ' l ' ' ' 1 ' I ' 100 200 400 1,000 2,000 4,000 10,000 40,000

BROMIDE, mg/l

Fig. 7.9. Relationships of the concentrations of chloride to bromide in an evaporite- formed brine to oilfield brines taken from the Smackover formation in five states of the United States.

to the Smackover brines, it explains their enrichment of calcium and bromide.

Kozin (1960) wrote about a "reverse" exchange of anions when the cations exchange on clays:

C1- (solution) + Br (clay) + Br- (solution) + C1 (clay)

Such a reaction also helps to account for the bromide enrichment found in most oilfield waters taken from the Smackover formation (Fig. 7.9).

A similar reaction for iodide:

C1- (solution) + I (clay) -, I- (solution) + C1 (clay)

would help explain the tremendous enrichment of iodide in oilfield brines (Collins, 1969a) with respect t o sea water as demonstrated in Tables 7.1 V-XIII.

Fig. 7.10 shows that boron usually is enriched relative to the normal evaporite curve in Smackover oilfield brines. Boron, like lithium, has a small radius, a low atomic number, and large polarization. Therefore, its replacing power in the lattices of clay minerals is low. Also, boron does not have a tendency to enter silicate lattices of the common rock-forming minerals. Because of these factors, it usually remains in solution until late-stage crystallization.


1,000 000 600

400-

200 - \ w

: 100: LL 00- 2 60- 0

40

20

- -

- A Louisiana - Mississippi

A Alabama 0 Arkansas 0 Texas

-

-

-

BORON, mg/l

Fig. 7.10. Relationships of the concentrations of chloride to boron in an evaporite- formed brine to oilfield brines taken from the Smackover formation in five states of the United States.

Mineral formation

A study of some brines taken from Devonian age reservoir rocks indicated that dolomitization probably is the most important mechanism in determining the calcium, strontium, and magnesium content of these brines (Egleson and Querio, 1969). It also was concluded that the relative amounts of ammonium, iodide, and lithium in these brines were too high to be derived directly from sea water, and the ammonium and iodide probably were enriched in the brines as a result of bioconcentration and subsequent leaching of organic debris.

Dolostone deposits owe their origin to hypersaline brines (Friedman and Sanders, 1967). Some dolomite, including diagenetic and epigenetic forms, originates from subsurface brines. In the geologic columns in several oil-

TABLE 7.XVI

Approximate sea-water composition before and after gypsum precipitation (mg/l)

Io n Before precipitation After precipitation

Calcium Magnesium Bromide Sulfate

390 1,300

65 2,580

0 1,300

65 2,580


TABLE 7.XVII

Approximate sea-water composition after dolomitization or bacterial reduction (mg/l)

Ion After dolomitization After bacterial reduction

Calcium Magnesium Bromide Sulfate

0 883 65 0

0 1,300

65 0

productive basins, mixtures of dolomite and anhydrite occur, which indicates that sulfate may have been removed from the associated waters by dolomitization as well as by bacterial reduction.

Table 7.XVI illustrates the approximate amounts of calcium, magnesium, bromide, and sulfate that could exist in a water’before and after precipitation of gypsum.

Assuming that the residual sulfate (1,644 mg/l) was removed by the dolomitization reaction:

MgC12 + 2CaC0, += CaC12 + CaMg(C0, )* - - CaC12- + MgS04- += CaS04 + MgCi2 MgSO, + 2CaC03 + CaS04 + CaMg(C0, ) 2

then the Mg/Br ratio would be about 883/65 = 13.6, as illustrated by the data in Table 7.XVII. However, if the residual sulfate was removed by bacterial reduction :

C,H, + Na2 SO4 + Na2C03 + H2S + C02 + H 2 0

the Mg/Br ratio would be about 1300/65 = 20. Magnesium will react with CaC03 (calcite) to form dolomite, thus in-

creasing the concentration of calcium in the brine. However, the total calcium plus magnesium in the brine should remain constant. This can be calculated as (24.31/40.08) x mg/l calcium + mg/l magnesium = total equivalent magnesium or Mg’. The ratio Mg’/Mg will vary, depending upon the availability of calcite, and the ratio should be indicative of the degree of dolomitization.

For example, brines that are in equilibrium with sandstones should have a relatively low Mg’/Mg ratio, those in equilibrium with dolomite should have higher ratios, and those in equilibrium with limestone should have the highest ratios. The average ratio for some Smackover brines is 7 (Table 7.XVIII), which indicates that the brines were in equilibrium with limestone and dolomite. Brines from some Tertiary age rocks which were primarily


TABLE 7.XVIII

Concentration ratios and excess factor ratios for some constituents in Smackover brines

Constituent Average composition (mg/l) Concentration Excess Number of ratio*' factor*' Smackover

sea water Smackover samples brines

Lithium Sodium Potassium Calcium Magnesium Strontium Barium Boron Copper Iron Manganese Chloride Bromide Iodide Sulfate Mg'*

0.2 10,600

380 400

1,300 8 0.03 4.8 0.003 0.01 0.002

19,000 65

2,690 1,543

0.05

17 4 66,975

2,841 34,534

3,465 1,924

23 134

41 30

171,686 3,126

25 446

24,362

1.1

870 6 8

86 3

241 767

28 359

4,049 14,957

9 48

501

16 0.2

18.1 0.1 0.2 1.8 0.1 5

16 0.6 7.5

84.2 31 1

0.2 1

10.4 0.003 0.3

71 283

82 284 280

85 73 71 64 90 69

284 74 73

27 1 284

*' Amount in brine/amount in sea water. ** Concentration ratio of a given constituent/concentration of bromide. *3 Mg' = (24.31/40.08) x mg/l Ca + mg/l Mg.

sandstone (Table 7.XIX) had an average ratio of 2.8, while brines from some Cretaceous age rocks had an average ratio of 6.0 (Table 7.XX).

Bromide does not form its own minerals when sea water evaporates. Some of it is lost from solution because it forms an isomorphous admixture with chloride with the halite precipitate. However, more bromide is left in solution than is entrained in the precipitate. Therefore, relative t o chloride, the bromide concentration in the brine increases exponentially. Bemuse of this, the bromide concentration in the brine is a good indicator of the degree of sea water concentration, assuming that appreciable quantities of biogenic bromide have not been introduced.

Table 7.XVIII presents data that were obtained by comparing the average composition of some Smackover brines with that of sea water. The concentration ratio was calculated by taking the mean average for a given constituent in the Smackover brines and dividing it by the amount of the constituent found in normal sea water. The excess factor was determined by dividing the concentration ratio of a constituent by the concentration ratio of bromide. The calculation for Mg' or total equivalent magnesium was previously explained, and the number of Smackover samples indicates how


TABLE 7.XIX

Concentration ratios of some constituents in some brines taken from Tertiary age rocks

Constituent Average composition (mg/l) Concentration Excess ratio*' factor * '

sea water Tertiary brines

Lithium 0.2 3 15 12.5 Sodium 10,600 37,539 3.5 2.9 Potassium 380 226 0.6 0.5

Magnesium 1,300 686 0.5 0.4 Strontium 8 148 18.6 15.5 Barium 0.03 73 2,439 2,033 Boron 4.8 20 4.1 3.4 Chloride 19,000 63,992 3.4 2.8 Bromide 65 79 1.2 1 Iodide 0.05 21 426 355 Sulfate 2,690 104 0.03 0.03 Mg' 1,543 1,947 1.3 1.1

Calcium 400 2,077 5.2 4.3

*' Amount in brine/amount in sea water. *' Concentration ratio of a given constituent/concentration of brymide. *3 Magnesium e,quivalent of calcium plus magnesium in brine: Mg = (24.31/40.08) x mg/l

Ca + mg/l Mg .

TABLE 7.XX

Concentration ratios of some constituents in some brines taken from Cretaceous age rocks

Constituent Average concentration (mg/l) Concentration Excess ratio*' factor*'

sea water Cretaceous brines

Lithium Sodium Potassium Calcium Magnesium Strontium Barium Boron Chloride Bromide Iodide Sulfate Mg'*3

0.2 10,600

380 400

1,300 8 0.03 4.8

19,000 65

2,690 1,543

0.05

4 28,462

193

606 346

4,999

48.3 27.5

54,910 287 37

206 3,643

20 2.7 0.5

12.5 0.5

43.3

5.7 2.9 4.4

0.1 2.4

1,608

737

4.5 0.6 0.1 2.8 0.1 9.8

1.3 0.7 1

168 0.02 0.5

365

*' Amount in brinelamount in sea water. *' Concentration ratio of a given constituentlconcentration of brymide. *' Magnesium equivalent of calcium plus magnesium in brine: Mg = (24.31/40.08) x mg/l

Ca + mg/l Mg .


1,000 800 600

400

\ - cn 200

W*

5 80- I 60

40

g 100:

0

20

10

many samples were used in the calculation. For example, 71 Smackover brines were analyzed for lithium, while 283 were analyzed for sodium.

The concentration ratios (Table 7.XVIII) indicate that all of the determined constituents in the Smackover brines were enriched with respect to sea water except sulfate. However, the excess factor ratios indicate that sodium, potassium, magnesium, chloride, sulfate, and total equivalent magnesium were depleted in the Smackover brines, while lithium, calcium, strontium, barium, copper, iron, manganese, and iodide were enriched. Further, these ratios indicate that the Smackover brines have been altered considerably if it is assumed that they originally were sea water.

The concentration ratio 48 for bromide (Table 7.XVIII) is one of the highest that this author has seen. For example, bromide concentration ratios of 1.2 (Table 7.XIX), 4.4 (Table 7.XX), and 8.8 and 7.2 were found for brines from Tertiary, Cretaceous, Pennsylvanian, and Mississippian age rocks (Collins, 1967, 1969a, 1970). The concentration ratios and excess factors in Tables 7.XIX and XX indicate several constituents are enriched and several are depleted in these brines also.

Almost one-third of the magnesium in sea water and subsequent bitterns can be removed during the dolomitization reaction. The formation of chlorite from montmorillonite requires about 9.2 moles of MgO per mole of chlorite (Eckhardt, 1958):

- - a Louisiana

Mississippi - - A Alabama

0 Arkansas

- o a */ 0 Texas

‘Normal evaporite curve -

- 0

-

I I I I I I I I I 1 1 6 1 I I I I I I 1 1 8 1 I I I

1.7 A1203 0.9 MgO 8 Si02 - 2 H 2 0 + 9.2 MgO + 6 H 2 0 +=

10.1 MgO 1.7 A1203 6.4 Si02 * 8 H 2 0 + 1.6 Si02

00

Fig. 7.11. Relationships of the concentrations of chloride to magnesium in an evaporite- formed brine to oilfield brines taken from the Smackover formation in five states of the United States.


1,000 000 600

400

- 2 00 \ 0

100

2 60

40

: 00 0

2 0

0

0

0

Louisiana Mississippi Alabama Arkansas Texas

0 0 0 4, 0

0 0

00

Fig. 7.12. Relationships of chloride to strontium in an evaporite-formed brine to oilfield brines taken from the Smackover formation in five states of the United States.

Such a reaction could remove large amounts of magnesium from waters. Hiltabrand (1970) has shown that contemporary argillaceous sediments can remove 100 mg/l of magnesium from sea waters.

Fig. 7.11 is a plot of the chloride concentrations versus the magnesium concentrations in some oilfield waters taken from the Smackover formation. The figure indicates that the Smackover waters are depleted in the concentration of magnesium with respect to an evaporite-formed brine. Tables 7.111-XI11 indicate that in general oilfield waters taken from rocks of other formations also are depleted in magnesium. The data also show that generally as the dissolved magnesium decreases the dissolved calcium increases. This is related t o the formation of minerals such as chlorite or dolomite and t o exchange reactions with argillaceous minerals. It is not a result of solubility because most magnesium compounds are more soluble than calcium compounds.

Fig. 7.12 is a plot of the concentration of chloride versus the concentration of strontium found in some oilfield brines taken from the Smackover formation. This figure indicates that the strontium concentration is enriched in the Smackover brines relative to sea water. Reactions that account for some of this enrichment are:

2SrC03 + MgCl, +. SrMg(C03), + SrCl, SrMg(C0, ), + MgCl, +. 2MgC0, + SrC1,

The data in Fig. 7.7 and Tables 7.111-XIV indicate that the concentration

Montmorillonite-type minerals systematically change t o illite with depth of potassium in oilfield waters generally is depleted relative to sea water.


in Gulf Coast shales (Burst, 1969). As a result of this transformation, the montmorillonite-type minerals lose interlayer water. Laboratory experiments at elevated temperatures and pressures indicate that montmorillonite loses its interlayer water and transforms into illite in the presence of potassium- enriched water (Khitarov and Pugin, 1966). The structural variations of the expandable minerals in clays also are apparently influenced by the potassium content of the associated waters. This indicates that oilfield waters tend to become depleted in potassium content where this reaction occurs.

Reactions between brines and minerals to form silicates that account for the depletion of dissolved alkali metals are:

3A1, Si2 O5 (OH), + 2K+ * 2KA13 Si, Ol0 (OH), + 3H2 0 + 2H+ KA13Si030,0(OH)2 + 6Si02 + 2K+ + 3KA1Si308 + 2H+ A12 Si205 (OH), + 4sio2 + 2Na+ =+ 2NaA1Si308 + H2 0 + 2H+

These reactions account not only for the depletion of potassium or sodium, but also for a decrease in pH because of the release of hydrogen ions. The decrease in pH enables the water t o dissolve metallic metals, to convert bicarbonate to carbon dioxide, or to convert bisulfide t o sulfide. The Smackover brines often contain relatively high concentrations of sulfide.

Several investigators have attempted to determine what mechanism is responsible for the increased concentration of calcium and depletion of magnesium relative to sea water in many subsurface brines. Chave (1960) and Von Engelhardt (1960) compared ocean water with subsurface brines containing high concentrations of calcium, and demonstrated that dolomitization cannot account for all of the calcium in the brine solutions. Von Engelhardt (1960) noted that even the formation of chlorite utilizing magnesium with exchange of sodium and calcium does not account for all of the soluble calcium; however, exchange reactions with other clays were not considered. Kramer (1963) assumed that calcium was more abundant in ancient oceans, but White (1965) found this relation to be untenable and suggested that shale-membrane filtration accounts for increased concentrations of calcium in some brines. Additional data are needed before more definite conclusions can be made. The amounts and ratios of calcium and magnesium vary from one formation water to another as well as within one formation at different geographic areas. Mineral formation, exchange reactions, leaching, and shale-membrane filtration all can alter the composition of the brine. However, in a specific area, one type of reaction may predominate.

Mem brane-concen tra ted brines

Essentially the postulate that clays and shales act as membranes t o filter dissolved solids from waters results from the fact that synthetic membranes are used to desalinate waters by reverse osmosis. Conceivably, compacted clays and shales may perform as imperfect semipermeable membranes. Solu-


tions of salts of different concentrations separated by a semipermeable membrane will cause water from the lower salt-concentration side t o move through the membrahe to the higher concentration side, producing a greater pressure on the high-concentration side. The pressure differential is the osmotic pressure of the system and can account for abnormal pressures found in some reservoirs.

Reverse osmosis occurs when hydraulic pressure in excess of the osmotic pressure is applied to the high-concentration side, which forces water through the membrane to the low-concentration side. The system is not 100% effective and some dissolved solids move through the membrane (Kimura and Souriragan, 1967).

Such a system requires rather high pressure differentials in nature to produce the highly concentrated brines found in some formations. The osmotic pressure could produce pressure differentials in formations, but the pressure comes t o equilibrium as the two solutions equilibrate. The reverse osmosis system works only as long as the excess hydraulic pressure is applied. In the absence of the excess hydraulic pressure, the system comes to equilibrium.

Larson (1967) reported some desalination results for water with reverse osmosis using cellulose-acetate membranes. With a brackish water containing about 4,300 mg/l of dissolved solids, input pressure of 42 kg/cm2 and temperature of 15.g0C, the ion rejection rates were as high as 99.9%. The rejection order based on the percent rejected was:

Ca+’ + Mg+’ > HC03-2 + SO4-’ > C1-> Na+ > NO3-

Assuming that this mechanism operates in a shale filtration system, the order of ion concentration on the high brine concentration side would be the same. The ion concentrations on the fresher water side would be the reverse or :

NO3- > Na+ > Cl- > SO4-’ + HC03-* > Ca+’ + Mg+’

Other investigators have obtained similar results. For example, Loeb and Manjikian (1965) found a rejection order of SO4-’ > Mg+’ > Ca+’ > Na+ > HC03- > C1- > NO3-. Michaels et al. (1965) found a rejection order of Ca+2 > Li+ > Na+ > K+ for the pressure independent portion of salt transport in cellulose acetate reverse osmosis desalination membranes. This correlates with the size of the hydrated ion radii because calcium is the largest and potassium the smallest. Further, this indicates that the pore size of the membrane is a controlling factor.

The data ‘of Larson (1967) showed that sulfate and carbonate scale formed on the high-pressure side of the membrane and if not removed would cause flow to decrease or stop. The pH on the output or fresh-water side of the membrane decreased.


Russell (1933) considered several processes which could produce subsurface brines more concentrated than sea water. He concluded that evaporation of the water by natural gas generally is not important, water evaporation in coarse-grained rocks generally is not important, gravitational settling of dissolved solids is not greatly important, rocks containing considerable amounts of feldspars and other unstable minerals take up large quantities of hydration water, clays adsorb bases and later expel them into solution causing concentration, and osmosis may occur through semipermeable membranes.

DeSitter (1947) noted that oilfield waters are altered as a result of two prominent diagenetic phases. During the first phase magnesium, calcium, sulfate, and carbonate precipitate from the original sea water. During the second phase the concentration of magnesium and calcium ions increases along with the concentration of other dissolved solids. He reasoned that the second phase occurred because of filtration through semipermeable shales.

The filtration results because of sediment compaction until a semipermeable membrane develops which allows water molecules t o pass through but retards salt ions. Thus, the more concentrated brines are found where sediment compaction and water flow distance were the greatest. This usually occurs in the deepest portion of a basin.

McKelvey et al. (1957) forced aqueous saline solutions through ion- exchange resins and found that the effluent solutions contained less dissolved salts than the influent solutions. Effluents from cation-exchange resins were found to contain Na/K ratios similar to those in the influent; however, the Mg/Ca ratios were at first higher than in the influent but with additional squeezing the ratio decreased to much lower values. They postulated that similar reactions occur during the compaction of sediments to change the concentrations of constituents dissolved in waters.

Pressures of 7 kg/cm2 to 105 kg/cm2 were applied t o force sodium chloride solutions through cation-exchange membranes. The results indicated that the membranes desalted the saline solutions, producing a filtrate containing less salt than the influent. This salt filtering effect was attributed to the electrical properties of the membrane.

Milne et al. (1964) determined the filtering efficiencies of sodium chloride solutions by bentonite membranes. The filtration efficiencies were 94% at 140 kg/cm2 and 88% at 703 kg/cm2 with 0.5N sodium chloride. Increased salinity caused less efficient filtration because filtration efficiencies of 94% for 0.W sodium chloride and 66% for 4N sodium chloride at a pressure of 352 kg/cm2 were obtained. A similar mechanism could operate in the subsurface to create concentrated brines.

Young and Low (1965) performed an experiment using natural rock and demonstrated that osmotic flow of water through shale and siltstone occurs. The osmotic pressures produced were less than theoretical and they were attributed to microcracks in the natural rock which caused them to be less effective than a perfect membrane.


Bredehoeft et al. (1963) developed a mathematical model to predict the distribution of ions within a formation. They assumed that a hydrostatic head differential opetates between the margin and center of a geologic basin, producing a water movement upward through confining low permeability beds. If these low permeability beds contain clay membranes to restrict the passage of ions, the waters on the upflow, or more permeable, side become more concentrated in dissolved solids. They theorized that this process produced the concentrated brines found in the Illinois Basin, and that their model added weight to the membrane theory of brine concentration. A major drawback to the model is the tremendous pressures that are necessary to produce a movement of water upward through confining low permeability beds.

Graf et al. (1965) found that isotopic fractionation occurred when waters passed through shale micropores in the Illinois, Michigan, Alberta, and Gulf Coast Basins. Their study did not yield sufficient evidence to estimate the total fraction of water movement in the basins subsequent t o sediment compaction. The 6 "0 concentrations in brines did not indicate a direct correlation with ancient oceans.

A study of the 6D and 6l80 in formation waters indicated that the water was predominantly meteoric, little exchange or fractionation had occurred to alter the deuterium, but extensive exchange between the water and rock had altered the oxygen (Clayton et al., 1966). They postulated that formation waters in the Gulf Coast Basin lost their original connate water because of sediment compaction and flushing, and that the present water is meteoric water which came in through outcrops.

This study was good; however, basic studies concerning the fractionation and exchange of isotopes between water, hydrocarbons, and rocks need to be made. Results of such studies should enable more positive interpretations.

A simplistic model was derived to determine the amounts of fresh water and sea water necessary to create the brine compositions now present in the Illinois and Michigan Basins (Graf et al., 1966). The model assumes: (1) perfect efficiency of shale ultrafilters; (2) complete bacterial reduction of sulfate with replacement in solution of equivalent bicarbonate; (3) complete removal of bicarbonate and equivalent sodium by shale ultrafiltration; and (4) magnesium reaction with calcium carbonate to form dolomite. The dolomitization reaction furnished more soluble calcium than is possible for the Illinois Basin, so another calculation was made assuming complete loss of magnesium to clay minerals with no return of calcium.

The calculations indicated that less fresh water passed through the rocks of the Illinois Basin than those of the Michigan Basin. These data conflicted somewhat with Clayton et al. (1966) in that they argued that the water molecules now in the Illinois Basin originated as fresh water, while the data of Graf et al. (1966) indicated that too few volumes of fresh water passed through the Illinois Basin t o alter the brine significantly.

A study of the hydrodynamics of the Illinois Basin indicated that in


recent times, before pumpage, the differences in vertical head in the deep aquifers were insufficient t o cause upward flow through shale, resulting in ultrafiltration (Bond, 1972). In fact the head differentials were barely sufficient to enable upward flow through an open conduit.

Berry (1969) outlined the relative factors that influence membrane filtration in geologic environments. The membrane properties of shales are caused by the electrfcal properties of their clays and organic materials. Clays predominantly are cation exchangers with singly charged SiO- and AlOSi-% sites and minor anion exchanges with replaceable OH- ions. Divalent cations are adsorbed in preference to monovalent cations and sodium is hyperfiltratcd with respect t o lithium and strontium with respect to calcium, because of preferential adsorption of ions with ionic potentials most similar t o the ionic potential of the exchange site. The selectivity of hyperfiltration for the halogens is C1 > Br > I > F because of their substitution for O H in the clays. Thus, in waters concentrated by this process the Ca/Na, Na/Li, Sr/Ca, Cl/Br, Br/I, and I/F ratios should increase. These ratio increases have been found in some brine systems, but by no means in all systems.

Billings et al. (1969) found five types of formation waters in the Western Canada Sedimentary Basin and postulated the origin of two of the types. One type of water was formed by selective membrane filtration which produced waters containing high concentrations of dissolved solids. A second type was a mixture of membrane-concentrated formation water and bitterns formed after the precipitation of halite but before the precipitation of sylvite. They theorized that the alkalies were filtered selectively by clay- shale membranes, producing a concentrated brine, and that the relative concentration pattern is Rb > K > Na > Li. This pattern is the reverse of what occurs by ion exchange but is similar to the surface mobilities of cations along clay surfaces.

A detailed study of the Western Canada Sedimentary Basin, including a determination of the rock volume and pore volume (Hitchon, 1968), the effect of topography upon the fluid flow (Hitchon, 1969a), and the effect of geology upon the fluid flow (Hitchon, 1969b), strongly suggested that thermal, electro-osmotic, and chemico-osmotic forces are operating within the basin to affect the fluid energy gradients. Pressure differentials of about 98 kg/cm*along with salinity differences of 200,000 mg/l between formations in close proximity were found which suggest that chemico-osmotic forces are occurring.

Hitchon and Friedman (1969) used chemical analyses and stable-isotope analyses for hydrogen and oxygen for surface waters, shallow ground waters, and deep ground waters in a study of the origin of formation waters in the Western Canada Sedimentary Basin. They postulated that surface waters have mixed with diagenetically altered sea water to form the formation waters. Using mass balance data for the deuterium and dissolved solid contents of the formation waters, they calculated not only how much fresh water is

CONCLUSIONS 245

present in the modified sea water but also observed how it redistributed the dissolved solids t o prQduce salinity variations.

They concluded that formation waters result from mixing of surface waters with modified marine or nonmarine water in the subsurface rocks, that exchange of oxygen isotopes between the water and rock caused different water types in different basins, and that formation waters that have passed through shale ultrafilters are more depleted in deuterium.

A study of the Surat Basin showed that most of its hydrocarbon accumulations are associated with quasi-stagnant waters. The salinities of these quasi-stagnant waters were higher than were the salinities of the waters in the more dynamic recharge areas. The investigators postulated that these high salinity waters were formed by membrane filtration because of cross- formational flow and also that the hydrocarbon accumulations in these quasi-stagnant areas resulted from release of hydrocarbons mobilized by a moving water. The hydrocarbons were released because of the higher salinities of the waters in the quasi-stagnant areas (Hitchon and Hays, 1971).

A study of waters in sedimentary rocks of Neogene age in the northern Gulf of Mexico Basin was made by Jones (1969). The hydrologic conditions currently found in these sediments are similar to conditions that previously occurred in older sedimentary basins. Osmotic flow has a dominant influence upon the hydrology of normally and abnormally pressured aquifer systems in the northern Gulf Basin.

Jones (1969) found that many forces such as gravity, sediment diagenesis, different water salinities, ionic and molecular diffusion, different electrical potentials of sediments, thermal potentials, pressure, and osmotic membrane filtration affect the hydrology in this basin.

Fowler (1970) found that salinity variations within the Frio sands in the Chocolate Bayou field, Brazoria County, Texas, are the result of selective concentration of ions by shales acting as membranes. In this field, pressures seem to reflect the flow paths of the waters, and the greatest changes in pressures are found across shaly sections. Analyses of water samples from this field over a 28-year period indicate decreasing salinity with production time caused by dilution of the original brines by waters squeezed from the shales adjacent to the aquifers.

Chilingarian and Rieke (1969) reviewed the processes which can alter the chemical composition of formation waters. They concluded that most of the original water was sea water, and that the concentration process in many cases results from compaction and membrane filtration rather than evaporation. Their experimental results indicated that solutions squeezed out of rocks during compaction progressively decrease in dissolved solids concentrations with increasing depth.

Conclusions

The origin of oilfield waters is related to many natural processes. Initially,


meteoric water reacted with weathered rock, soil, and organic matter. The excess waters that did not penetrate the rock or soil caused the rock and soil to erode and channels formed through which the water could move more easily. Forces of gravity caused the water to move from areas of high potential to areas of low potential, and as the waters moved, the concentrations of dissolved solids in them increased. Some of these waters found their way to lakes and the sea. As they entered the lakes or seas their movement slowed, causing some of the suspended particles in them to deposit. Mixing of the waters with the more saline waters in the sea caused dissolved carbonate and organic compounds to precipitate.

Evaporation of the sea and lake waters caused other compounds such as sulfates t o precipitate. The pH of the waters changed slightly because of reactions with the atmosphere, the sediments, and other waters. Each pH change caused precipitation of compounds or dissolution of new compounds.

Some of the waters became highly concentrated in dissolved solids in the more shallow marine environments. Evaporites formed in these lagoons, pans, and exposed supratidal sabkhas. Evaporites also formed in deep-water basins when the salinity of the water at the bottom of the basin became sufficiently high.

The sediments were buried as additional sediments were deposited on them, and water surrounding the sediment particles also was buried. As the depth of burial increased, the sediments compacted and some of the water was squeezed out. Both the squeezed-out water and the remaining interstitial water reacted with minerals in the sediments to change the composition of the dissolved solids in the water and the composition of the sediments.

Mechanisms that cause the oilfield waters t o differ in composition from water originally deposited with the sediments include ion exchange, infiltrating waters, sediment leaching, mineral formation, sulfate reduction, and ultrafiltration through clay-shale membranes.

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Pirson, S.J., 1968. Redox log interprets reservoir potential. Oil Gas J., 66:6*75. Plumley, W.J., Risley, G.A., Graves, Jr., R.W. and Kaley, M.E., 1962. Energy index for

limestone interpretation and classification. In: W.E. Hem (Editor), Classification of Carbonate Rocks - Am. Assoc. Pet. Geol., Mem.1, pp.85-107.

Pollard, T.A. and Reichertz, P.O., 1952. Core-analysis practices - basic methods and new developments. Bull. Am. Assoc. Pet. Geol., 36:230-252.

Quaide, W., 1958. Claymineralsfrom salt concentration ponds. A m . J. Sci., 256:431-437. Rankama, K. and Sahama, T.G., 1950. Geochemistry. Chicago University Press, Chicago,

Riley, G.A., 1944. The carbon metabolism and photosynthetic efficiency of the earth as a

Rittenhouse, G., 1967. Bromine in oilfield waters and its use in determining possibilities

Rittenhouse, G., Fulton, R.B., Grabowski, R.J. and Bernard, J.L., 1969. Minor elements

Rosenqvist, I.T., 1962. The influence of physico-chemical factors upon the mechanical

Ross, C.S., 1943. Clays and soils in relation to geologic processes. J. Wash. Acad. Sci.,

Russell, W.L., 1933. Subsurface concentration of chloride brines. Bull. Am. Assoc. Pet.

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Stumm, W. and Morgan, J.J., 1970. Aquatic Chemistry. Wiley-Interscience, Div. of John

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Geol., 17:1213-1228.

219-246, 507-552.

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Wiley and Sons, New York, N.Y., 583 pp.


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Chapter 8. CLASSIFICATION OF OILFIELD WATERS

Classification of waters provides a basis for grouping closely related waters. Because the grouping is chemical, it is dependent upon the dissolved constituents found in the waters. Most of the classification systems developed to date have considered only the dissolved major inorganic constituents and have ignored the organic and the minor and trace inorganic constituents.

Waters as related to the earth are meteoric, surface, and subsurface. Sur- face waters can be fresh or saline if the amounts of dissolved constituents in the waters are used to classify them. For example, water from melting snow on a mountain top usually will contain small amounts of dissolved mineral matter and can be classified as fresh water, while water in an ocean will contain about 35,000 mg/l dissolved minerals and is classified as saline. Waters found in rivers connecting the mountain stream t o the ocean may contain varying amounts of dissolved constituents and depending upon the amounts can be classified as fresh or saline. In a similar manner, subsurface waters are classified as fresh or saline. Merely classifying a water as either fresh or saline does not provide a very useful classification. The dissolved constituents that are used in many classification systems depend upon the amounts or ratios of sodium, magnesium, calcium, carbonate, bicarbonate, sulfate, and chloride found in the water. The reason for this is that these are the ions that usually are determined or calculated in a water. (Sodium often is calculated from the difference found in the stoichiometric balance of the determined anions and cations.)

The amounts and ratios of these constituents in subsurface waters are dependent upon the origin of the water and what has occurred t o the water since entering the subsurface environment. For example, some subsurface waters found in deep sediments were trapped during sedimentation, while other subsurface waters have been diluted by infiltration of surface waters through outcrops. Some waters have been replaced by infiltration water. Also, rocks containing the waters often contain soluble constituents, which dissolve in the waters or contain chemicals which will exchange with chemicals dissolved in the waters causing alterations of the dissolved constituents.

The amounts of dissolved constituents found in subsurface waters can range from a few milligrams per liter t o more than 350,000 mg/L This salinity distribution is dependent upon several factors, including hydraulic gradients, depth of occurrence, distance from outcrops, mobility of the dissolved chemical elements, soluble material in the associated rocks, and the exchange reactions.

254 CLASSIFICATION OF OILFIELD WATERS

Portions of three classification systems (Palmer, 1911; Sulin, 1946; Schoeller, 1955) and Bojarski’s (1970) modification of Sulin’s system were applied to about 4,000 formation waters (U.S. Bureau of Mines, 1965). The waters were analyzed by standard methods (American Petroleum Institute, 1968). The results indicated that the classifications are useful in exploration and production problems.

Palmer’s classification

Palmer (1911) observed that the basic characteristics of natural waters are dependent upon their salinity (salts of strong acids) and alkalinity (salts of weak acids). Salts that cause salinity are those that are not hydrolyzed, while alkalinity is caused by free alkaline bases produced by the easily hydrolyz- able salts of weak bases.

All positive ions (cations) including hydrogen can cause salinity, but of the negative ions (anions), only the strong acids, (e.g., chloride, sulfate, and nitrate) can cause salinity. Because salinity is dependent upon the combined activity of the cations and anions and is limited by the reacting values of the strong acids, its value is determined by multiplying the total value of the strong acids by two.

Alkalinity is caused by free alkaline bases as a result of the hydrolytic action of water on dissolved bicarbonates and other weak acid salts. The alkalinity value is calculated by doubling the reacting values of the bases which exceed the reacting values of the strong acids.

The ions that commonly are found in waters comprise three groups: (a) alkalies (sodium, potassium, lithium), whose salts are easily soluble in water and do not cause hardness; (b) alkaline earths (magnesium, calcium, strontium, barium), whose salts cause hardness and many of which are sparingly soluble; and (c) hydrogen, whose salts are acids and cause acidity.

Geologists know what “strong alkalies”, “alkaline earths”, “strong acid radicles”, “weak acid radicles”, “ions”, and “reacting values” mean generally. To compare several analyses it usually is easier if they are made on a chemical basis. The. proportions of the various ions do not react in proportion to the various weights given in milligrams per liter but rather in proportion to their “capacity for reaction”, or “reaction value”. The reacting value of each ion is determined by multiplying the amount of each radicle by weight (mg/l) by its “reaction coefficient”, which is the valence of a radicle divided by its atomic weight.

The groups of the ions are determined by summing the reacting values of their members, and according to the predominance of reacting values of the groups, five special properties were designated by Palmer. To determine the special properties, the reacting values of a group of cations or anions are doubled so that the full value of a given special property is considered. The terms “primary” and “secondary” were used t o qualify the general proper-

PALMER’S CLASSIFICATION 25 5

ties of the water; e.g., the principal soluble decomposition products of the oldest rock formations are the alkalies (primary), while more recent rock formations are the principal source of the alkaline earths (secondary), This theory of Palmer’s that the terms primary and secondary are associated with the age of the rock should not necessarily be considered undisputably true, because primary salinity certainly can be acquired from other soluble material than that derived directly from decomposition products of the oldest rock formations.

The five special properties of water are: (1) Primary salinity (alkali salinity); that is, salinity not t o exceed twice

the sum of the reacting values of the radicles of the alkalies. (2) Secondary salinity (permanent hardness); that is, the excess (if any) of

salinity over primary salinity, not t o exceed twice the sum of the reacting values of the radicles of the alkaline earths group.

(3) Tertiary salinity (acidity); that is, the excess (if any) of salinity over primary and secondary salinity.

(4) Primary alkalinity (permanent alkalinity); that is, the excess (if any) of twice the sum of the reacting values of the alkalies over salinity.

(5) Secondary alkalinity (temporary alkalinity); that is, the excess (if any) of twice the sum of the reacting values of the radicles of the alkaline earths group over secondary salinity.

Reacting values in percent are used in this system. The percentage values are determined by summing the milliequivalents of all the ions, dividing the milliequivalents of a given ion by the sum of the total milliequivalents, and multiplying by 100. Waters are classified by numerical values of the relationships of anions to the cations, where a , b , and d represent the percentage values of the alkali cations, alkaline earth cations, and strong acid anions, respectively. Any one of the following five conditions may exist: d may be equal t o or less than a , greater than a and less than a + b y equal to a + b y or greater than a + b . Using these conditions, waters are classified into five classes :

Classl: d < a 2d = primary salinity 2(a - d ) = primary alkalinity 2b = secondary alkalinity

Class 2: d = a 2u or 2d = primary salinity 2b = secondary alkalinity

Class 3: d > a ; d < (a + b ) 2a = primary salinity 2(d - a ) = secondary salinity 2(a + b - d ) = secondary alkalinity


Class 4: d = (a + b ) 2a = primary salinity 2b = secondary salinity

Class 5: d > (a + b ) 2u = primary salinity 2b = secondary salinity 2(d - a - b ) = tertiary salinity (acidity)

These five classes of water are found in nature. Examples of the first three classes are various surface waters, sea water and brines represent class 4, while mine drainage waters and waters of volcanic origin fall in class 5 (Palmer, 1911).

Rogers (1917, 1919) studied oilfield waters of the San Joaquin Valley, California, and used the classification system of Palmer (1911). He found that generally the surface waters of the San Joaquin Valley possess secondary salinity rather than primary alkalinity, contain more sulfate than chloride, and contain low amounts of bicarbonate. With increasing depth, the subsurface waters decrease in secondary salinity until primary alkalinity becomes evident. Waters above an oil zone often contained hydrogen sulfide, which was attributed to reduction of sulfates by hydrocarbons, thus decreasing the amounts of sulfate and increasing the bicarbonate in the water, which Rogers called an altered water. Further he found that, in these altered waters in close proximity to hydrocarbon accumulations, chloride becomes relatively and absolutely important because of the residual chloride from the original (ancient) sea water chlorides as compared to waters above the oil zone which often are freshened because of a more hydrodynamic situation. Altered waters, according t o his definition, can have either primary alkalinity or secondary salinity depending upon their amounts of carbonate and chloride, but normal waters have only secondary salinity.

Elliott (1953) used the Palmer system t o determine the chemical characteristics of some Paleozoic age formation waters in Texas. He found that all of the waters in the group that he studied (about 70) contained predominant, primary salinity. Many of these waters contained appreciable concentrations of sulfate; one contained 5,800 mg/l sulfate, and many contained more than 2,000 mg/l. The calcium concentration ranged up to 13,000 mg/l while the bicarbonate concentrations ranged up t o 800 mg/l.

Ostroff (1967) used the Palmer classification to classify waters from several basins and t o compare this classification system with two other systems. He found that the Palmer system groups some of the constituents together that are not closely related chemically. Furthermore the system does not consider ionic concentrations or saturation conditions related t o sulfate or bicarbonate.

SULIN’S CLASSIFICATION 257

Sulin’s classification

Sulin (1 946), a Russian geochemist, proposed a classification system based upon various combinations of dissolved salts in the waters. The waters are described according to chemical type, subdivided into group, subgroup, and class. He found four basic environments of natural water distribution:

(1) Continental (terrestrial) conditions which promote the formation of sulfate waters. Such conditions supply soluble sulfate constituents to the water and the genetic type of such a water is “sulfate-sodium”.

(2) Continental conditions which promote the formation of sodium bicarbonate waters. The genetic type is “bicarbonate-sodium ”.

( 3 ) Marine conditions and the formation of a “chloride-magnesium ” type of water.

(4) Deep subsurface conditions within the earth’s crust and the formation of a “chloride-calcium ” type of water.

The first two types are characteristic of meteoric and/or artesian waters, the third of marine environments and evaporite sequences, and the fourth of deep stagnant conditions.

Types, groups, and subgroups

Water composition is expressed in milligram-equivalents of the separable ions, and the composition is calculated per 100 g of water. The percent of the sum of the equivalents is used to exclude the degree of water mineralization, and t o compare waters containing different amounts of dissolved solids.

The ratio Na/Cl expressed in the percent equivalent form determines the genetic water type. If the value is greater than one, sodium predominates over chloride and the excess sodium can be combined with sulfate or bicarbonate. Therefore waters with a Na/Cl ratio greater than one belong to the bicarbonate-sodium or the sulfate-sodium types. Sulin calculated sodium as the sum of all the alkalies (Li, K, Na etc.) and chloride as the sum of all the halides (Cl, Br, I).

The ratio (Na - C1)/S04, if greater than one, indicates that the water is the bicarbonate-sodium type, while if it is less than one it is the sulfate- sodium type. Similarly the ratio (Cl- Na)/Na if less than one indicates the chloride-magnesium type, but if greater than one it indicates the chloride- calcium type.

Water classes

Subdivision of the groups of waters were made by Sulin (1946) using the Palmer (1 911 ) characteristics, because these characteristics express the dissolved constituents in the waters in a generalized format. For example, the sum of the alkali chlorides and sulfates corresponds t o primary salinity, and the sum of the alkaline earth chlorides and sulfates corresponds to secondary


salinity and the sodium bicarbonate-calcium stage. N o sodium bicarbonate is present in sulfate-sodium, chloride-magnesium, or chloride-calcium types of water; therefore, these types are classified as follows:

(1) Class A2 : secondary alkalinity predominates (alkaline earth carbonates and bicarbonates).

(2) Class S2 : secondary salinity predominates (alkaline earth sulfates and chlorides).

(3) Class S, : primary salinity predominates (alkali sulfates and chlorides). (4) Class S,: tertiary salinity predominates (iron and aluminum sulfates

Bicarbonate-sodium type waters contain sodium bicarbonate and are

( 5 ) Class A2 : secondary alkalinity predominates (alkaline earth carbonates

(6) Class A , : primary alkalinity predominates (alkali carbonates and bicar-

(7) Class S, : primary salinity predominates (alkali chlorides and sulfates). (8) Class A, : tertiary alkalinity predominates (iron and aluminum carbon-

ates and bicarbonates). The water classification is expressed by use of a formula representing

decreasing values of the Palmer characteristics. For example, S, S2 A2 indicates that primary salinity is predominant and is followed by secondary salinity and secondary alkalinity. Therefore, the classes are subdivided into subclasses, and class S1 can include the subclass S, S2 A 2 , S1 A2 S2, S1 S2, and S, . Table 8.1 outlines Sulin’s method of water characterization. Table 8.11 briefly outlines the relative values of the coefficients which determine the four genetic types of waters.

The Palmer characteristics do not account for the interrelations between chloride and sulfate and between calcium and magnesium. Therefore, Sulin calculated the ratio SO4 /C1 and Ca/Mg to establish additional subgroups. The complete water characterization included the following: (a) water formula given in Palmer characteristics; (b) coefficients in percent equivalents for S04/C1 and Ca/Mg; (c) sum of the milligram equivalents per 100 g of water (Z r ) t o illustrate the degree of water mineralization; and (d) the genetic coefficients (Na - C1)/ SO4 and (Ca - Na)/Mg t o determine the water type, and Na/C1 t o determine related genetic types of water.

and chlorides and free strong acids).

classified as follows:

and bicarbonates).

bonates).

Hydrochemical indicators of hydrocarbons

Sulin (1946) noted that certain properties of subsurface waters were favorable indicators of hydrocarbon accumulations. The bicarbonate-sodium and chloride-calcium types of waters are widely found in oilfields. However, the chloride-calcium type is the more favorable indicator if it has the most characteristic composition plus certain minor or micro constituents. In general, he determined that hydrocarbon accumulations are most commonly

SULIN’S CLASSIFICATION 25 9

TABLE 8.1

Sulin’s method of water characterization

Na/Cl > 1 _____

(Na+ - C1-) > Bicarbonate-sodium type: so4 -2

< 1 (Na+ - C1-)

so,, -2 Sulfate-sodium type:

Bicarbonate group class A2

calcium subgroup magnesium subgroup

Sulfate group class S1

calcium subgroup magnesium subgroup sodium subgroup


class Sp

Chloride group class S1



class A2 sodium subgroup


sodium subgroup class S 1



sodium subgroup

sodium subgroup

Na/Cl < 1

(C1-- Na+) (Cl- - Na+) > Mg+2

< 1 Chloride-calcium type: Mg+’ Chloride-magnesium type:

Bicarbonate group class Aq


Sulfate group class s1



class S2




class S2






class s 2




class s 2

26 0 CLASSIFICATION OF OILFIELD WATERS

TABLE 8.11

Coefficients characterizing the genetic types of waters ~~

Type of water Na+/Cl- (Na’ - Cl-)/S04-2 (Cl-- Na+)/Mg+’

Chloride-calcium < 1 < O > 1 Chloride-magnesium < 1 < O < 1 Bicarbonate-sodium > 1 > 1 < O Sulfate-sodium > 1 < 1 < O

related t o water types in this order: chloride-calcium > bicarbonate-sodium > chloride-magnesium > sulfate-sodium. Most oilfield waters of the chloride-calcium type belong to the S1 S2 A2 class with a few in the S2 S, A2 class, while most oilfield bicarbonate-sodium waters belong to the S, A, A2 and A, S1 A2 classes.

Other significant indicators were grouped by Sulin; however, none of them can assure the existence of a hydrocarbon deposit, and certainly they cannot provide definite evidence of the size of the accumulation. The groups are as follows:

Group I: direct hydrocarbon indicators; for example, naphthenic acid salts and iodide. The naphthenic acids are more soluble in bicarbonate-sodium type waters and are related t o the composition of the hydrocarbon accumulation. Iodide is related to oil because it must have an organic origin. Sulin also noted the dissolved gases in the waters and considered the heavier hydrocarbons such as ethane and butane and the absence of oxygen as direct indicators.

Group 11: highly mineralized chloride-calcium or bicarbonate-sodium types of water containing reduced forms of sulfur are important indirect indicators of oil. The sulfate content should be low to indicate interaction with bituminous constituents and/or sulfate-reducing bacteria.

Group 111: in this group are constituents which have no genetic relationship to hydrocarbons but appear characteristic of waters that are related to hydrocarbon accumulations. The constituents are bromide, boron, barium, strontium, radium, and possibly fluoride.

Modification of Sulin’s system by Bojarski

Bojarski (1970) studied 400 water analyses and differentiated hydrochemical zones within basins in Poland that appear suitable for preservation of hydrocarbon deposits. He distinguished the waters as follows:

(1) Waters of the bicarbonate-sodium type. Such waters occur in the upper zone of a sedimentation basin, with “intense water exchange” (that is, a hydrodynamic situation where the waters are moving at a relatively fast geological rate), which promotes unfavorable conditions for the preservation of petroleum and natural gas deposits. The waters are defined by the ratio

MODIFICATION OF SULIN’S SYSTEM 26 1

(Na-Cl)/SO, >l. As Sulin (1946) noted, if the ratio Na/Cl in epm is greater than 1, the water contains more sodium than chloride and the excess sodium can react with sulfate or bicarbonate ions. Therefore, such waters belong to the bicarbonate-sodium or sulfate-sodium types. If the ratio (Na - C1)/S04 is greater than 1, it indicates an excess of sodium with respect t o both chloride and sulfate.

(2) Waters of the sulfate-sodium type with (Na - Cl)/S04 < 1. This ratio, if less than 1, indicates that all of the sodium will react with chloride or sulfate.

(3) Waters of the chloride-magnesium type with (Cl- Na)/Mg < 1. A ratio of this type indicates that all of the chloride will react with sodium and magnesiun. Such a water is characteristic of the transition zone between a hydrodynamic area which is becoming more hydrostatic in the deeper part of the basin, and the amount of dissolved bromide increases directly with the (Cl- Na)/Mg ratio.

(4) Waters of the chloride-calcium type with (Cl- Na)/Mg > 1. This ratio indicates an excess of chloride with respect t o sodium and magnesium, and the excess will react with calcium. This type of water occurs in deeper zones which are isolated from the influence of infiltration waters and are hydrostatic or almost hydrostatic.

Bojarski observed a large variation in the chemical composition in the chloride-calcium type of water and subdivided this type as follows:

(a) The first class, chloride-calcium I with Na/Cl > 0.85 characterizes an active hydrodynamic zone with considerable water movement. It is considered a zone of little prospect for the preservation of hydrocarbon deposits.

(b) The second class, chloride-calcium I1 with Na/C1 = 0.85-0.75, characterizes the transition zone between an active hydrodynamic zone and a more stable hydrostatic zone of the sedimentation basin, which is generally considered a poor zone for hydrocarbon preservation.

(c) The third class, chloride-calcium I11 with Na/Cl = 0.75-0.65 (0.60), characterizes favorable conditions for the preservation of hydrocarbon deposits.It is designated as a fairly favorable environment for the preservation of hydrocarbons.

(d) The fourth class, chloride-calcium IV with Na/C1 = 0.654.50, is characterized by complete isolation of the hydrocarbon accumulations as well as by the presence of residual waters. I t is considered a good zone for the preservation of hydrocarbons.

(e) The fifth class, chloride-calcium V with Na/C1 < 0.50, is characterized by the presence of ancient residual sea water which has been highly altered since original deposition, both in the concentration of dissolved solids and in the ratios of the dissolved constituents. Bojarski considers a zone of this type to be one of the most likely areas where hydrocarbons are accumulated. Additional characteristics of water associated with hydrocarbon accumulations are as follows: (1) iodide > 1 mg/l; (2) bromide > 300 mg/l (increasing


iodide and bromide concenbrations may point to a bitumen accumulation); (3) ratio Cl/Br < 350; and (4) SO4 x lOO/Cl< 1.

In addition to indicating the degree of alteration, bromide and iodide as biophile constituents play a decisive role in the classification Bojarski adopted. This followed because of the increased concentration of biophile elements in the waters accompanying a petroleum deposit. The concentration of iodide in the ground waters depends mainly on the organic substances, whereas the’concentration of bromide up t o a certain limit takes place in an inorganic medium, but an increase in bromide must be evaluated as a positive indication. In many waters accompanying petroleum deposits, large amounts of bromide and smaller amounts of iodide were detected, or vice versa. This probably is related t o the type of bituminous substances which absorb the individual biophile elements in different amounts.

Chebotarev’s classification

Chebotarev (1955), an Australian geochemist, classifies waters on the basis of dissolved bicarbonate, sulfate, and chloride, and he does not consider the acid waters or those that contain free sulfuric or hydrochloric acid. His fundamental assumption is that the anions are independent variables while the cations are dependent.

The geochemical types of waters are related t o the products of weathering. Table 8.111 illustrates the cycles and products that are produced by weathering. During the first cycle the igneous rocks are weathered allowing chloride, sulfate, calcium, sodium, silica, and magnesium to go into solution. The second cycle is the weathering of sedimentary rocks with the solution of more of the same products. The third cycle is the weathering of recent drift and yields of the above constituents plus aluminum and iron.

Table 8.IV illustrates Chebotarev’s (1955) geochemical classification of subsurface waters. The phase of weathering corresponds t o four phases of the solution and redistribution of the chemical constituents in the earth’s crust and correlates with their relative mobilities. He plotted the relative mobilities of nine chemical constituents using the mobility of chloride as 100%. From this four phases were obtained, namely: (1) chloride and sulfate 100% t o about 58% mobility; (2) calcium, sodium, magnesium and potassium 3% to about 1.2% mobility; (3) silica about 0.20% mobility; and (4) iron oxide and aluminum oxide, less than 0.05% mobility. The four phases of weathering correspond to the products of weathering shown in Table 8.IV and also to the cycles and products of weathering in Table 8.111. For example the fourth phase in Table 8.IV corresponds with the first cycle in Table 8.111.

The genetic types of water shown in the upper portion (A) of Table 8.IV do not correspond directly with the weathering phases since the genetic types overlap the phases. These genetic types are related to the accumulation products shown in Table 8.111. In the lower portion (B) of Table 8.IV are the

TABLE 8.111

b Cycles and types of products of weathering (after Chebotarev, 1955) rn

Cycles of First cycle (orthoeluvium) Second cycle (paraeluvium) Third cycle (Neoluvium) z weathering: from igneous and highly metamorphosed rocks from sedimentary rocks from Recent Drift rrl

is =iJ

Types of (1) coarse detrital (1) chloride-sulphate (1) detrital (1) chloride-sulphate (1) solonez and (1) chloride-sulphate 0 products (chiefly alluvial) gypsum bearing z

residual products accumulative products residual products accumulative products residual products accumulative products b

of weathering (2) calcareous (2) calcareous (2) siallitic (2) calcareous (2) leached supra- (2) CaC03 (under vegetation (chiefly colluvial (supra-calcareous chloride-sulphate calcareous cover) and proluvial) (siallitic)

(3) siallitic (3) siallitic (3) allitic (?) (3) unsaturated siallitic*2 (3) unsaturated siallitic (3) alumino- and ferri- calcareous chloride- siallitic*’ siliceous system sulphate

(4) a l l i t i ~ * ~ (lateritic crust of weathering)

*’ A large quantity of silica and much of its calcium and sodium compounds are removed; the aluminosilicates pass gradually into residual aluminosilicic acids,

*’ The action of carbonated atmospheric water is insufficient to replace the absorbed ions by hydrogen. *3 The accumulation of sesquioxides at the expense of the leaching out of the alkalis, alkaline earth, and silica.

i.e., acids of the kaolin type.

TABLE 8.IV

Geochemical classification of subsurface waters (after Chebotarev, 1955)

(A) Relationship of the products of weathering to the genetic types of water

Presumable phase of weathering Products of weathering Genetic types of water

Fourth phase

Third and partly second phases

Second and partly first phases

First phase

residual (orthoeluvium and detrital paraeluvium) bicarbonate (alkaline)

siallitic drift

calcareous accumulation

bicarbonate-chloride (alkaline-saline)

chloride-bicarbonate (saline-alkaline)

chloride-sulfate (saline)

chloride-sulphate accumulation chloride (saline)

(B) Geochemical groups of Waters

Major group Class Genetic types of Reacting value in percent of water water

H C 0 3 - + COB- Cl- SO4-’ Cl- + SO4-’ HC0,- + CI- HC03- + SOq-‘

Bicarbonate I bicarbonate >40

I1 bicarbonate-chloride 40-30

111 chloride-bicarbonate 30-15

Sulphate IV sulphate-chloride 15-5

- sulphate

Chloride 111 chloride-bicarbonate 30-15

IV chloride-sulphate 15- 5

V c h 1 or i d e < 5

<25 >25

>40 -

>20 -

>20 -

>40 -

< l o -

10-20

20-35

-

<2 5

<10

Na+ + K+ prevail in all types of waters C3+ and Mg” less than 2.5 in the water of high saline facies and less than 19.0 in low saline facies

Na+ + K+ prevail in all types of waters Ca+’ less than 4.5 in all waters Mg” less than 4.0 in all waters

Na+ + K+ prevail in all types of waters Ca” less than 12.5 in the water of high saline facies Mg+’ less than 6.0 in all types of waters

CHEBOTAREV’S CLASSIFICATION 26 5

geochemical groups of waters. The three major groups of waters are divided into genetic types, which are determined from the absolute concentrations of the dissolved constituents expressed in reacting values in percent. The bicarbonate group contains three genetic types of water, namely: (1) bicarbonate; (2) bicarbonate-chloride; and (3) chloride-bicarbonate. The amounts of bicarbonate plus carbonate and chloride plus sulfate determines the genetic type. The sulfate group is subdivided into two genetic types: (1) sulfate-chloride; and (2) sulfate. The chloride group is divided into three genetic types: (1) chloride-bicarbonate; (2) chloride-sulfate; and (3) chloride. Chebotarev relates the genetic types to the products of weathering because he believes that although the concentration of dissolved solids in subsurface waters may vary substantially, the types of soluble salts remain largely unchangeable .

The water classes are related to the products of weathering, rainfall, and drainage conditions. Class I corresponds t o soluble products from the weathering of orthoeluvium or igneous and highly metamorphosed rocks and their silicate compounds. Class I1 waters are related to products of weathering from the same silicates and calcareous accumulations. Class I11 waters primarily are related to weathered products from calcareous accumulations. Class IV waters are related to weathering of alluvial, detrital, and gypsum deposits. Class V waters are related to marine deposits plus weathering of the products that derived the Class IV waters.

Table 8.IV shows the approximate reacting values in percent for waters found in some oilfields (Chebotarev, 1955). For example, in such waters in the bicarbonate group, the major cations are sodium plus potassium with the reacting value percentage for calcium and magnesium less than 2.5 if the saline facies are high. (The divisions between his saline facies are shown in Table 8.V.)

Table 8.V shows the relationships of hydrodynamic zones t o the geochemistry of the water and the geological environment. The zones are: (1) recharge with active water exchange; (2) pressure with delayed water exchange; and (3) accumulation with stagnant conditions.

The equilibrium of the chemical systems (those typical of the major geochemical group of waters) is a criterion called the coefficient of water exchange ( K e ) and is computed as:

Na(K)HC03 + (Ca,M&) (HC03)2 Na(K)Cl + (Ca,Mg)C12 + Naz SO4 + (Ca,Mg)S04 Ke =

The absolute and relative coefficients of water exchange for the three major groups of waters are as follows:

Ke (absolute) Ke (relative) Bicarbonate waters 1.55 96.9 Sulfate waters 0.11 6.9 Chloride waters 0.016 1 .o

TABLE 8.V

Relationships of hydrodynamic zones to the geochemistry of water and the geological evironment (after Chebotarev, 1955)

Hydrodynamic zone Geochemistry of water Geological environment

recharge- water- class hydro-chemical approximate common structures relation to water depth examples

cycle (ppm) water

Zone of active I and I1 low saline facies 180-2,400 fresh different intensive flush usually less everywhere recharge exchange (some than 500

discharge exchange facies salinity terms for (ft)

times 111)

transitional 2,400--11,400 brackish deep portions of delayed flush sometimes Great Artesian Basin, (typical) facies structures with 5,000-7,000 Rocky Mountain oil-

peculiar geo- field and others chemical environment

high saline facies 11,400-37.800 saline hampered flush

Zone of delayed 111 and low saline facies 400-2,500 fresh different inadequate flush usually less everywhere pressure exchange IV than 1,000

trazs. Lional 2.500-7.400 brackish deeper portions circulation and sometimes precaucasian Basin, (typical) facks of structures, drainage limited 3.000-4,000 South Dakota Basin,

folded zones some oilfield areas

high saline facies 7,400--19,300 saline

Zone of stagnant V low saline facies 1.500-20,000 fresh and different salt accumulation different chiefly in arid regions; accumulation condition saline prevails upon deeper portions of many

leaching artesian basins: some oilfields

transitional 20.000-90,000 saline and deeper portions (typical) facies brines of structures,

highly folded zones

high saline facies 90,000-300,000 brines water exchange manifests on geo- loeical scale time

sometimes 8,000-1 3,000

many oilfield areas (Louisiana, Alberta, etc.)

SCHOELLER’S SYSTEM 26 7

The absolute and relative coefficients were derived from assumed chemical compositions of typical waters of the major geochemical groups. The absolute value can be not lower for the group, but it can be relatively higher. Several thousand analyses of waters associated with oil pools in the world were used to formulate the typical waters. As the water-exchange conditions deteriorate, the type of water changes, and the changes are related to alteration or diagenesis of the waters (metamorphism). The data in Table 8.V give hydrochemical facies, common names of various waters as related to dissolved solids concentrations, geological structures, flush or water circulation, depths, and examples where some of the water types are found.

The highly concentrated chloride waters are primarily associated with oil occurrences; however, this is not always true. A prime determinant of the chemical composition of oilfield waters is the hydrodynamic situation and the type of trap. For example, an intensively flushed zone will contain a different type of water from a zone with limited circulation. The type of basin strongly influences the type of water that.is likely to be found. For example, an open basin probably will contain artesian waters of the bicarbonate group, a partly closed basin may contain artesian or subartesian waters of the bicarbonate or sulfate groups, while a closed basin is more likely to contain bicarbonate waters on the flanks of the basin with sulfate and chloride waters in the deeper areas.

Chebotarev (1955) applied his classification t o 917 subsurface waters in oilfields in the world. The classification indicated that 73.7% of the waters were of the chloride genetic type, 23.0% of the bicarbonate type, and 3.3% of the sulfate type. Most of the sulfate and bicarbonate types were found in the Rocky Mountain areas of the United States and probably were mixtures containing infiltrating meteoric water.

Schoeller’s system

A French geochemist, Schoeller (1955), classified waters on the basis of their dissolved constituents and in the following order of importance: (1) chloride; (2) sulfate; (3) bicarbonate plus carbonate; (4) index of base exchange (IBE); and (5) relationships of anions t o cations. This system separates waters into six primary types based upon their amounts of dissolved chloride and four subgroups based on their concentrations of sulfate. The amounts of bicarbonate and carbonate ions give additional differentiation, and an index of base exchange indicates exchange of ions in the waters with ions in associated clays. Table 8.VI outlines Schoeller’s classification.

As shown in Table 8.VI the chloride concentration separates waters into six types. Waters from several oil-producing regions were classified and the sequence C1> SO4 > HC03 was found to occur in very high chloride waters and in sea waters, especially when they are saturated with CaS04. If the waters are not saturated in CaS04, the sequence Cl- > HC0,- > S04-2 is predominant, and in low-chloride waters the predominant sequence is H C O ~ - > C T > S04-2.

26 8 CLASSIFICATION O F OILFIELD WATERS

TABLE 8.VI

Schoeller’s scheme for classifying petroleum reservoir waters*

Chloride concentration as Ci-

Very high if > 700 Marine if 420 - 700 High if 140 - 420 Average if 40 - 140 Low if 10 - 40 Normalif< 10

Sulfate concentration as s04-’

Very high if > 58 High if 24 - 58 Average if 6 - 24 Normalif< 6 Near saturation when J(S04- ’ ) (Ca+’) > 70

Bicarbonate plus carbonate concentmtion as H C 0 3 - + c03-’

High if > 7 Normal if 2 - 7 Low if < 2

However, he recommends using q ( H C 0 3 - + CO3-’ )‘(Ca+’ ) rather than HC03- + C03-’

Index o f base exchange (IBE)

If Cl- > Na+ then IBE = (Cl- - Na+)/Cl- If Na+ > Cl- then IBE = ( C T - Na+)/(S04-’ + HCO3- + C03-2)

Importance o f anions and cations

c1- > c1- > co3-’ co3-’ Na+ > Na+ >

SO^' > co3-’ .co~-‘ > so4-’ > c1-> so4-2

> so4-’ >CT Mg” > Ca+’ Ca+ ’ > Mg+’

* All constituents are calculated in epm.

SCHOELLER’S SYSTEM 26 9

Also, in very high chloride waters only the sequence Na+ > Ca+’ > Mg+2 is found. As the C1- decreases, the sequence Na+ > Mg+’ > Ca+’ becomes more frequent. In very high chloride waters SO4-’ > Ca+’, but in less concentrated waters the opposite may occur. The sequence HC03-< Ca+’ always is found in very high chloride waters. In less concentrated chloride waters, either HCO,- < Ca+’ or HC03- > Ca+’ may be found, while in low chloride waters HC03- > Ca+’ is predominant.

Schoeller used an arbitrary value of 70 for JSO4- x Ca+’ to indicate that a water is saturated with CaS04. (This is not necessarily true because some waters, depending upon their other dissolved constituents, can contain smaller or larger amounts.) He divided waters into four additional types depending upon their amounts of sulfate.

Saturation with CaS04 was found to occur only in very high chloride waters. The calcium concentration always is very high - ranging from 150 to 1,100 epm - in high chloride waters which have SO4-’ > 58 epm and usually is less than 150 epm in high chloride waters where SO4-’ < 58 epm. All petroleum waters even if saturated in CaS04 have a low S04/C1 ratio which is attributed to reduction of sulfates and high concentrations of chloride. The ratio never exceeds one except in low or normal chloride waters.

The third subgroup contains three additional types depending upon the amounts of bicarbonate and carbonate in the waters. The preferred formula for this calculation is Y(HCO,- + C03-’ )’ (Ca+’ ) which is proportional to the gaseous pressure of C 0 2 in equilibrium with CaCO, in the water. As the Cl- increases, the tendency is for Ca+’ to increase and HC03- to decrease; however, because the Ca+’ increases, the product of y(HCO,- + C03-’ )’ (Ca+’ ) does not vary greatly.

As the waters move in their subsurface environment their dissolved ions ’ have a tendency to exchange with those in the rocks. Two extreme types of adsorption can be noted in addition to intermediate types of adsorption. The extreme types are a physical adsorption or the Van der Waals adsorption with weak bonding between the adsorbent and the constituent adsorbed and a chemical adsorption with strong valence bonds. Both of these adsorptions can act simultaneously.

Cations can be fixed at the surface and in the interior of the associated minerals. These fixed cations can exchange with the cations in the water. When the exchange occurs, there is an exchange of bases. With the right physical conditions of the adsorbent, similar exchange can occur with the anions. Some of the formation constituents that are capable of exchange and adsorption are argillaceous minerals, zeolites, ferric hydroxide, and certain organic compounds.

Particle size influences rates and capacities, if the solids are clays such as illite and kaolinite. The.rate increases with decreasing particle size. However, if a larger mineral has a lattice, the exchange can easily occur on the plates.


The concentration of exchangeable ions in the adsorbent and in the water is important. More exchange will occur when the solution is highly concentrated.

Schoeller (1955) used the formula: 1

( a - x ) = K - (a E x ) IP

to indicate the relationship that exists between the initial concentration, a , of the cations in milliequivalents in the unreacted water, and x , which equals the final concentration of the cations in milliequivalents in the water after equilibrium or reaction with the rocks. The amounts of cations exchanged by passing from the liquid to the rock or clay is a - x and the index of base exchange (IBE) = (a - x) /a. By substitution:

The IBE is used to indicate the ratio between the exchanged ions and the same ions as they originally existed. For example, assume that in the original water there were as many equivalents of C1- as (Na+ + K'), and that when the Na+ and K+ of the water exchanged with the alkaline earths in the rocks alkaline exchange occurred, then:

C1- - (Na+ + K+ ) c1- IBE =

and this value is positive if the equivalents are Cl- > (Na' + K'). Theoret- ically all the halides should be included as C1- and all the alkalies as Na+ or (Na+ + K').

However, when the alkaline earth ions in the water exchange for alkali metal ions on the rocks then:

IBE = Cl- - (Na+ + K+)

SO4- + HC03- + NO3-

and this value is negative if the equivalents are Cl- < (Na+ + K+). The lack of equilibrium between the halides and the alkalies is not always a characteristic of base exchange because sea water has a positive value without the occurrence of base exchange. Negative values usually are observed for water coming from altered crystalline rocks. Waters with an IBE equal to or greater than 0.129 can be true connate petroleum reservoir waters. Waters with a negative IBE are waters of meteoric origin that have infiltrated into marine sediments.

Comparison of petroleum-reservoir waters with other types of subsurface waters revealed that the other waters have most of the same characteristics

or Kr. Waters that are in contact with organic matter a much higher SO4- concentration and a lower

SCHOELLER’S SYSTEM 271

(other than petroleum), such as bitumens, lignites, and coals, resemble petroleum reservoir water, but the frequency of a Kr above normal is greater in petroleum associated waters. Waters related to magmatic reactions commonly possess high concentrations of HC03 .

Schoeller’s (1955) study of petroleum reservoir waters indicated that a positive IBE is more frequent as the C1- increases. A negative IBE is more frequent as the C1- decreases, and a negative value is predominant in low and normal chloride waters associated with petroleum. In fact, this characteristic appears specific for petroleum reservoir waters since in other subsurface waters a positive index occurs as frequently as a negative index.

Ancient sea water (connate water) deposited with the sediments usually has an IBE > 0.129 and a Cl/Na > 1.17. Intruding meteoric water in sedimentary marine rock has an IBE < 0.129 and Cl/Na < 1.17. Petroleum- reservoir waters with an IBE greater than sea water 0.129 also have the characteristics Cl/Na > 1.17, Cl/Ca < 26.8, Cl/Mg > 5.13, Mg/Ca < 5.24; a very high value for $(HCO,-)’ (Ca+* ) indicating sulfate reduction; low concentrations of HC03-; and frequent high concentrations of NH4 +.

Petroleum-reservoir waters containing infiltrating meteoric water mixed with ancient sea water have an IBE less than sea water, 0.129, and the characteristics Cl/Na < 1.17, the ratio Mg/Ca increases and approaches but never equals 5.24, and the ratios Na/Ca and Na/Mg decrease as the dissolved solids increase.

-

Gases in petroleum-reservoir waters

Schoeller (1955) noted that there should be equilibrium between the free petroleum gases and those dissolved in the water. Considering the solubility of the gases, those in the water should reflect the composition of the petroleum. Components characteristic of petroleum accumulations are ethane, propane, butane, pentane, ethylene, and propylene. Associated components, which may also be present in volcanic waters and in waters in contact with other organic matter such as coal, peat, and lignite as well as in petroleum- associated waters, are favorable components. These are methane, carbon dioxide, organic nitrogen, hydrogen sulfide, helium, radon, and the absence of oxygen. Other components or universal components found in all types of waters are nitrogen and argon.

The top waters can contain gases such as Hz S, C 0 2 , and CH4 but because they do not contact the petroleum deposit they are not similar in composition t o the bottom waters. The edge waters are in contact with the petroleum and are characterized by higher amounts of HC03, sulfate reduction, and the presence of H2 S , NH4, and small amounts of dissolved hydrocarbons.


Oilfield brine analyses

About 4,000 oilfield brine analyses were classified. All of these analyses are now in the U.S. Bureau of Mines (1965) open-file report on oilfield brines. The data are on automatic data processing magnetic tape as well as in a file of computer printout sheets listed by State, county, sedimentary basin, formation, etc.

These brine data were collected by the Bureau of Mines because the value of oilfield brine analyses in the study of various petroleum-related problems was recognized early in the history of petroleum and natural gas. Before 1928 the Bureau of Mines had indicated in several reports (Ambrose, 1921; Swigart and Schwarzenbek, 1921; Collom, 1922; Mills, 1925; Reistle, 1927) ways in which the analyses could be used. In earlier years, confusion existed because of greatly varying methods of analysis that were used. A paper presenting the methods used by the Bureau of Mines was published by Reistle and Lane (1928). This system of determining the characteristic constituents of oilfield waters and of calculating and reporting results was widely adopted by the petroleum industry. Later the Bureau of Mines cooperated with several interested agencies, and a more detailed report with more modern methods of analyzing oilfield waters was published (American Petroleum Institute, 1968).

The Bureau of Mines has an oilfield water analysis laboratory at the Bartlesville Energy Research Center, Bartlesville, Oklahoma. These 4,000 samples were analyzed at this laboratory.

Analysis methods

The specific gravity of each sample is determined so that a correct aliquot size can be taken for a specific ion analysis. Chloride is determined by titration with silver nitrate, carbonate and bicarbonate are determined by titration with a standard acid, and a pH meter is used to determine the end points. This alkalinity determination should be completed at the time of sampling for accur?te results. However, most of the data for the 4,000 samples were obtained by analysis in the laboratory and were completed within 6 t o more than 48 hours after sampling. Therefore, the alkalinity data cannot be considered absolute but only relative.

The calcium was determined by titration of calcium oxalate with permanganate until about 1957, about which time it was determined by complexometric titration such as with disodium ethylenediametetraacetic acid (EDTA) until about 1969; since then, it has been determined by atomic absorption. Magnesium determination has a similar history. I t was precipitated as the pyrophosphate until about 1957, and titrated with EDTA until 1969, from then to now it has been determined by atomic absorption.

Sulfate was determined by precipitation as barium sulfate, and this method still is used. Sodium was determined by calculation from the difference

OILFIELD BRINE ANALYSES 273

between the reacting values of the assumed total anions and cations until about 1960, after which time it was determined by flame photometry or atomic absorption.

Several other analyses for dissolved constituents in oilfield brines are now made by the Bureau of Mines. For example, potassium, lithium, rubidium, and cesium are determined by atomic absorption or flame photometry; strontium and barium by atomic absorption; manganese, iron, and boron by atomic absorption or titrimetric methods; and bromide and iodide by titrimetric methods.

The precision of the methods is as follows: alkalinity, 2-3% of the amount present; sodium, 2--5% of the amount present; calcium and magnesium, 4--5% of the amount present; sulfate, 1-2% of the amount present; chloride, 1% of the amount present. If sodium is calculated, the precision value reflects the sum of the precision data for the data from which it is calculated plus the undetermined dissolved constituents. The significant figures for the analytical data are all the certain digits and only the first doubtful digit. This number usually is limited to three significant figures except for specific gravity, where four or five are common.

It often is recognized that the sampling method is as important as the analytical method. This certainly is true of oilfield brines.

Field sampling methods

Most of the 4,000 samples were obtained only from wells where reasonable assurance was evident that the formation brine was not contaminated by drilling fluids or by intrusion of water from other formations. Wells were selected on the basis of age, type of completion, and production of fluids. Samples were not taken from some gasfields because of the likelihood of dilution by water condensed from vapor carried up the hole with the gas. Some samples were taken from gas-condensate wells that produced large volumes of brine.

In many cases the electrical resistivity measurement was made on the sample at the time the sample was taken, and resulting values were compared with measurements from other samples from the same formation within that field or nearby fields. Obvious discrepancies were eliminated by sampling additional wells.

Nearly all samples were withdrawn at production wellheads, and the water was separated from the oil in portable separators. A few samples were taken of brines from formations that did not produce enough water to permit taking samples at individual wellheads. Such samples were taken from gun- barrels or oil-water separators.

Samples were taken in clean, 1-gallon glass jugs that were first rinsed several times with the water sampled and then filled, capped, and labeled. In a few instances samples were obtained by the producer from comparatively isolated small pools or fields and shipped to the laboratory in 1-gallon polyethylene jugs.


Application of the classification systems

Several investigators have applied the classification systems to determine their usefulness in studies related t o exploration and production of petroleum. Ostroff (1967) concluded that Palmer’s system is less useful than the systems of Sulin and Schoeller. Further he concluded that the Sulin system is more applicable to petroleum formation waters because many such waters contain more than 2,000 epm of dissolved solids, and the Schoeller system tends to lump these highly concentrated waters together. The index of base exchange (IBE) in Schoeller’s system, however, appears to have merit for certain interpretations as does theJ Ca+* x SO4-*.

Dickey (1966) concluded that the Palmer system does not correlate very well with the geology of oil reservoirs, that Schoeller’s nomograph is useful, but that the Sulin system appears to conform better with geology. He also noted that relating water types to geology and flow patterns should be useful in exploration and that distinguishing between a stagnant water and artesian related waters should be highly significant in a new oilfield development area.

The Sulin system appears to be more generally applicable than the other systems in studies of waters from petroleum reservoirs. Because of this and because the Schoeller system appears t o have merit in studying certain types of oilfield waters, it was decided t o apply portions of the Sulin system, the Schoeller system, and Bojarski’s modification of the Sulin system to a study of brines from various sedimentary basins of the United States that are known to be related to petroleum and natural gas.

Calculations

The analyses of most oilfield waters are reported in units of milligrams per liter (mg/l). The conversion of mg/l to equivalents per million (epm) is done using the following formula:

= epm ion mg/l of ion atomic weight of ion

valence of ion specific gravity of brine x

Table 8.VII provides formulas for calculating the epm for many of the common constituents found in oilfield brines. If the constituent is reported in parts per million (ppm), it is not necessary to divide by the specific gravity of the brine.

The sum of the epm’s (Z epm) shown in Table 8.VII are converted to Zr/100 g of water for the Sulin calculations by moving the decimal to the left in the Z epm and calling this Zr. The term s is used to indicate the percent of equivalent of a given constituent. The percentage equivalent (s) of each ion is determined by dividing the equivalents per 100 g of water by the total equivalent in 100 g of water. For example, if the r for sodium equals

APPLICATION OF THE CLASSIFICATION SYSTEMS 27 5

TABLE 8.VII

Formulas for converting milligrams per liter to equivalents per million for constituents commonly found in oilfield waters

Lithium Potassium Sodium Magnesium Calcium Strontium Barium Carbonate Bicarbonate Sulfate Chloride Bromide Iodide

mg/l Li+ mg/l K+ mg/l Na+ mg/l Mg+’ mg/l Ca+’ mg/l Sr+’ mg/l Ba+’ mg/l co3-’ mg/l HC03- mg/l SO^+ mg/l C1- mg/l Br- mg/l I-

x 0.1442/sp. gr.* = epm Li+ x O.O256/sp. gr. = epm K+ x O.O435/sp. gr. = epm Na+ x O.O823/sp. gr. = epm Mg+’ x O.O499/sp. gr. = epm Ca+’ x O.O228/sp. gr. = epm Sr+’ x O.O146/sp. gr. = epm Ba+’ x O.O333/sp. gr. = epm c03-’ x O.O164/sp. gr. = epm HC03- x 0.0208/sp.gr. = eprnS04-’ x O.O282/sp. gr. = epm C1- x O.O125/sp. gr. = epm Br- x O.O079/sp. gr. = epm I-

Z e p m =

* Specific gravity.

200.6 and the Zr for the total equivalents equals 518.8, then 200.6/518.8 x 100 = 38.7, or 38.7 percentage equivalents for sodium.

The Sulin classification considers only the macro constituents; if ions such as potassium, lithium, strontium, barium, bromide, and iodide are determined, they should be added t o their associated macro constituents to be properly considered in the analysis report. For example, when sodium, potassium, and lithium are determined by atomic absorption the total mg/l of each is reported. Therefore, the epm Na + epm K + epm Li should be added to obtain the correct r value for sodium:

epm Na + epm K + epm Li 10 10 r N a =

epmCa + epmSr+ epmBa 10 10 r C a =

epm C1 + epm Br epm I 10 10 rC1 =

The r values then are divided by the Zr and multipIied by 100 to obtain the s value or percentage equivalents. The s values are used to determine the type, class, and other Sulin values of the water as illustrated in Table 8.1, where a = sNa, b = sCa + sMg, and d = sC1+ s S 0 , . The epm values are used to determine the Schoeller characteristics such as the degree of chloridiza- tion, the degree of sulfation, IBE, etc., illustrated in Table 8.VI.

27 6 CLASSIFICATION O F OILFIELD WATERS

TABLE 8.VIII

Classification of some oilfield waters from 10 formations in eight sedimentary basins

No. State Formation Basin Depth Concentration (epm)

1 2 3 4 5 6 7 8 9

1 0 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40

Kans. Kans. Kans. Kans. Kans. Kans. Kans. Kans. Kans. Kans. Kans. Kans. Kans. Kans. Kans. Kans. Kans. Kans. Kans. Kans. Okla. Okla. Okla. Okla. Okla. Okla. Okla. Okla. Okla. Okla. Ark. Ark. Ark. Texas Texas Texas Texas Texas Texas Texas

Arbuckle Arbuckle Arbuckle Arbuckle Arbuckle Arbuckle Arbuckle Arb u ck le Arbuckle Arbuckle Lansing Lansing Lansing Lansing Lansing Lansing Lansing Lansing Lansing Lansing Wilcox Wilcox Wilcox Wilcox Wilcox Wilcox Wilcox Wilcox Wilcox Wilcox Nacatoch Nacatoch Nacatoch Nacatoch Nacatoch Nacatoch Nacatoch Nacatoch Nacatoch Nacatoch

Cent .Kans. Cent .Kans. Cent.Kans. Cent.Kans. Cent.Kans. Cant.Kans. Cent.Kans. Cent.Kans. Cent .Kans. Cent .Kans. Cent. Kans. Cent.Kans. Cent.Kans. Cent .Kans. Cent. Kans. Cent. Kans. Cent .Kans. Cent.Kans. Cent.Kans. Cent .Kans. Cherokee Cherokee Cherokee Cherokee Cherokee Cherokee Cherokee Cherokee Cherokee Cherokee E.Texas E.Texas E.Texas E.Texas E.Texas E.Texas E.Texas E.Texas E.Texas E.Texas

1,050 1,091 1,023 1,102

992 1,152 1,174

949 1,195 1,104

928 1,075

966 999 902

1,009 1,063 1,148 1,172

853 1,228 1,731

904 1,539 1,106

582 1,432 1,97 2 1,865 360 465 373 905 70 1 242 650 283 191 181

1,020

634.6 60.6 581.6 58.4 282.0 24.8 639.9 56.6 430.3 38.8 458.7 34.4 473.2 53.1 356.4 57.4 446.4 35.4 577.4 49.4

1,759.6 266.6 570.4 117.4

1,899.9 266.4 1,728.2 232.0 1,903.8 274.5 2,514.8 309.3 1,854.7 225.2 2,087.2 223.6 2,414.5 251.0 1,898.4 210.8 2,366.5 193.3 2,188.4 209.5 2,161.5 163.2 2,365.3 200.8 1,997.1 140.4 1,990.0 161.3 1,587.2 151.2 2,459.0 174.5 2,701.4 153.1 2,635.5 180.6 233.4 9.0 463.4 39.5 300.4 25.9 788.2 9.4 481.8 7.8 274.0 8.1 492.7 10.4 295.4 8.1 451.5 17.6 490.6 3.6

133.0 121.8

40.2 13.0 65.4 81.3

119.4 100.4

71.2 112.1 373.9 174.6 442.1 512.4 478.8 532.7 449.8 384.8 519.0 416.7 810.1 529.4 530.3 445.6 457.3 513.7 287.5 511.6 606.0 629.6

22.4 59.5 36.8 28.7 17.3 14.7 16.5 14.7 44.7

7.8

7.7 49.0 6.5 22.7 9.5 22.1 2.2 46.6 8.5 17.5 3.4 45.9 5.1 36.0

12.8 39.9 9.0 30.0

35.9 45.5 1.8 0.0 2.4 34.9 0.3 0.8 1.7 2.5 1.1 0.0 0.4 1.5 0.5 1.1 1.4 1 .o 0.7 2.4 0.8 0.7 1.1 7.7 0.3 9.8 0.4 7.3 1.1 15.9 0.9 7.8 0.7 13.3 1.8 1.4 1.1 6.0 0.7 8.4 1.1 8.6 3.7 0.0 1.4 0.0 4.3 1.0 3.1 0.0 3.3 0.0 2.5 0.8

18.9 0.1 2.4 0.9 7.1 0.4 2.8 0.6

773.8 732.3 313.9 827.0 510.9 523.2 705.0 456.7 512.7 685.8

2,398.9 826.6

2,605.0 2,469.4 2,655.6 3,35 3.6 2,529.6 2,706.1 3,17 9.9 2,515.5 3,360.6 2,917.2 2,847.4 2,992.0 2,584.3 2,650.8 2,021.6 3,138.8 3,449.1 3,436.6 261.1 559.5 357.7 824.6 503.5 294.2 498.4 313.6 506.2 498,4

* Chloride (epm): (VH)C = > 700, (MC) = 420-700, (H)C = 140-420, (A)C = 40-140, (L)C = 10-40, (N)C = < 10. Sulfate (epm): (VH) = > 58, (H) =: 24-58, (A) = 6-24, (N) = < 6 .


Sulin Schoeller*

Zepm type class CT so4-’

1,659.0 Cl-Ca 1,523.6 Cl-Ca 692.6 Cl-Ca

1,585.4 Cl-Ca 1,071.6 C1-Ca 1,147.2 Cl-Ca 1,492.0 CI-Ca 1,024.0 Cl-Ca 1,105.0 CI-Ca 1,506.4 C1-Ca 4,800.9 CI-Ca 1,726.6 Cl-Ca 5,214.7 Cl-Ca 4,946.5 Cl-Ca 5,314.0 CI-Ca 6,712.5 Cl-Ca 5,061.1 Cl-Ca 5,404.4 Cl-Ca 6,367.7 Cl-Ca 5,043.1 Cl-Ca 6,739.4 Cl-Ca 5,854.9 Cl-Ca 5,710.4 Cl-Ca 6,021.0 Cl-Ca 5,188.0 Cl-Ca 5,330.0 Cl-Ca 4,051.1 Cl-Ca 6,291.3 Cl-Ca 6,918.8 Cl-Ca 6,892.3 Cl-Ca 529.8 CI-Ca

1,123.5 Cl-Ca 726.2 Cl-Ca

1,654.2 C k C a 1.013.8 Cl-Ca 594.5 Cl-Ca

1,037.4 Cl-Mg 635.2 Cl-Ca

1.027.8 Cl-Ca 1,004.0 Cl-Ca

80.7 52.6 29.8 77.8 33.8 61.1 65.6 62.3 46.2 71.4 0.0 78.0 19.4 36.0 0.0 28.7 22.5 20.4 35.9 17.8 79.1 72.3 62.3 84.3 59.9 82.7 20.5 55.7 71.4 73.6 0.6 0.0 6.0 0.0 0.0 3.6 1.6 3.6 4.5 2.2

20.0 17.4 15.4 8.7 16.8 9.9 14.6 25.2 17.9 52.5 10.7 10.2 3.5 11.6 8.5 4.4 5.1 9.1 6.3 6.6 9.9 3.6 4.7 8.5 7.1 6.4 9.9 8.7 7.1 9.4 6.8 4.9 8.8 6.5 5.7 4.6 18.1 4.4 13.2 4.0

0.18 0.21 0.10 0.23 0.16 0.12 0.19 0.22 0.1 3 0.16 0.27 0.31 0.27 0.30 0.28 0.25 0.27 0.23 0.24 0.25 0.30 0.25 0.24 0.21 0.23 0.25 0.21 0.22 0.22 0.23 0.11 0.17 0.16 0.04 0.04 0.07 0.01 0.06 0.1 1 0.02


TABLE 8.VIII (continued)

No. State Formation Basin Depth Concentration (epm) (m)

Na+ Mg+’ Ca+’ HCOJ- S04-* Cl-

41 Ark. Paluxy E.Texas 1,115 1,246.8 90.6 254.1 0.4 0.0 42 Ark. Paluxy E.Texas 737 586.0 32.2 86.7 2.8 3.3 43 Ark. Paluxy E.Texas 1,297 1,310.3 107.1 278.5 2.7 .7 44 Ark. Paluxy E.Texas 884 934.9 64.8 197.6 1.5 1.1 45 Ark. Paluxy E.Texas 1,417 1,507.2 138.6 504.4 0.5 3.3

47 Texas Paluxy E.Texas 2,174 1,515.1 51.1 205.9 4.7 3.7 46 Texas Paluxy E.Texas 2,340 1,642.1 22.5 378.5 0.0 9.3

48 Texas Paluxy E.Texas 1,943 1,495.4 89.0 448.9 2.7 8.2 49 Texas Paluxy E.Texas 1,512 205.3 6.4 10.0 14.9 6.0 50 Texas Paluxy E.Texas 1,943 1,522.8 90.2 448.1 1.8 8.3 51 Ark. Rodessa E.Texas 1,897 1,971.8 157.2 669.7 0.0 8.0 52 Ark. Rodessa E.Texas 1,241 1,943.8 185.1 563.6 0.9 11.7 53 Ark. Rodessa E.Texas 1,033 1,060.3 108.2 289.8 0.0 21.4 54 Ark. Rodessa E.Texas 711 538.6 35.9 75.0 3.0 2.9 55 Texas Rodessa E.Texas 2,844 1,772.1 127.3 878.8 1.5 2.8 56 Texas Rodessa E.Texas 2,519 1,861.9 217.4 1,084.7 1.1 2.7 57 Texas Rodessa E.Texas 2,722 2,068.5 148.5 900.9 0.6 4.8 58 Texas Rodessa E.Texas 2,115 1,950.3 139.9 726.1 1.8 8.5 59 Texas Rodessa E.Texas 2,289 2,020.0 141.2 741.8 0.8 4.2 60 Texas Rodessa E.Texas 3,062 1,877.5 92.7 610.0 1.0 5.4 61 Texas Woodbine E.Texas 1,047 1,507.0 44.3 161.4 4.2 3.5

64 Texas Woodbine E.Texas 841 1,060.5 32.4 58.9 0.0 0.2 65 Texas Woodbine E.Texas 1,809 1,271.9 59.6 154.9 1.0 4.9 66 Texas Woodbine E.Texas 1,144 809.1 12.7 61.1 7.3 3.7 67 Texas Woodbine E.Texas 925 478.8 12.4 23.6 7.0 0.1 68 Texas Woodbine E.Texas 1,442 1,451.3 26.7 213.3 3.9 0.0 69 Texas Woodbine E.Texas 1,596 1,447.3 38.3 144.1 1.6 0.1 70 Texas Woodbrine E.Texas 1,332 1,268.0 30.2 81.9 8.3 4.0

62 Texas Woodbine E.Texas 1,750 1,263.0 33.4 56.3 8.2 1.8 63 Texas Woodbine E.Texas 898 341.8 4.4 9.3 11.3 0.6

71 Ala. Eutaw Interior Sal. 1,061 1,124.4 45.0 164.7 2.7 0.0 72 Ala. Eutaw Interior Sal. 972 1,102.9 25.6 160.5 2.0 0.0 73 Ala. Eutaw Interior Sal. 1,060 1,186.7 59.6 164.3 2.9 0.0 74 Miss. Eutaw Interior Sal. 1,444 1,733.6 82.7 287.3 0.9 0.0 75 Miss. Eutaw Interior Sal. 2,263 2,009.8 75.9 306.8 5.2 33.6 76 Miss. Eutaw Interior Sal. 1,312 1,572.7 88.9 224.9 0.9 0.0 77 Miss. Eutaw InteriorSal. 2,443 1,721.3 256.7 458.0 0.0 0.0 78 Miss. Eutaw Interior Sal. 1,690 1,925.9 61.6 359.9 3.9 0.0

80 Miss. Eutaw InteriorSal. 2,469 2,153.7 87.7 518.9 0.0 1.0

* Chloride (epm): (VH)C =-> 700, (MC) = 420-700, (H)C = 140-420, (A)C = 40-140, (L)C = 10-40, (N)C = < 10. Sulfate (epm): (VH) = > 58, (H) = 24-58, (A) = 6-24, (N)

79 Miss. Eutaw Interior Sal. 1,315 1,579.6 60.6 252.9 2.3 0.0

- < 6.

1,594.4 699.0

1,692.0 1,194.9 2,208.7 2,033.8 1,763.1 2,022.2 202.4

2,050.3 2,789.9 2,679.0 1,436.5 643.4

2,773.2 3,165.1 3,111.6 2,802.4 2,909.8 2,57 6.9 1,705.0 1,342.2 343.5

1,161.4 1,478.2 873.3 507.7

1,685.1 1,629.4 1,367.4 1,330.1 1,288.9 1,411.8 2,108.5 2,358.5 1,890.2 2,433.4 2,352.4 1,893.5 2,765.6


_ - Sulin Schoeller* d c a + ' + so4-' V(HCO~- + coz-2 ) ? ( ~ a + ~ ) IBE

Zepm type class CT SO^-' 3,186.6 CI-Ca 1,410.3 CI-Ca 3,391.5 Cl-Ca 2,395.0 CI-Ca 4,363.0 CI-Ca 4,086.4 Cl-Ca 3,543.9 Cl-Ca 4,066.7 Cl-Ca

4,121.6 CI-Ca 5,596.8 Cl-Ca 5,384.3 Cl-Ca 2,916.3 CI-Ca 1,299.0 CI-Ca 5,556.0 Cl-Ca 6,333.1 Cl-Ca 6,235.2 Cl-Ca 5,622.2 CI-Ca 5,818.1 CI-Ca 5,163.7 CI-Ca 3,425.6 Cl-Ca 2,705.0 CI-Ca 711.0 CI-Mg

2,313.7 Cl-Ca 2,970.7 CI-Ca 1,767.3 C1-Ca 1,029.9 Cl-Ca 3,379.5 Cl-Ca 3,261.0 Cl-Ca 2,760.0 Cl-Ca 2,667.1 Cl-Ca 2,580.1 Cl-Ca 2,825.4 CI-Ca 4,213.1 Cl-Ca 4,789.9 Cl-Ca 3,777.7 Cl-Ca 4,869.6 Cl-Ca 4,704.8 Cl-Ca 3,789.1 Cl-Ca 5,527.1 Cl-Ca

445.2 SO4-N

3.1 17.1 14.1 15.0 41.0 59.5 27.9 60.9 7.7 61.0 73.3 81.3 78.7 14.8 50.1 54.4 66.2 79.0 55.9 57.4 23.9 10.0 2.4 4.0 27.6 15.1 1.5 0.0 3.7 18.1 0.1 0.1 0.1 0.1

101.6 0.0 0.0 0.0 0.0 22.7

3.8 8.8 12.8 7.6 5.4 0.0 16.6 13.6 13.1 11.1 0.5 8.0 0.4 8.8 12.9 11.1 7.3 13.5 7.7 8.4 14.2 15.6 10.6 0.0 5.4 14.8 10.5 14.8 7.4 17.8 10.6 8.8 11.1 6.2 20.3 5.7 0.0 17.8 11.0 0.0

0.22 0.16 0.23 0.22 0.29 0.19 0.14 0.26 0.0 0.26 0.29 0.27 0.26 0.16 0.36 0.41 0.34 0.30 0.31 0.27 0.12 0.06 0 .oo 0.09 0.14 0.07 0.06 0.14 0.11 0.07 0.15 0.14 0.16 0.18 0.15 0.1 7 0.29 0.18 0.17 0.22

280

TABLE 8.VIII (continued)

CLASSIFICATION OF OILFIELD WATERS

No. State

81 Miss. 82 Miss. 83 Miss. 84 Miss,

85 Miss. 86 Miss. 87 Miss. 88 Miss. 8 9 Miss. 90 Miss. 91 La. 92 Ark. 93 Ark. 94 Ark. 95 Ark. 96 Ark. 97 Ark. 98 La. 99 La.

100 La. 101 La. 102 La. 103 La. 204 La. 105 La. 106 La. 107 La. 108 La. 109 La. 110 La. 111 N.D.

Formation Basin

Wilcox Miocene Wilcox Miocene Wilcox Miocene Wilcox Miocene

Wilcox Miocene Wilcox Miocene Wilcox Miocene Wilcox Miocene Wilcox Miocene Wilcox Miocene Smackover N .Louisiana Smackover N.Louisiana Smackover N.Louisiana Smackover N.Louisiana Smackover N.Louisiana Smackover N. Louisiana Smackover N.Louisiana Smackover N.Louisiana Smackover N.Louisiana Smackover N.Louisiana Wilcox W. Gulf Wilcox W. Gulf Wilcox W. Gulf Wilcox W. Gulf Wilcox W. Gulf Wilcox W. Gulf Wilcox W. Gulf Wilcox W. Gulf Wilcox W. Gulf Wilcox W. Gulf Silurian Williston

Depth (m)

-___ 1,975 1,748 1,412 1,871

2,330 1,646 2,162 2,268 1,552 1,327 3,109 2,103 2,399 2,509 2,240 2,526 2,615 2,949 3,271

701 1,399 1,814

747 1,561 1,722

666 1,124 2,441 2,158

471 3,633

Concentration

Na+ Mg+2 Ca+2

2,031.8 36.8 100.3 1,847.9 48.4 94.9 1,362.9 15.0 82.5 2,157.3 54.1 89.9

1,972.2 65.8 95.7 1,992.4 38.0 81.9 2,043.7 25.5 132.2 2,198.7 83.8 90.7 1,280.8 36.7 56.3 1,318.9 20.9 99.6 1,589.7 86.7 1,256.8 2,444.9 275.9 1,392.8 2,518.1 280.4 1,622.1 2,790.1 222.2 1,641.6 2,418.0 279.5 1,470.8 2,729.0 218.6 1,598.2 4,277.5 10.0 34.9 2,225.4 149.7 2,282.1 1,971.2 173.5 1,668.9

681.8 35.2 63.6 1,718.5 44.9 90.1 2,035.8 46.5 124.7 1,206.3 43.6 47.2 1,874.2 40.9 91.0 2,138.9 41.9 96.2 1,057.5 26.6 51.0 1,379.4 41.8 60.0 2,119.4 43.7 100.2 2,132.3 15.3 115.2

840.1 26.8 24.1 3,431.2 100.6 993.7

c1- 4.5 0.0 3.8 0.0 4.4 0.0 6.8 0.0

3.9 7.2 3.0 0.0 7.2 0.0 3.9 0.3 9.4 0.0 3.9 0.0 0.0 8.8 2.0 4.6 1.8 3.7 2.3 1.7 0.0 4.1 2.4 1.7 2.4 0.0 0.0 1.4 0.0 1.8 5.1 2.1 1.4 0.2 5.6 0.8 4.6 0.6 0.7 0.8 1.4 1.4 0.0 0.0 2.5 0.6 6.1 0.0 4.0 8.0 7.0 0.0 1.5 8.4

2,163.3 1,98 5.9 1,455.8 2,114.0

2,122.3 2,108.5 2,194.5 2,369.8 1,364.3 1,434.8 2,940.8 4,105.9 4,413.8 4,648.6 4,163.0 4,540.4 4,312.9 4,654.9 3,810.9

778.6 1,851.2 2,199.9 1,291.2 2,003.8 2,273.4 1,058.4 1,477.6 2,263.4 2,256.4

888.4 4,305.3

* Chloride (epm): (VH)C = > 700, (MC) = 420-700, (H)C = 140-420, (A)C = 4040, (L)C = 10-40, (N)C = < 10. Sulfate (epm): (VH) = > 58, (H) = 24-58, (A) = 6-24, (N) = < 6 .

APPLICATION OF T H E CLASSIFICATION SYSTEMS 281

Cepm type class ~ 1 - SO^-^ ~

4,336.9 Cl-Ca 3,981.1 Cl-Ca 2,920.8 Cl-Ca 4,422.4 HCO,

4,267.3 Cl-Ca 4,223.9 Cl-Ca 4,403.4 Cl-Ca 4,747.3 Cl-Ca 2,747.7 Cl-Ca 2,878.2 Cl-Ca 5,883.0 Cl-Ca 8,226.2 Cl-Ca 8,840.1 Cl-Ca 9,306.8 Cl-Ca 8,335.6 Cl-Ca 4,454.9 Cl-Ca 8,637.9 Cl-Ca 9,313.8 Cl-Ca 7,626.5 Cl-Ca 1,566.7 Cl-Ca 3,706.6 Cl-Ca 4,413.6 Cl-Ca 2,593.7 C1-Ca 4,011.7 Cl-Ca 4,55 3.5 Cl-Ca 2,193.6 Cl-Mg 2,962.2 Cl-Ca 4,533.4 Cl-Ca 4,531.3 Cl-Ca 1,786.7 Cl-Ca 8,840.7 Cl-Ca

-Na

0.0 Q.0 0.0 0.0

26.2 0.0 0.1 5.4 0.0 0.0

103.6 80.0 78.0 53.5 78.0 53.4

0.0 57.5 55.5 11.4

5.1 10.2

5.6 8.8

11.7 0.0 6.1 0.0

29.9 0.0

90.6

12.7 11.2 11.8 16.1

11.4 9.0

18.9 11.1 17.0 11.5

0.0 17.7 17.9 21.1

0.6 21.3

5.9 0.7 0.6

11.6 5.6

15.8 10.1

3.6 5.9 0.0 7.3

15.2 12.1

9.9 13.0

0.06 0.07 0.06 0.0

0.7 0.06 0.07 0.07 0.06 0.08 0.46 0.40 0.43 0.40 0.42 0.40 0.01 0.52 0.48 0.12 0.07 0.07 0.07 0.06 0.06 0.0 0.07 0.06 0.05 0.05 0.20


Interpretation of the classification

The majority of the 4,000 oilfield waters that were classified fell in the S , S2 A2 class and were of the chloride-calcium type. Table 8.VIII illustrates the classification data for some of the samples from the Arbuckle, and Lansing Kansas City formations in the Central Kansas Basin; the Wilcox formation in the Cherokee Basin; the Nacatoch, Paluxy, Rodessa, and Woodbine formations in the East Texas Basin; the Eutaw formation in the Interior Salt Basin; the Smackover formation in the North Louisiana Basin; and the Wilcox formation in the western Gulf Basin.

Most of the samples of the bicarbonate-sodium and sulfate-sodium types were found at relatively shallow depths. This could indicate that the waters contained infiltrating water.

The Cl/Na ratio was determined for each sample as suggested by Bojarski. This ratio was calculated from the epm values, and the ratios ranged from 0.33 to values greater than 1. Values greater than 0.85 are characteristic of hydrodynamic waters, according t o Bojarski (1970),while the more altered waters found in static environments have ratios of less than 0.50.

Schoeller's classification uses the chloride concentration t o separate the waters into six types. The majority of the 4,000 oilfield waters analyzed for this study were very high chloride waters (where the chloride epm is equal to or greater than 700). The sulfate concentration of these waters according to his classification was not as consistent. Many of them were normal with sulfate epm less than 6. However, in several waters the sulfate epm was higher than 24. Few waters contained sulfate in excess of 58 epm.

The JCa+' x SO4-' exceeded 70 in some waters, indicating that such waters were nearly saturated with calcium sulfate. Schoeller did not consider that the solubility of calcium sulfate increases in the presence of certain other dissolved ions; therefore the value of 70 may not always indicate saturation. However, in primary and secondary recovery operations this value should be considered.

The 4(HC03- + C03-' )' (Ca+' ) was used by Schoeller to determine if a water was saturated with calcium carbonate, and such a water should have a value greater than 7. This is not entirely accurate, but the formula does indicate if the water contains an excess of calcium, which decreases the carbonate concentration. Many of the 4,000 waters evaluated had values greater than 7. A distilled water thus saturated would deposit precipitated calcium carbonate, but the activities of other ions dissolved in a brine cause the solubility product t o be different in the brine.

The predominant cation sequence for these 4,000 oilfield brines was Na+ > Ca+? > Mg+'. The SO4 /Cl ratio ranged from 0.00 to 0.34. The ratio 0.34 was found for a bicarbonate-sodium water sample, which may have contained infiltrating water. None of the chloride-calcium type waters had a S04/Cl ratio greater than 0.17, with many of them 0.00.

The IBE indicates that exchange of metal ions dissolved in the water have

APPLICATION OF THE CLASSIFICATION SYSTEMS 283

exchanged with metal ions on the clays. (Schoeller made the arbitrary assumption that the concentrations of sodium and chloride originally present in the water were equal.) If the IBE is a positive number the exchange was alkali metals in the water for alkaline earth metals on the clays, and if the IBE is negative the exchange was alkaline earth metals in the water for alkali metals on the clays. Very few negative numbers were evident when the IBE was determined on the 4,000 oilfield water analyses. This indicates that most of the formation waters associated with hydrocarbons had exchanged dissolved alkali metals for alkaline earth metals on the clays. The few samples that yielded the negative IBE numbers were sulfate-sodium and bicarbonate- sodium type waters which, according to Sulin, is indicative of terrestrial derived waters.

Ratios

The ratios Na/(Ca + Mg) and Ca/Mg were calculated from the analytical data for the 4,000 oilfield water samples. Fig.8.1 illustrates a plot of the Na/(Ca + Mg) ratio versus dissolved solids for samples from the East Texas Basin. The ratio tends to decrease with increasing dissolved solids concentration. The depletion of sodium with respect to calcium + magnesium can be attributed to diagenesis of the waters. This correlates with Schoeller's IBE, indicating that the alkali metals in the water exchange with alkaline

I K E Y

Tertiary

Upper Cretaceous 6 Lower Cretaceous

0 Jurassic x Pennsylvanian

0 DISSOLVED SOLIDS, g / l

Fig. 8.1. Plot of the Na/(Ca + Mg) ratio versus the concentration of dissolved solids in some formation waters taken from sedimentary rocks in the East Texas Basin.


- 7 -

0

0

0

Fig. 8.2. Plot of the Na/(Ca + Mg) ratio versus the concentration of dissolved solids in some formation waters taken from the Rodessa formation in the East Texas Basin. The line is a least squares fit (y = a + bx + ex2 ) for the scattered data.

earth metals on the clays, decreasing the dissolved alkali metals and increasing the dissolved alkaline earth metals.

Fig.8.2 shows the scattered data for the brines taken from the Rodessa formation in the East Texas Basin. The scattered data were submitted to least squares analysis to determine with more certainty how the ratios varied with depth and with dissolved solids concentrations. The least squares formula used was y = a + bx + cx2 or the approximation to a parabola. If the best fit is a straight line, the solution will regress to it, and this occurred for the data shown in Fig. 8.2. Also, if this occurs, the value for c i n the formula is very small. The curve shown in Fig. 8.2 represents a fit of about 88% of the sum of the mean, a fit of 100% would be ideal.

Preliminary plots of the scattered data indicated that a better fit could be obtained with the parabolic least squares approximation than with the least squares approximation for a straight line. A computer was used to obtain the fit.

The least squares curve indicates that the concentration of sodium decreased with respect to calcium plus magnesium until the dissolved solids were about 210,000 mg/l and then increased. This could be attributed to exchange of sodium in the water for alkaline earths on the minerals until the concentration of dissolved solids reached 210,000 mg/l, at which point the solubility products of the alkaline earths are such that they are unable to stay in solution. This would correlate with Schoeller’s IBE. However, the IBE does not consider the effect of other ions in solution upon the solubility product of an ion.

APPLICATION OF THE CLASSIFICATION SYSTEMS

30

0 -= 20- 2

:Is 10-

285

Tertiary 0 Upper Cretaceous

Lower Cretaceous

Jurassic

-

x Pennsylvanian-

0 n&

.n n . . 0 . 0 n

a 0

0

0

315 7b 105 I40 I'l5 2;O 245 280 3;5 z 50 DISSOLVED SOLIDS, g / l

Fig. 8.3. Plot of the Ca/Mg ratio versus the concentration of dissolved solids in some formation waters taken from sedimentary rocks in the East Texas Basin.

Fig. 8.3 illustrates a plot of. the Ca/Mg ratio versus dissolved solids. Here the trends appear to be that the Ca/Mg ratio increases as the dissolved solids increase. This trend also is related to diagenesis of the waters. The calcium increases as the magnesium decreases, and this may be related to the formation of dolomite and chlorite, or to reactions with argillaceous minerals.

Fig. 8.4 is a plot of Ca/Mg versus dissolved solids. The Ca/Mg ratios for some brines from the Rodessa formation in the East Texas Basin were submitted to least squares analysis, and the results were used to plot Fig. 8.4.

The scattered data in Fig. 8.4 did not yield as good a f i t to the formula y = a + bx + cx2 as did the data in Fig. 8.2, because the fit is about 35% of the mean where 100% is ideal. The line indicates that the ratio increased as the dissolved solids increased. This is the result of magnesium lost from the brine by reactions to form minerals, ion exchange, or shale membrane filtration. I t is not a result of solubility product because most magnesium compounds are more soluble than calcium compounds.

Fig. 8.5 is a plot of Na/(Ca + Mg) against depth from which the samples were taken. The trend does not indicate a definite relationship for these samples.

Fig. 8.6 is a plot of the least squares analysis data for Na/(Ca + Mg) versus depth for some brines from the Rodessa formation in the East Texas Basin. The plot indicates that the sodium concentration decreases with respect to


calcium plus magnesium until the depth is about 2,350 m and then it increases. The curve in Fig. 8.6 represents a 45% mean fit of the scattered data where an ideal fit is 100%.

Fig. 8.7 is a plot of Ca/Mg versus depth, and there appears to be an increase of this ratio with depth which would indicate that magnesium is depleted more with respect to calcium in brines taken from deeper strata.

. . 0 . 7t

21 i I1 I I 1 I 20 80 I40 200 260 3

DISSOLVED SOLIDS, g/l

10

Fig. 8.4. Plot of the Ca/Mg ratio versus dissolved solids for some formation waters taken from the Rodessa formation in the East Texas Basin. The line is a least squares fit (y = a + bx + cx') for the scattered data.

I "

6C

50

2c

I C

C

KEY

A Cretaceous Comanche o Jurassic x Pennsylvanian

- o Cretaceous gulf

-

Tertiary -

- . 0

A . - 0

0 A 0 0

500 1,000 1,500 2,000 2,500 3,000 DEPTH, meters

Fig. 8.5. Plot of the Na/Ca + Mg) ratio versus depth for some formation waters taken from sedimentary rocks in the East Texas Basin

APPLICATION OF THE CLASSIFICATION SYSTEMS 287

I I I I I

DEPTH, meters

0 500 1.000 1,500 2,000 2,500 100

Fig. 8.6. Plot of the Na/(Ca + Mg) ratio versus depth for some formation waters taken from the Rodessa formation in the East Texas Basin. The line is a least squares fit (y = a + bx + cx2 ) for the scattered data.

3c

0 'F 2c e :I r"

10

0

K E Y

A Cretaceous Comanche

x Pennsylvanian Tertiary 0

- o Cretaceous gulf

. A Jurassic

A 0

A

- A P o

A 0

8 0

I I I I .

500 If300 1,500 2,000 2,500 3,( DEPTH, meters

m A A

. .. I **

30

Fig. 8.7. Plot of the Ca/Mg ratio versus depth for some formation waters taken from sedimentary rocks in the East Texas Basin.

This would indicate that magnesium is taken from the brine by reactions to form minerals or absorbed by clays.

Fig. 8.8 is a plot of the least squares analysis data for Ca/Mg versus depth for some brines from the Rodessa formation in the East Texas Basin. The plot indicates that the concentration of calcium increases with depth with


I I I I I 10 L 0 500 I.000 1.500 2POO 2.500 3pOO

DEPTH, meters

Fig. 8.8. Plot of the Ca/Mg ratio versus depth for some formation waters taken from the Rodessa formation in the East Texas Basin. The line is a least squares fit (y = a + bx + cxz ) for the scattered data.

respect to magnesium. Reactions occurred between the brines and the enclosing rocks to deplete the magnesium or increase the calcium in these brines. The curve in Fig. 8.8 represents a 35% mean fit of the scattered data where an ideal fit is 100%.

Ternary diagram

Ternary or triangular diagrams are useful in studying the distribution of the cations and anions in subsurface waters. The ions which often are used in these diagrams are sodium, calcium, and magnesium or chloride, sulfate, and bicarbonate. To plot these constituents, the equivalent weights of three cation constituents or three anion constituents are determined and summed to equal 100%. The percentage of the three then are plotted. Dickey (1966) used these types of plots fo study the composition of some deep subsurface waters.

Fig. 8.9 is a ternary plot of the normalized values for sodium, calcium, and magnesium concentrations of some brines taken from oil-productive sedimentary basins. This diagram indicates that all of these brines contain more calcium than magnesium. For these particular samples the diagram seems to indicate that the calcium equivalents tend to increase with the age of the rocks from which the brines were taken; this does not, however, apply to all brines.

DISCUSSION 289

Fig. 8.9. Relative concentrations of sodium, calcium, and magnesium in some formation waters taken from sedimentary rocks in oil-productive basins.

Discussion

Chebotarev (1955) postulated that most subsurface waters are altered by meteoric water. The three hydrodynamic zones that he considers are: (1) active exchange, where water is influenced by a relatively high degree of hydrodynamic movement with flushing-out of most of the salt thus producing a low salinity water; (2) delayed exchange, where the hydrodynamic flow is less rapid, thus leaving a higher salinity water; and (3) stagnant conditions, where there is little hydrodynamic movement, so that the salinity accumulates and is higher.

This system was not applied to the 4,000 waters because it evaluates in a rather complex manner the types and classes of waters from the constituent compositions in reacting values in percent. The method appears useful in certain general types of studies.

Palmer’s system does not consider ionic concentrations or possible conditions of saturation of calcium carbonate or calcium sulfate. Some constituents such as the alkaline earths and chloride and sulfate are lumped togeth-


er. Calcium and magnesium should not be lumped together because even though they are in the same chemical group in the Periodic Table, they often behave quite differently in chemical reactions. For example, the solubilities of many of their salts are considerably different. The same often is true of the chlorides and sulfates.

The portion of the Palmer system applied to the 4,000 brines was used only because it is incorporated in Sulin’s system. The Palmer system by itself appears to have little value in studying subsurface brines related t o hydrocarbon accumulations.

Schoeller separates the waters into six types solely on the basis of the concentration of the chloride ion and into four additional types using the concentration of the sulfate ion. Because of this, his classification of oilfield waters gives considerably more variation in types than the Sulin system, and thus it is more confusing in interpretation. Schoeller’s formula for determining relative saturations of sulfates and carbonates in the waters has value in production problems. For example, knowledge that the sulfates or carbonates may precipitate from a water under certain conditions is useful so that correct treatment can be applied to prevent well and/or formation damage. The index of base exchange also is useful in evaluating diagenetic reactions that may have occurred to change the water.

Sulin’s system considers some of the ions in determining the type of water, and the class indicates the predominance of the anion groups. These two characteristics of waters appear useful in studying waters that are likely to be associated with hydrocarbon accumulations. For example, several investigators have determined that the chloride-calcium type in the S1 S2 A2 class of water is the most likely type to be associated with a hydrostatic environment that promotes the accumulation of hydrocarbons. The next most likely type is bicarbonate-sodium in the S1 A l A2 class and the least likely types are chloride-magnesium and sulfate-sodium.

Knowledge of the type and class plus what Sulin describes as the significant indicators (direct and indirect) appears useful in hydrocarbon exploration studies. The Sulin system does not consider the degree of saturation of the water with respect to sulfates and carbonates, which is a disadvantage in production problems. Also, the system makes no provision for determining the degree of base exchange which is useful in certain interpretations of diagenesis.

Bojarski’s modification of the Sulin system appears to have little value in evaluating a water that is likely to be associated with petroleum. Many of the values that were found for the Na/Cl ratio in the 4,000 samples were greater than 0.85. This value in a chloride-calcium type water according to Bojarski is not likely to be found in a water associated with petroleum. It is possible that the waters that Bojarski evaluated were consistently very concentrated waters with respect to dissolved solids.

CONCLUSIONS 291

Conclusions

Classification of the subsurface waters aids in interpreting the type of water that is more likely to be associated with a hydrocarbon accumulation. Application of water classification techniques t o 4,000 oilfield brine samples revealed that the majority of the samples were chloride-calcium type of the S1 S2 A2 class, had positive IBE values, had a predominant cation sequence of Na > Ca > Mg, and were very highly concentrated with dissolved chloride. Many of the 4,000 samples had values greater than 7 for q m C03 )’ (Ca), and some had values greater than 70 for d m , indicating that many of the waters were saturated or nearly saturated with respect to carbonate and sulfate.

The Bojarski modification of the Sulin system appears to be of little value. The ratio Na/(Ca + Mg) generally decreased with increasing dissolved solids and depth. The ratio Ca/Mg generally increased with increasing dissolved solids and depth.

Studies of the water characteristics and mapping of the more important water properties in conjunction with other geological and geophysical data appear useful in exploration. Maps of certain water characteristics such as the JCa+’ x SO,,-’ and d(HC03- + C03- )’ (Ca+’ ) are useful in solving production problems.

References

Ambrose, A.W., 1921. Underground conditions in oilfields. US. Bur. Min. Bull., 195, 238 PP.

American Petroleum Institute, 1968. API Recommended Practice for Analysis o f Oilfield waters. Subcommittee on Analysis of Oilfield Waters, API RP 45, 2nd ed., 49 pp.

Bojarski, L., 1970. Die Anwendung der hydrochemischen Klassifikation bei Sucharbeiten auf Erdol. 2. Angew. Geol., 16:123-125.

Chebotarev, I.I., 1955. Metamorphism of natural waters in the crust of weathering. Geochim. Cosmochim. Acta, 8:22-48, 137-170,198-212.

Collom, R.E., 1922. Prospecting and testing for oil and gas. U.S. Bur. Min. Bull., 201, 170 PP.

Dickey, P.A., 1966. Patterns of chemical composition in deep surface waters. Bull. Am. Assoc. Pet. Geol., 50:2472-2478.

Elliott, Jr., W.C., 1953. Chemical characteristics of waters from Canyon, Strawn, and Wolfcamp formations in Scurry, Kent, Borden, and Howard Counties, Texas. Pet. Eng., 25 : B7 7-BB9.

Mills, R. van A., 1925. Protection of oil and gas field equipment against corrosion. U.S. Bur. Min. Bull., 233, 127 pp.

Ostroff, A.G., 1967. Comparison of some formation water classification systems. Bull. A m . Assoc. Pet. Geol., 51:404-416.

Palmer, C., 1911. The geochemical interpretation of water analyses. U.S. Geol. Sum. Bull., 749~5-31.

Reistle, Jr., C.E., 1927. Identification of oilfield waters by chemical analysis. U.S. Bur. Min. Tech. Paper, No.404, 24 pp.

Reistle, Jr., C.E. and Lane, E.C., 1928. A system of analysis of oilfield waters. U.S. Bur. M i a Tech. Paper, No.432, 14 pp.


Rogers, G.S., 1917. Chemical relations of the oilfield waters in San Joaquin Valley, California. U.S. Geol. Sum. Bull., 653:5-116.

Rogers, G.S., 1919. Sunset-Midway oil field, California, 11. Geochemical relations of oil, gas, and water. U.S. Geol. Sum. Prof. Paper, No.117, 103 pp.

Schoeller, H., 1955. Geochemie des eaux souterraines. Rev. Znst. Fr. Pet., 10:181-213, 219-246, 507-552.

Sulin, V.A., 1946. Waters of Petroleum Formations in the System of Nature Waters. Gostoptekhizdat, Moscow, 96 pp. (in Russian).

Swigart, T.E. and Schwanenbek, F.X., 1921. Petroleum engineering in the Hewitt Oilfield, Oklahoma. Cooperative Bulletin published by the US. Bureau of Mines, the State of Oklahoma, and the Ardmore, Oklahoma, Chamber of Commerce, 61 pp.

U.S. Bureau of Mines, 1965. Analyses of Oilfield Waters. Open-file Report.

Chupter9. SOME EFFECTS OF WATER UPON THE GENERATION, MIGRATION, ACCUMULATION, AND ALTERATION OF PETROLEUM

Both water and hydrocarbons are ubiquitous in the crust of the earth and water is in contact with most if not all chemical and physical reactions. The water cycle is comprised of mechanisms whereby it precipitates from the atmosphere t o the crust of the earth and there enters various environments - e.g., surface and subsurface, chemical and physical, and biogenic and abiogenic - until it ultimately returns to the atmosphere. The carbon cycle comprises the reaction of water, minerals, carbon dioxide, and a catalyst (chlorophyll) to form organic plant material composed of carbohydrates, fats, lignins, proteins, and some hydrocarbons such as alkanes. Production of additional types of organic material results from the consumption of plants by animals.

Organic matter from land and marine plants and animals is deposited with inorganic sediments to form a biomass from which petroleum and natural gas originate. Most of the organic matter that will later produce the hydrocarbons is deposited in an aqueous environment; therefore, it is evident that water profoundly influences not only the hydrocarbon precursors but (as will be demonstrated later) also the generation, migration, accumulation, and alteration of hydrocarbons.

The environment controls where and how inorganic and organic matter is deposited. Most of the petroleum source material is marine (autochthonous); however, Corbett (1955) noted that considerable terrestrial (allochthonous) derived organic matter is carried by streams and rivers until the bulk of it often is deposited in deltas. In the marine depositional environment, the sediment characteristics are controlled by hydraulics and by grain size of the detrital material. Most coarse-grained sediment will deposit on beaches, bank tops, and shelves, or where water turbulence is maximum. Finer grained sediments are deposited in shelf areas, while the finest grained are deposited in the deep basin (Emery, 1960).

Reducing conditions which aid in preserving organic matter are prevalent in sediments and bottom waters in many marine environments and in general tend to become more reducing with depth below the water-ediment interface. Therefore, most of the oxidation of organic detritus occurs as it falls to the sea bottom where the reducing environment will inhibit further oxidation. Rapid deposition will aid in the preservation of more organic matter as well as more of the easily oxidized organic compounds.

294 EFFECTS O F WATER ON PETROLEUM

Compaction

Recently deposited sediments have water-filled pore spaces which comprise 8Wo or more of their volume, and deposition of a few more hundred meters of sediments causes this porosity to be reduced to 30% accompanied by the expulsion of water (Hedberg, 1964). Considerable time is necessary for water t o be expelled from low-permeability fine clays (Terzaghi and Peck, 1948). In some cases, pressures approaching geostatic are created because with increasing compaction, the pore water, which cannot easily escape, carries the full load. The pressure will drop to hydrostatic as the water is squeezed out, then the water bears the weight of the overlying water column and the sediments carry the weight of the overlying sediment column minus the buoyancy factor of the water.

Compaction occurs in most sediments, but it is greater as muds form shales than when sands form sandstones, and likewise the expulsion of water from muds is greater. Also carbonate compaction will halt before argillaceous mud compaction because carbonate recrystallization causes formation of a rigid, difficult to compact, structure.

The clay, montmorillonite, expands when interlayer water is added and contracts when it is removed. The removal of water from montmorillonite is a function of pressure and temperature (Burst, 1969). Schmidt (1971) found that the temperature is about 93-104OC when clay starts releasing intra- crystalline water and that rate of release increases with higher temperatures. Powers (1967) also suggested that it is a function of the amount of potassium which is necessary for the transformation of montmorillonite to illite. Removal of water from montmorillonite with compaction resulting from deep burial yields large amounts of free water which can migrate. The amount of freed interlayer water depends upon the amount of montmorillonite or other clays in an expanded state in the sediment. The conversion of montmorillonite to chlorite does not require any volume change (Weaver and Beck, 1969), but the conversion of montmorillonite t o illite reduces the clay volume about 5096, so it is apparent that this freed water can be equivalent to 50% of the amount of montmorillonite in the sediment. The dehydration of montmorillonite occurs in three stages and probably a t three different depths of burial since the dehydration is a function of depth. Therefore, the second and third dehydration stages could release water at about 1,500 m and perhaps below 3,000 m thus allowing new supplies of water to migrate.

In the Gulf Coast area, the last water is not removed from montmorillonite until the depth is about 4,500 m. The clays in this area are composed of 50--80% montmorillonite, and the last water out comprises about 20% of the volume of montmorillonite present so it is evident that considerable freed water also is available at depths to 4,500 m.

Von Engelhardt and Gaida (1963) noted that compaction of clays appears to proceed more rapidly if the pore solution is enriched in dissolved electrolytes. This may influence the compaction rate as, for example, a nonmarine

GENERATION AND MIGRATION 295

clay may compact more slowly than a marine clay. This could relate to a nonmarine source evolving a different type of hydrocarbon.

Generation and migration

Most petroleum and natural gas hydrocarbons are generated from sediment organic matter by low-temperature chemical reactions (Philippi, 1965). Philippi also concluded that lipids probably are the major petroleum precursor and that most petroleum is generated by chemical reactions occurring at temperatures above 115°C. A catalytic effect of the surrounding sediment, and in particular the shales, influences the rate and type of hydrocarbon formation.

According t o McIver (1963) the maturation of hydrocarbon is influenced by depth, and the heavy hydrocarbons in the liquid crude oil decrease with depth while the lighter hydrocarbons increase with depth. Fig. 9.1 illustrates how an aromatic type oil might generate and mature to graphite with depth, and how a paraffinic type crude oil might generate and maturate to methane with depth. In reality many crude oils contain both aromatics and paraffins and the ultimate end product with increasing burial depth would be graphite.

I t has been postulated that oil migrates from the fine-grained source rock to a trap as a discrete oil phase. However, calculations indicate the migration of oil globules in reservoirs required forces several thousand times greater than those produced by hydrodynamic gradients in most reservoirs (Levorsen, 1954).

Because water is present in all sediments that contain organic matter which transforms to petroleum and natural gas hydrocarbons, it is reasonable to assume that water is closely related to petroleum-generation processes. In essence, water controls the depositional environment of the petroleum

1 r S t a r t i n g mater ial I S t a r t i n g mater ia l

1

1 Para f f in ic crude oil

Lighter hydrocarbons plus N, S, and 0 compounds

1 I CH 4 1

Fig.9.1. Schematic of how an aromatic crude oil can maturate to graphite with increasing temperatures associated with increasing depth, and how a paraffinic crude oil can maturate to dry methane gas. (After McIver, 1963.)

296 EFFECTS OF WATER ON PETROLEUM

precursors, while in the subsurface environment, water appears to control the migration of petroleum hydrocarbons and it is not unlikely that water is a control in the generation of petroleum.

The generation of hydrocarbon is temperature dependent (Philippi, 1965). The viscosity of crude oil decreases exponentially with increasing temperature. The solubilities of petroleum hydrocarbons in water increase with temperature and decrease as the salinity of the water increases. A temperature drop from 150’ to 25OC reduces the solubility of petroleum in water by a factor of 4.5 t o 20.5 (Price, 1973).

Nonhydrocarbon organic acids, esters, and ketones are relatively soluble in water. Therefore it is possible that these compounds may migrate in water solution and be reduced t o hydrocarbons in the reservoir. Baker (1959) demonstrated that artifical solubilizers enhance the ability of saline water to solubilize and transport hydrocarbons.

Baker (1962) ultrafiltered dilute petroleum acid soap solutions and found two kinds of colloidal particles present at all finite concentrations. One type he called a small ionic micelle and the other a large neutral micelle. Accord- ing to him, “the presence of these colloidal particles in water increases the water solubility of hydrocarbons by providing hydrocarbonlike regions in which the hydrocarbon solutes preferentially and selectively dissolve. The relatively small, spherical, isotropic micelle appears to enhance hydrocarbon solubility chiefly by incorporating hydrocarbons on its surface. However, hydrocarbons may be accommodated within the interior of the larger, cylindrical, anisotropic micelle, as well as on its surface.” He found that paraffinic, naphthenic, and aromatic hydrocarbons possess different solubilities in the different kinds of micelles. I t has not been demonstrated that these micelles occur in nature, however.

Peake and Hodgson (1966 and 1967) studied the accommodation of C12-C3, n-alkanes in water. They found that it is possible to accommodate various hydrocarbons in water in the range of 0.01-100 ppm. Levels this high are more than adequate to account for known petroleum reserves. For example, Hunt (1961) estimated a ratio of 27/1 for the volume of dispersed hydrocarbons in sediments to oil in reservoirs, or that about 3.6% of the dispersed hydrocarbons are trapped in reservoir. Further, it can be shown that only approximately 1.8 ppm of the source hydrocarbons need t o be reservoired to account for the known oil reserves, assuming that the source sediments contain an average of 50 ppm of hydrocarbon. Hodgson et al. (1964) estimated that it would be necessary t o mobilize only about 1 ppm of the hydrocarbons from the source sediment to the reservoirs to account for known reserves.

The odd/even carbon ratio is different in recent sediments, from ancient sediments and from most crude oils (Bray and Evans, 1961). Baker (1959) and Peake and Hodgson (1966) concluded that the odd carbon preference does not persist in the mobilizing water because the accommodation of hydrocarbon in water is a function of its properties rather than supply.

GENERATION AND MIGRATION 297

Welte (1965) extracted some bituminous rock samples with oilfield brines which had been cleaned of traces of hydrocarbons. The extracted n-paraffins had an approximately equal carbon number distribution.

Cooper and Bray (1963) postulated a mechanism whereby the carbon number distribution may change when fatty acids are dissolved in water. Each fatty acid can lose COz to form an intermediate product which reacts to produce an n-paraffin and a fatty acid. The products have one less carbon atom than the original fatty acids. The oilfield waters that they investigated contained fatty acids with 14-30 carbon atoms with a balanced distribution between even and odd carbon numbers.

Kartsev et al. (1959) reported that some oilfield waters contain up to 5,000 mg/l of sodium naphthenate. Gullikson et al. (1961) found 5,000 t o 8,000 mg/l of organic acid salts in oilfield waters from the Ventura Basin. Collins (1969) reported that some waters from the Anadarko Basin contain up to 3,000 mg/l of organic acid salts. The presence of 50 mg/l of organic acid salts in waters could transport significant amounts of hydrocarbons out of source rocks.

It is apparent that petroleum hydrocarbons are generated from organic matter in sediments, that hydrocarbons are formed primarily at temperatures above 115'C through abiogenic reactions, and that water serves to transport the hydrocarbons from the sediments. I t is possible that the water also may transport. petroleum precursors from the sediment. These precursors might be released from the water phase when the environment is right and then be transformed into petroleum hydrocarbons.

Fluids in subsurface strata will move from regions of high potential to a low-energy region. The permeabilities of the strata influence how quickly equilibrium can be attained between high-energy and low-energy fluid potentials. The fluids will move toward the strata offering the least resistance and that have the greatest permeability. Generally the lower energy environment is straight up, but it may also be straight down or lateral. The source sediments may overlie a sand structure, in which case the migration is likely to be down into the sand structure which may serve as a reservoir.

Energy gradients which cause fluids to move are caused by potentials resulting from temperature, pressure, elevation, and osmotic forces which have not been completely described mathematically (Hitchon, 1969). Rapid tectonic uplift can alter the steady-state equilibrium in a basin.

Primary transit of hydrocarbon or precursors is this migration from the source sediment and usually is only for a short distance or far enough to reach a coarse-grained sediment. After they reach the coarse-grained sediment, they may or may not be trapped. Secondary migration occurs after the hydrocarbons or precursors move into the coarser grained sediment, and it may result in long or short-distance migration. The forces suggested above affect the migration. Once the petroleum and gas have separated from the aqueous phase they tend t o move to higher zones because of gravity segregation.


Accumulation

Compaction of sediments containing organic matter and water results in the expulsion of water and solubilized organic matter. Conceivably, the organic matter and gases can be solubilized or combined with the water phase as organic acid salts or as other soluble, colloidal, or suspended forms as a result of increased pressure. Meinschein (1959) outlined a method whereby ptroleum hydrocarbons may dissolve in compaction-expelled water, migrate, and later be unloaded to form an accumulation.

Cartmill and Dickey (1970) formed a crude oil in water emulsion and found that it freely passed through coarse sand. However, it tended t o coalesce with decreasing grain size. They attributed this to electrochemical and capillary phenomena. Such a process could operate in a subsurface environment and form a hydrocarbon accumulation. Related to this phenomenon, Kidwell and Hunt (1958) studied the hydrocarbon content produced from sands. They decided, “that in the lenticular sands hydrocarbons are being filtered out of the moving stream of water by capillary action.”

Jones (1968) gives some data illlustrating the relation of pressure differentials to salinity differences in waters attributed to osmotic flow of water through a clay-shale membrane. He found that the salinity differential may exceed 100,000 mg/l between two aquifers separated by a 10- to 50-m layer of clay-shale. Waters carrying dissolved or solubilized hydrocarbons could release them because of salting out when contacting highly saline brines because water will accommodate less hydrocarbon as its dissolved salt concentration increases (Baker, 1967). I t also has been speculated that the solubilized or dissolved hydrocarbons may be unloaded from the aqueous phase because of temperature or presssure changes, filtration, salinity changes, or the attraction of the organic constituents in the water for a hydrocarbon accumulation.

According to Baker (1962), “the nature of the oil, whether paraffinic, naphthenic, or aromatic, probably depends less on the nature of the hydrocarbons originally available in the sediments for collection than on the proportions of neutral and ionic micelles that were able t o release crude oil droplets for subsequent pooling in the reservoir rock. It appears that the frequency distribution of hydrocarbons in crude oil reflects variations in the kind and size of the micelles in which the sediment hydrocarbons selectively dissolve. The subsequent release of solubilized hydrocarbons from aqueous solution results in the accumulation of oil. The hydrocarbons, after under- going this solution and release process, would exist in the proportion characteristic of hydrocarbon occurrence in crude oil.”

Welte (1965), in discussing the micelle theory, noted that Neumann “distilled several crude oils and observed that the surface tension of the distillate decreased and the dielectric constants increased with increasing boiling point. This means that the polar surfaceactive molecules which are

ALTERATION 299

necessary for the formation of micelles are enriched in the high molecular- weight fraction.” The surface-active components were phenols, and it was found that the interfacial tension between oils and a buffered solution was strongly pH dependent, suggesting that pH variations in pore solutions are important for stability of micelles.

Hodgson and Hitchon (1966) theorized that surfactants aid in the mobilization of hydrocarbons in water, allowing them to migrate. During migration, the surfactants may decompose, leaving the hydrocarbons in an unstable state in the water phase. If the water is moving, the hydrocarbons will have a tendency not to agglomerate, but in a hydrostatic quasi-stagnant area the hydrocarbons will tend to separate by gravity t o form an accumulation.

Hydrocarbons accumulate in areas called traps, and these traps sometimes are structural traps such as an anticline or stratigraphic traps such as permeability barrier. Accumulations of hydrocarbons in oil pools apparently form by the release of hydrocarbons from a water system. The hydrocarbons accumulate subsequent to their migration, and the volume of water associated with their migration is large; however, tremendous volumes of water are available in the subsurface, and large amounts of water are freed by diagenesis or alteration of clays.

Baker (1967) postulated that the “tar mats” that form near the edges of sedimentary basins can be attributed to organic solutes moving in a water phase. The water merely evaporates at the sediment-air interface with complete release of the heavy oil solute containing compounds of carbon, hydrogen, nitrogen, oxygen, and sulfur.

Because the solubilities of petroleum hydrocarbons increase with temperature and decrease with increasing salinity, a mechanism for petroleum accumulation can be formulated. Upward moving subsurface waters will decrease in temperature, and as they move upward, the pressure will be lower, and they may meet more saline waters. Because of these changing conditions they will release dissolved hydrocarbons.

Alteration

Hydrocarbons are subject to alteration as soon as they are formed. The long-chain alkanes may react with other chemicals associated with the water phase, resulting in bond breaking and the formation of a shorter chain alkane. Organic acid salts may form which are relatively soluble in water and they may be further altered if the redox potential or pH of the water changes. The pH may change because of release of carbon dioxide associated with a hydrocarbon reaction. The hydrogen proton in the low pH water will react with dissolved organic acid salts, causing a reversion to the less soluble organic acid, which will disaccommodate from the aqueous phase.

A positive change in the redox potential of the water could cause oxidation of dissolved or associated hydrocarbons. A negative change in the redox

300 EFFECTS O F WATER ON PETROLEUM

potential will aid in preserving the hydrocarbon, but if the redox should become extremely reducing, it could cause hydrogenation of the hydrocarbons, this is, however, very unlikely. Reservoired oil becomes lighter with depth in all productive sedimentary basins; this usually is attributed to increased cracking of the larger hydrocarbon molecules into smaller ones, and is associated with increased temperatures (Philippi, 1965). This process requires more hydrogen for the smaller molecules, which may result in con- densation and polymerization of large molecules. Ultimately, with deeper burial and higher temperature, the hydrocarbons would be converted to methane and graphite (Fig.9.1).

Water washing

Water washing is a simple dissolving of light hydrocarbons by water moving past a reservoir. The water washing causes the hydrocarbon accumu-

Oi l migrated l o here

Fig.9.2. Alteration of an oil accumulation caused by tectonism and moving water.

ALTERATION 301

lation to become more concentrated in heavy hydrocarbons with a lower API degree gravity because of fractionation.

Water washing occurs when fresh water infiltrates through an outcrop and flows through the zone containing a structurally trapped hydrocarbon accumulation. Examples of this type are found in the Rocky Mountain area.

Tectonic disturbances can cause the hydraulic potential associated with a hydrocarbon accumulation to become dynamic. The resulting hydrodynamic situation can cause severe alteration of the hydrocarbon accumulation. Fig. 9.2 illustrates how oil may migrate to another reservoir if the strata are tilted, causing oil t o spill from a structural trap. This phenomenon can be observed in the Rocky Mountain area, where the first row of anticlines at the edge of a basin often are barren of hydrocarbon accumulation.

Bacterial

Biological degradation of a hydrocarbon accumulation is more complex than water washing. I t results from the introduction of bacteria into the reservoir or the reactivation of dormant species.

Alteration of petroleum by bacteria cannot be directly termed alteration because of water, but water indirectly aids the alteration because water must be present so that the bacteria can live. Aerobic bacteria can exist and thrive at the surface or in the subsurface only if several conditions are met, and these requirements as listed by Beerstecher (1954) and Davis (1967) include the following: (1) Water: water must be present t o serve as a medium in which the

bacteria can live. (2) Bacteria: the bacteria themselves must be present. (3) Nutrients: certain inorganic trace nutrients must be present. (4) Temperature: bacteria can exist at temperatures up to about 90°C but

thrive at temperatures of less than 60°C. (5) Food: a supply of food such as organic matter or petroleum must be

present. (6) Toxics: bacterial poisons such as hydrogen sulfide must not be present

in excessive concentrations. (7) Oxygen: aerobic bacteria require free oxygen dissolved in the water

medium in which they live. Obviously all of these conditions are most easily met at the surface and

the heavy oils and tars common to oil seeps are products of fractionation and aerobic degradation of crude petroleum. Bacterial alteration of petroleum can also occur below the surface of the earth if the prerequisite conditions are met. These conditions, especially the presence of dissolved oxygen, occur only where subsurface waters are in hydrodynamic connection with the surface and are actively receiving surface-recharge waters. The presence of free oxygen is critical although it generally exists in very small concentrations, Kuznetsov (1957) measured the dissolved oxygen content in.


waters from wells in the Groznyv oil district and found up to 10.6 mg/l at a depth of 249 m. In general, dissolved oxygen was found only in the zone of active water circulation (surface recharge) and was lacking in the zone of stagnate water.

Dissolved oxygen in smaller concentrations (less than 1 ppm) sustains aerobic bacteria and controls the rate at which they consume food (organic matter and petroleum). Since the oxygen content of subsurface waters usually is low, alteration and consumption of petroleum in reservoirs may require thousands or even millions of years to achieve a significant degree of change.

Kuznetsov (1 957) made bacterial counts in produced subsurface waters and found that the number of bacteria varied directly with the rate of exchange of water (recharge). The amount of dissolved oxygen varied directly with the rate of recharge, and the size of the bacterial population is dependent upon the amount of oxygen available. Aerobic bacteria in outcropping rocks were carried into the subsurface by recharge waters and were sustained by dissolved atmospheric oxygen in such waters.

Apparently the rate at which bacteria are able t o move depends only on the amount of available oxygen and food. All digestible organic matter in the carrier bed along the recharge path would have t o be removed before the bacteria could proceed. Biodegradable organic matter in the carrier bed would be depleted as the oxygen “front” advanced and would permit free oxygen to reach great distances into the subsurface. The ultimate advance of bacterial alteration depends principally on time and temperature. If favorable conditions are present for sufficient time, bacterial alteration can reach great distances if the temperature remains below about 6OoC. Although some forms of bacteria can exist at temperatures up to about 90°C, they apparently are in a dormant state above about 6OoC (Davis, 1967).

Zobell (1949, 1950, 1952) found that all kinds of hydrocarbons appear to be susceptible t o bacterial action, even though the process is selective. In general, aliphatic hydrocarbons and aliphatic side chains on cyclic compounds are most susceptible to attack while naphthenes and aromatics are least affected. Bacteria prefer the normal alkanes over the branched alkanes and concentrate on the heavier molecules, rarely touching hydrocarbons as light as C 3 .

Bacteria consume alkanes at a hydrocarbon fermentation plant at Grange- mouth, England (Anonymous, 1971). The nearly pure mixture of paraffins is prepared from crude oil by molecular sieving. The microorganisms assimi- lated the material with little waste and produced microbial protein which is used in animal feed.

After consumption of the normal alkanes, branched chain alkanes are attacked (Winters and Williams, 1971), as are long chains attached to aromatic and naphthenic rings (Davis, 1967). Bacteria usually reject ring compounds and many aromatics are toxic to bacteria. However, with ideal conditions, bacteria can break naphthenic rings and consume them. Because

ALTERATION 303

bacterially altered oils contain less paraffinic hydrocarbons than unaltered oils of the same type, they have higher correlation index values (Smith, 1940) and a lower API gravity.

Winters and Williams (1971) found an increase in nitrogen and optical activity disproportionate to n-paraffin loss in altered Powder River Basin ofis in Wyoming and suggested that microbially produced materials are added to altered oils. Bailey and Krouse (1970) observed an increase in weight percent sulfur and asphaltenes and a decrease in saturates (alkanes) in altered Williston Basin crudes. The relative increase in asphaltenes because of the selective loss of lighter saturates leads t o increased viscosity of highly altered oils. The results of bacteria alteration are evidenced by heavy residual oils common t o oil seeps and breached oil accumulations such as the Athabasca tar sands.

A bacterially altered paraffinic crude differs from a similarly altered asphaltic crude. Altered paraffinic crudes contain higher percentages of asphaltene and naphthene compounds than their unaltered counterparts, and usually are liquid and mobile. In contrast, severe alteration of asphaltic crude produces a solid, immobile tar. In the subsurface, the formation of tar seals halts bacterial alteration and may even act as a trapping mechanism for an accumulation. An example of oil residue providing a seal occurs in the Bolivar Coastal fields of the Maracaibo Basin in Venezuela (Brenneman, 1960).

The Maracaibo Basin oils have an asphaltic base, and bacterial alterahion has produced heavy residues which provides a seal (Rubio, 1959). Appar- ently, secondary migration of the oils occurred in a carrier-bed system exposed at the surface. Oil migrated updip without being trapped until it reached meteoric recharge waters about 5-10 km from the outcrop. Here, aerobic bacteria reduced the n-paraffin content of the oil, causing an asphaltic gel t o precipitate which reduced the porosity and permeability, preventing further migration and allowing oil to accumulate. An example are the vast reserves of Lagunillas field found in a massive sand downdip from an asphaltic seal in an area devoid of structural of stratigraphic txappng mechanisms .

Three types of oil exist in the Bell Creek field, which is a large stratigraphic trap on the northeast flank of the Powder River Basin. The field contains common reservoirs, but the oil at the south was not altered and contained a full spectrum of n-paraffins, while in the middle of the field all n-paraffins were absent and the oil at the north was deficient in n-paraffins up to C1,. Selective loss of n-paraffins up to C1, caused by microbiological activity occurred (Winters and Williams, 1969).

The Bell Creek altered oils also had lower API gravity, higher nitrogen content, and higher optical rotation than their unaltered counterparts. The Bell Creek field is associated with fresh meteoric water in its central and northern portions but has no oil-water contact at its southern end, the downdip limit of production in that area being defined by absence of reser-


voir sand. Evidence of aerobic organisms was found in waters produced with altered Bell Creek oils; oils in the Hackberry field, Louisiana, were bacterially altered by loss of n-paraffins and singly branched isoparaffins, and in North Africa an oil was depleted in n-paraffins.'

Conclusions

A suitable mechanism for removing water and organics from source sediments is compaction and squeezing of the fluids into adjacent beds either vertically, laterally, or below. Accommodation of hydrocarbons or hydrocarbon precursors in the aqueous phase appears to be a probable means of primary migration. Variations in salinity, pressure, temperature, pH, redox potential, capillarity, hydrodynamics, or lithology may cause dissolution of mobilized hydrocarbons and serve to begin an accumulation. Finally, the moving waters can serve to alter an accumulation.

Alteration of crude oils in the reservoir by water washing and biodegradation is common t o many producing areas and affects a significant portion of the world's reserves. Biodegradation is most prevalent in shallow-basin flank environments where fresh meteoric water reaches into the subsurface and carries with it aerobic bacteria and the oxygen necessary to sustain them. Bacterial alteration selectively removes n-alkanes first, followed by isoal- kanes and aliphatic side chains on cyclic compounds, leaving an oil relatively enriched in naphthenes, aromatics, asphaltenes, and sulfur compounds. The API gravity is lowered, and the nitrogen content and optical activity are increased. Asphaltic base oils may be reduced t o an immobile tarry residue that can block porosity and form a seal which may trap oil. Alteration of paraffinic based crudes produces the so-called naphthenic oils, which, because of their relatively small asphaltene content, remain mobile even under advanced alteration conditions.

References

Anonymous, 1971. Food from oil. Nature, 229:79. Bailey, N.J.L. and Krouse, H.R., 1970. Chemical aspects of crude oil preservation

Baker, E.G., 1959. Origin and migration of oil. Science, 129 (3353):871-874. Baker, E.G., 1962. Distribution of hydrocarbons in petroleum. Bull. A m . Assoc. Pet.

Geol., 46 (1):76-84. Baker, E.G., 1967. A geochemical evaluation of petroleum migration and accumulation.

In: B. Nagy and U. Colombo (Editors), Fundamental Aspects of Petroleum Geo- chemistry. American Elsevier, New York, N.Y., pp.299-329.

Beerstecher, Jr., E., 1954. Petroleum Microbiology - A n Introduction to Microbiological Engineering. American Elsevier, New York, N.Y., 375 pp.

Bray, E.E. and Evans, E.D., 1961. Distribution of n-paraffins as a clue to recognition of source beds. Geochim. Cosmochim. Acta, 22:2-15.

Brenneman, M.C., 1960. Chemical study of crudes of the Maracaibo Basin: Venezuela. Direc. Geol., Bol. Geol., Publ. Espec., No.3, Part 3, pp.1025-1069 (in Spanish).

(abstract). Bull. Am. Assoc. Pet. Geol., 54:834-835.

REFERENCES 305

Burst, J.F., 1969. Diagenesis of Gulf Coast clayey sediments and its possible relation to petroleum migration. Bull. A m . Assoc. Pet. Geol., 53 (1):73-93.

Cartmill, J.C. and Dickey, P.A., 1970. Flow of a disperse emulsion of crude oil in water through porous media. Bull. Am. Assoc. Pet. Geol., 54 (12): 2438-2447.

Collins, A.G., 1969. Chemistry of some Anadarko Basin brines containing high concentrations of iodide. Chem. Geol., 4:169-187.

Cooper, J.E. and Bray, E.E., 1963. A postulated role of fatty acids in petroleum formations (preprints). A m . Chem. SOC., Div. Pet. Chem., 8 (2):A17-A28.

Corbett, C.S., 1955. In situ origin of McMurray oil of northeastern Alberta and its relevance to general problem of origin of oil. Bull. A m . Assoc. Pet. Geol., 39 (8):1601-1649.

Davis, J.B., 1967. Petroleum Microbiology. American Elsevier, New York, N.Y., 604 pp. Emery, K.O., 1960. The Sea Off Southern California: A Modern Habitat of Petroleum.

John Wiley and Sons, New York, N.Y., 366 pp. Gullikson, D.M., Caraway, W.H. and Gates, G.L., 1961. Chemical analysis and electrical

resistivity of selected California oilfield waters. U.S. Bur. Min. Rep. Invest., No.5736, 21 PP.

Hedberg, H.D., 1964. Geologic aspects of origin of petroleum. Bull. Am. Assoc. Pet. G e o i , 48 (11):1755-1803.

Hitchon, B., 1969. Fluid flow in the Western Canada Sedimentary Basin, 2. Effect of geology. Water Resour. Res., 5:460-469.

Hodgson, G.W. and Hitchon, B., 1966. Research trends in petroleum genesis. In: Petroleum --roc. Eighth Common. Min. Metall. Congr., Aust. N.Z. Paper 34, 59-19.

Hodgson, G.W., Hitchon, B. and Taguchi, K., 1964. The water and hydrocarbon cycles in the formation of oil accumulations. In: I. Miyake and T. Koyamer (Editors), Recent Researches in the Fields of Hydrosphere, Atmosphere, and Nuclear Geochemistry. Maruzen, Tokyo, pp.217-242.

Hunt, J.M., 1961. Distribution of hydrocarbons in sedimentary rocks. Geochim. Cosmochim. Acta, 22:37-49.

Jones, P.H., 1968. Geochemical hydrodynamics - a possible key to the hydrology of certain aquifer systems in the northern part of the Gulf of Mexico Basin. Proc. 23rd Int. Geol. Congr., Prague, 1968, 17:113-125.

Kartsev, A.A., Tabasaranskii, Z.A., Subbotta, M.I. and Mogilevskii, G.A., 1959. Geo- chemical Methods of Prospecting and Exploration for Petroleum and Natural Gas. University of California Press, Berkeley, Calif., 349 pp.

Kidwell, A.L. and Hunt, J.M., 1958. Migration of oil in recent sediments in Pedernales, Venezuela. In: L.C. Weeks (Editor), Habitat o f Oil. American Association of Petro- leum Geologists, Tulsa, Okla., pp.790-817.

Kuznetsov, S.I., 1957. A review of fundamental research on the microflora of petroleum deposits. Mikrobiologiya, 26 (6): 651-658.

Levorsen, A.I., 1954. Geology of Petroleum. W.H. Freeman, San Francisco, Calif., 703 PP.

"McIver, R.D., 1963. Maturation of oil, an important natural process. Geol. SOC. Am. Annual Meet., 1963 Paper, 15 pp.

Mehschein, W.G., 1959. Origin of petroleum. Bull. Am. Assoc. Pet. Geol., 43:925-943. Peake, E. and Hodgson, G.W., 1966. Alkanes in aqueous systems, I. Exploratory investiga-

tions on the accommodation of Czo-C33 n-alkanes in distilled water and occurrence in natural water systems. J. Am. Oil Chem. SOC., 43 (4):215-222.

Peake, E. and Hodgson, G.W., 1967. Alkanes in aqueous systems, 11. The accommodation of C, *-C36 'n-alkanes in distilled water. J. Am. Oil Chem. SOC., 44 (12):696-702.

Philippi, G.T., 1965. On the depth, time, and mechanisms of petroleum generation. Geochim. Cosmochim. Acta, 29:1021-1049.

3 06 EFFECTS OF WATER ON PETROLEUM

Powers, M.C., 1967. Fluid-release mechanisms in compacting marine mudrocks and their importance in oil exploration. Bull. Am. Assoc. Pet. Geol., 51:(7) 1240-1254.

Price, L.C., 1973. Solubility of petroleum in water as function of temperature and salinity and its significance in primary migration. Bull. Am. Assoc. Pet. Geol., 57:801.

Rubio, F.E., 1959. The conditions of the accumulation of petroleum of the Costaueros Fields, in the Bolevar District, Lake Maracaibo. Tercer Congr. Geol. Venezolana, Mem., 3:1009-1023 (in Spanish).

Schmidt, G.W., 1971. Interstitial Water Composition and Geochemistry o f Deep Gulf Coast Shales and Sands. M.S. Thesis, University of Tulsa, Tulsa, Okla., 121 pp.

Smith, H.M., 1940. Correlation index to aid in interpreting crude-oil analyses. U.S. Bur. Min. Tech. Rep., No.610, 34pp.

Terzaghi, K. and Peck, R.B., 1948. Soil Mechanics in Engineering. John Wiley and Sons, New York, N.Y., 566 p9.

Von Engelhardt, W. and Gaida, K.H., 1963. Concentration changes of pore solution during the compaction of clay sediments. J. Sediment. Petrol., 33 (4):919-930.

Weaver, C.E. and Beck, K.C., 1969. Changes in the clay-water system with depth, temperature, and time. O f f Water Resour. Res. Project N0.A-008-GA WRC-0769, Georgia Inst. Technol., Completion Rep., 95 pp.

Welte, D.H., 1965. Relation between petroleum and source rock. Bull. Am. Assoc. Pet. Geol., 49 (12):2246--2268.

Winters, J.C. and Williams, J.A., 1969. Microbiological alteration of crude oil in the reservoir (preprints). Am. Chem. SOC., 14(4):E22-E31.

Winters, J.C. and Williams, J.A., 1971. Microbiologic alteration of crude oil in muddy sandstone and other reservoirs. Bull. Am. Assoc. Pet. Geol., 55:369.

Zobell, C.E., 1949. Action of microorganisms on hydrocarbon. Am. Pet. Inst. Rep. Progr. 1946-1947, pp. 107-132.

Zobell, C.E., 1950. Assimilation of hydrocarbons by microorganisms. Adu. Enzymol., 10:443--468.

Zobell, C.E., 1952. Part played by bacteria in petroleum formation. J. Sediment. Petrol., 22:42-49.

Chapter 10. GEOCHEMICAL METHODS OF EXPLORATION FOR PE- TROLEUM AND NATURAL GAS

The current worldwide concern for energy resources results from the fact that man eases his burdens and accomplishes enormous amounts of work by harnessing mineral energy. His material progress is reflected by the amount of energy his machines consume, and the continued upward thrust of such progress is dependent upon the supply of mineral fuels. In the United States this energy has eased the burdens of man to the extent that every person in the U.S.A. has available the energy equivalent of the output of 260 men. About 33% of the total mineral energy demand is supplied by natural gas and about 42% by crude oil. In 1967 the U S . demand for natural gas was 17.7 trillion cubic feet and the demand for crude oil was 4.5 billion barrels. The demand for both is expected to double by the year 2000.

Improved methods of finding petroleum and gas are needed. Many investigators believe that the application of geochemical methods in conjunction with geological and geophysical methods can markedly improve the discovery ratio. Data presented in this chapter primarily are in the form of an annotated survey of the available literature and many of these data were taken from Petroleum Abstracts with permission of H.O. McLeod (1971).

Introduction

Type of methods

Geochemical methods of exploring for petroleum and gas can be termed

(1) Analysis of soil samples to determine the amounts of hydrocarbon

(2) Analysis of free hydrocarbons in soils. (3) Analysis of soils to determine the amounts of soil wax, paraffin dirt,

and other bitumens. (4) Analyses of waters t o determine their amounts of dissolved hydrocar-

bons. These methods are classified as direct because the determined constituents

are present in accumulations of petroleum and gas or derived from them. The indirect methods are as follows:

(1) Measure the oxidation-reduction potential of soils, rocks, and waters. (2) Analyze soil samples for various salts such as bromides, chlorides,

direct and indirect. The direct methods are as follows:

gases adsorbed by the soil.

carbonates, and sulfates.

308 EXPLORATION FOR PETROLEUM AND GAS

(3) Analyze plants to determine if their growth is affected by petroleum- type bitumens.

(4) Analyze soil samples for bacteria such as the types that consume hydrocarbons.

The indirect methods are so classified because the determined properties may have originated from something other than petroleum or gas accumulation (Rosaire, 1939; Kartsev et al., 1959). Collected data from both the direct and indirect methods usually are plotted or contoured to form maps to identify anomalies and to locate a target area for drilling.

Case histories

A geochemical soil survey led t o the discovery of an oilfield in the Texas Gulf Coast (Stormont, 1939). Three hundred geochemical surveys were made in 1939 with a greater than 50% success ratio (Simons, 1940). A gas discovery at Stroud, Oklahoma, was attributed t o geochemistry (Rosaire et al., 1940). Pirson (1942) determined the success ratios for the following exploration methods: random drilling, 5.8%; geology, 8.2%; geophysics, 14.9%; and geochemistry, 57.8%.

Geochemistry predicted the discovery in Oklahoma of the West Edmond field (Bronston, 1947). The Hardy field in Texas was found by drilling into a geochemical anomaly where reflection seismographs gave no indication of a stratigraphic trap (Ransone, 1947). The Soviet Union attributes a 70% success ratio to wells drilled into geochemical anomalies (Sokolov et al., 1959). The success of geochemical methods is outstanding when compared to the overall success ratio for wildcats (Anonymous, 1960b). A company using an indirect inorganic geochemical technique achieved a 25.5% success ratio, which is more than double the usual wildcat ratio (Anonymous, 1959).

Success ratios of 65% and 75%, respectively, were obtained using geochemical anomalies in the Texas Gulf Coast and North Texas areas (Anonymous, 1960a). The Kohav oilfield in Israel was discovered solely through hydrocarbon geochemistry, and geochemistry successfully predicted that stepout wells in this field and the Heletz field would be dry (Davidson, 1963).

Analytical techniques, type of hydrocarbon anomalies, and successful discoveries made by hydrocarbon geochemical studies in Texas were discussed by Horvitz (1969). According t o him, the anomalies become weak and tend to disappear after an oil accumulation is produced.

Note: The author has been told by representatives of various companies that research performed by them has produced evidence indicating that success ratios claimed for some of these exploration techniques cannot be met in actual practice. However, the author is at a loss t o cite references to this effect because there are no documented published data available.

INTRODUCTION 309

Source rocks

There are three basic elements relevant to hydrocarbon accumulations: (1) source rock; (2) trap; and (3) reservoir. Before any hydrocarbons can accumulate in commercial quantitites, a source rock must be present. Concepts of hydrocarbon generation from source rocks have been reviewed by Hedberg (1964), Erdman (1965), Philippi (1965), Welte (1965), Landes (1967), Tissot et al. (1971), and Klemme (1972).

Crude oil is liquid in its natural state and is composed primarily of hydrocarbons often combined with nitrogen, sulfur, and oxygen. Examples of some hydrocarbons found in petroleum are shown in Fig. 10.1. Natural gas is a gas in its natural state composed primarily of hydrocarbons often mixed with carbon dioxide, hydrogen sulfide, and nitrogen. Examples of hydrocarbons found in natural gas are shown in Fig. 10.2.

Organic matter in rocks usually is divided into the part that is soluble in common organic solvents and the part that resists these solvents. The non- soluble organic matter is called kerogen, and the amount of kerogen and soluble matter can be estimated from their respective carbon contents. The hydrocarbons in the soluble matter are of primary value in evaluating a source rock. The evaluation of total organic carbon in rocks can serve as an

ALKANES

c-c-c-c-c-c-c c-c-c-c-c I C

I C

Porottin

Bronchrd Porottin

Tricyclic Monocyclic Bicyclic

CYCLOPARAFF INS (nophthrnrsl

AROMATICS

Pyrrne

Fig.lO.1. Some of the types of hydrocarbons found in petroleum.


N O R M A L P A R A F F I N S

H H H H H H I 1 I I I I

H-C-C-C-H H-C-C-H

H H H H H Methane Ethone Propane

I I

I I I

I H-C-H

H

Fig.lO.2. Some of the hydrocarbons found in natural gas.

indication of a source rock for further estimation of the hydrocarbon potential of a target area.

Organic matter in all sedimentary rocks is about 2% of the rock mass, and the amount of trapped oil is about 1.25 x The Clarke for organic carbon is 1.14% in shales and 0.24% in carbonates (Gehman, 1962). Forsman and Hunt (1958) found that the ratio of organic material t o organic carbon in rocks ranges from 1.07 to 1.22. Philippi (1969) found that the ratio between soluble carbon and total carbon CJCt must be greater than 3 for shale before it can be construed to be a source rock.

Good source rocks contain more than 130 ppm of petroleumlike hydrocarbons; fair source rocks, 40-130 ppm; and poor source rocks, less than 40 ppm (Hunt and Meinert, 1954). Philippi (1957) extracted several shale samples and made a similar conclusion. His ranges were more than 500 ppm good, 50-500 ppm fair, and less than 50 ppm noncommercial.

Analysis of the gases in cores and cuttings can be used to identify source rocks (FeugGre and Gkrard, 1970). Hydrocarbons with carbon numbers below CI4 usually occur in source rocks (Dunton and Hunt, 1962), but the recent sediments do not contain light hydrocarbons (Erdman, 1967), indicating that long periods of time are necessary in the hydrocarbon generation process.

Commercial accumulations of oil usually are associated with marine shales or with organic-rich, fine-grained limestones. A shale commonly contains 0.5% or more organic matter and a limestone 0.2% before oil begins to occur. The kind and amount of organic matter in a rock indicate its source potential (Hunt and Meinert, 1954). Less than 5% of the organic matter in sediments eventually becomes petroleum; therefore, about 95% of it remains in the source rocks (Hunt and Jamieson, 1956; Philippi, 1957).

Trask and Patnode (1942) studied about 35,000 rock samples and found that the average amount of organic matter in rocks in close proximity t o oilfields was about 1.5%. According t o Hunt (1967), more hydrocarbons appear to be generated by fine-grained carbonate rocks than by other types of rocks containing the same amounts of organic matter.

Philippi (1969) concluded that petroleum is generated by chemical reactions at relatively low temperatures, from source rocks. He further concluded that bacteria alone do not transform organic material into petroleum,

INTRODUCTION 311

and that radioactive bombardment of organic matter contributes little t o the formation of petroleum. His study of the shales and oil from the Los Angeles Basin indicated that the Upper Miocene divisions of the D and E shales form the major source of oil; this was the first documentation of oil source rock identified by comparing the composition of crude oil and shale hydrocarbons. He believes that lipids are the major precursors but that precise data concerning the chemical conversion of lipids t o petroleum components are lacking.

Silverman (1964) summarized available data and concluded that petroleum is derived from lipids and that the r3C/12C 6-values indicate that the ranges for the lipid fractions of marine and land plants cover the ranges found in all petroleums. He suggested that polymers are a petroleum hydrocarbon nrecursor. Organic acids were suggested as hydrocarbon sources by Cooper and Bray (1963).

Ferguson (1962) derived a quantitative method of determining hydrocarbons in sediments, using benzene (rather than mixed solvents), the benzene is evaporated, and the extract residues are resolved using silica gel chromatography. This method was used in an organic geochemistry study of the Cherokee Group rocks in Kansas and Oklahoma (D.R. Baker, 1962).

A quantitative method using electron spin resonance spectrometry was used to evaluate the maturation stage of potential source rocks (Pusey, 1973). The method is effective for all types of rocks and all types of kerogens.

Water and hydrocarbons

Because of the need to locate gas and oil reserves, better hydrogeochemical exploration methods are needed. Water affects the accumulation and migration of hydrocarbons. Water flowing from compacting sedimentary rocks moves the oil precursors from source rocks before they concentrate in a trap area.

Peake and Hodgson (1966, 1967) found that water can accommodate up to 150 ppm of C,,-C,, hydrocarbons as a fine colloidal suspension. Low- molecular-weight hydrocarbons such as benzene, methane, ethane, and propane are somewhat soluble in brines and water; however, the normal paraffins and cycloparaffins with carbon numbers greater than C8 are rather insoluble (McAuliffe, 1969), and the insoluble ones are the main constituents of most crude oils. E.G. Baker (1962) postulated that micelles of oil (colloids) may be transported by water; however, the effects of temperature, p ~ s s u r e , and flow through sedimentary rock need further study. Spencer and Koons (1970) theorized that hydrocarbon precursors may be transported in water as compounds of nitrogen, oxygen, or sulfur, which later are reduced t o hydrocarbons. Cartmill and Dickey (1970) stabilized an emulsion of crude oil in water where the globules averaged 1 p in diameter, and the emulsion passed through sand but coalesced as the grain size decreased.


According to them, the coalescing process may be an electrochemical rather than a capillary phenomenon.

Baker (1960) suggested that salts of organic acids form clusters or micelles in water solution and that these colloidal particles increase the solubility of hydrocarbons by providing hydrocarbonlike regions within the water. An. equation was developed which postulates a relation between the abundance of a hydrocarbon in a crude oil and micellar water solubility.

Fig.lO.3. Illustrations of (a) structural and (b) stratigraphic traps.

The precise manner whereby oil leaves a source rock is not known, but it apparently is related t o the flow of water from compacting sediments. A better understanding of the migration process will aid in locating reserves of oil and especially those in stratigraphic traps or in a combination of stratigraphic and structural traps. Fig. 10.3 illustrates these types of traps.

HYDROGEOCHEMICAL RESEARCH AND METHODS 313

Hydrogeochemical research and methods

Organic compounds

Saturated hydrocarbons Davis and Yarbrough (1969) invented a geochemical prospecting method

which involves the analysis of formation waters for the saturated hydrocarbons: normal decane, isodecane, butyl cyclohexane, and pentyl cyclohexane. The presence of these hydrocarbons in the formation water is indicative of petroleum accumulations.

Buckley et al. (1958) studied the dissolved hydrocarbon gases in waters of petroleum-bearing strata and determined the “escaping pressure” or the pressure at which the gas started t o come out of solution. Most of the gas in solution was methane with lesser quantities of ethane and heavier gases. The results indicated that the gases generally diffuse into the edgewater rather short distances from the margins of oil fields.

Kortsenshtein (1965) outlined a general solution for the problem of determining the oil and gas potential of subsurface strata from data of the gas saturation of subsurface waters under dephased equilibrium conditions. His study indicated that water that is saturated or supersaturated with hydrocarbon gases can positively be used t o predict whether oil and gas are present in traps, while waters that are not saturated with hydrocarbon gases cannot be used to make a positive prediction.

It was observed: (1) that .the direction of increasing saturation indicates the direction of the accumulation; (2) that a relatively accurate target location can be obtained by determining where the increasing saturation pressure intersects by using data from two or more wells; (3) that an increase in pressure of saturation stratigraphically upward in a well may indicate an approach to a gas-water contact; (4) that a constant saturation pressure laterally presents an unsolvable problem, unless one has data on changes with depth; and (5) that interpretation of the size of the postulated accumulation is difficult (Kortsenshtein, 1964).

Continuous investigations made in the oilfields of the Dnepr-Donets Basin revealed a number of regularities in the composition and degree of gas saturation of groundwaters. In the presence of oil accumulations, the gas saturation of waters and the composition of the dissolved gases were determined with respect to the oil pool in a vertical and horizontal direction. The regularities of the gas saturation of these waters serve as a basis for oil exploration (Gutsalo and Krivosheya, 1965).

London et al. (1961) found three classes of gas-water relationships. The first is represented by formation waters undersaturated with gas in which the hydrocarbons dominate the chemistry of the water. Commercial gas pools are not probable under such conditions. Examples of these exist in the Jurassic and Cretaceous sediments of the West Siberia Lowland. A system in which predominantly hydrocarbon gases and formation water are in equi-


librium (that is, the gases are at saturation pressure) represents the second class. The third class is represented by a system in which the pressure of the dissolved gas is greater than the saturation value, free gas escapes, and the hydrocarbons are oxidized. Gas pools are likely to be found near the highly saturated water.

Bond (1962) patented a geochemical exploration method which com- plements conventional gravimetric, magnetic, seismic, and electrical geologic survey methods. The technique utilizes the analysis of gas samples, collected from earth or water samples obtained from locations in the proximity of hydrocarbon-containing reservoirs. The gas is analyzed t o determine the isotopic ratio '*C1H4 /13C1H4. If the samples .of oil-gas have not diffused a considerable distance through the earth, the normal ratio ordinary methane/ heavy methane is in the range of 89.5-93.5. If the gas has diffused up from a considerable depth, the ratio will be 0.5-2.5 units above normal, which in turn indicates the presence of petroleum.

Aromatic hydrocarbons Zarrella et al. (1967) found that the amount of benzene in formation

waters directly reflects the occurrence of a petroleum accumulation in a formation. They believe that vertical migration of hydrocarbons between aquifers is restricted and that lateral migration is limited. For example, Fig. 10.4 illustrates how the concentration of a hydrocarbon in a brine may vary with the distance of the brine from an oil pool.

Zinger and Kravchik (1969) believe that toluene and benzene in water are hydrochemical indexes which indicate the presence of oil and gas. Accumula- tions of oil and gas are the principal source of benzene and toluene in oilfield waters. The ratio benzene/toluene in these waters is greater than 1. Benzene in waters is considered one of the most important and direct indicators of oil and gas content (Kortsenshtein, 1968; Kartsev et al., 1969).

If the concentration of a measured aromatic hydrocarbon in a sample of formation water is equal to a target value, the point from which the sample was obtained is close to a reservoir of crude oil. Greater differences between these two values represent greater distance to the crude oil accumulation. The target value is determined by contacting the type of crude oil expected in the sampled reservoir with water solutions of salt and measuring the concentration of the aromatic hydrocarbon in the solutions. This determines the variation in concentration of this aromatic hydrocarbon as a function of the salinity of the dissolving water. The salinity of the sample of the water makes it possible to determine the target value; that is, the value of concentration of this aromatic hydrocarbon existing at the point of contact between crude oil and formation water (Schmidt, 1970).

daturnted, unsaturated, and aromatic hydrocar'bons McAuliffe (1 969) determined hydrocarbons dissolved in water by gas

chromatographic methods using a number of techniques to separate the


Fig.10.4. Relationship of the concentration of benzene in brines and proximity to an oil accumulation. (After Zarella, 1969.)

hydrocarbons from water. Separation methods include : (1) direct injection of the water sample; (2) equilibration of aqueous sample with immiscible solvent; and (3) equilibration of aqueous sample with gas. Some of the solubilities found in water were: n-hexane, 10 ppm; n-heptane, 3 ppm; n-octane, 0.6 ppm; cyclopentane, 156 ppm; benzene, 1,780 ppm; and iso- propylbenzene, 50 ppm (McAuliffe, 1966). McAuliffe (1967) obtained a patent for a geochemical method of prospecting for petroleum, which utilized the concentrations of dissolved hydrocarbons in oilfield brines to determine the location of a hydrocarbon accumulation.

Fatty acids Cooper and Kvenvolden (1967) analyzed samples of water from the sub-

terranean formations to determine the ratios of selected fatty acids. These ratios indicate the presence of a petroleum reservoir if the ratio of fatty acids containing an even number of carbon atoms to those containing an odd number of carbon atoms is not more than 1.6.


Organic acids Shvets and Shilov (1968) used a quantitative method t o determine water-

soluble organic substances in waters. Waters near oil accumulation deposits contained up to 3,500 mg/l of organic acids. Data on organic carbon, organic acids, and oil hydrocarbons in waters could be used as indicators of oil accumulations.

Organic acids dissolved in subsurface waters in the form of salts, or in the free state, indicate the removal of organic substances from rocks. This indicates the existence of geochemical processes in which deeply buried organic substances are being broken by decarboxylation, accompanied by the formation of hydrocarbons. Thus, organic acids and their salts may be considered a source for the formation of hydrocarbon accumulations (Shabarova et al., 1961).

Inorganic and organic compounds

Kolodii (1969) found two types of hydrochemical anomalies in the Pli- ocene deposits of the South Caspian Basin. The first is associated with structures in which the red bed part of the producing formation is at a shallow depth. I t manifests itself in sudden increase in dissolved solids in the water up to 300 g/l. The second anomaly is related t o the lower section and decreased dissolved solids 5-40 g/l. These waters are often of bicarbonate- sodium type and were formed by mixing oilfield water with condensate water which reacted with the host rocks. This hydrochemical inversion is related to processes accompanying migration of hydrocarbons into the zones of reduced pressure and temperature. The genetic relationship between hydrochemical anomalies and the presence of oil (gas) deposits can be used in oil exploration.

Compared to a general background, methane, heavy hydrocarbons, hydrogen sulfide, and carbonic acid concentrations in water increase with the approach to a gas and oil accumulation, while the content of sulfates decreases. The amount of helium in the zone depends upon the difference between its saturation in the waters and in the accumulation (Savchenko et al., 1965).

Sudo (1967) studied the major oil- and gasfields of Japan as related to subsurface water for the exploration of oil and gas deposits. The analytical data suggested that: (1) the SO,-2 concentration is extremely low, perhaps resulting from microbiological activity in the initial sedimentary environment; and (2) dissolved hydrocarbons and naphthenic acid salts in the brine are direct indicators, and I- and HC03 are indirect indicators of oil and gas accumulations.

Oilfield waters (as well as waters of gasfields and bituminous formations) are characterized by enrichments of the biophile elements K+, B+3, Br-, and I-. Alkaline waters with higher concentrations of carbonates and sulfates, and with naphthenic acids, are associated with naphthenic oils. Alkaline-

-

HYDROGEOCHEMICAL RESEARCH A N D METHODS 317

earth chloride waters with low-numbered fatty acids are associated with paraffinic oils ( Krejci-Graf, 1962).

In0 rgan ic compounds

Serebriako and Tronko (1969) found that the ammonium content of subsurface waters correlates with hydrocarbon deposits. The amount of ammonium found was above 80 mg/l in oil- and gas-bearing areas with lesser amounts in nonproductive areas.

Korobov (1965) determined that the main source of lithium, strontium, barium, manganese, copper, chromium, and aluminum in oilfield waters is related to the geochemical and biochemical environments which produced the oil and gas deposit accumulations. The elements potassium, boron, barium, iodide, strontium, barium, and gallium are enriched in oilfield waters (Krejci-Graf, 1962) and are an indication of bituminiferous formations.

The first transition series metals - iron, cobalt, manganese, nickel, vanadium, titanium, chromium, and scandium - are soluble in the reduced state but insoluble in the oxidized state and are useful in determining the proximity of petroleum deposits according t o a patent issued to Billings (1969). The method involves analyzing formation waters for one or more of the transition metals to determine a trend in the amounts of the metal in an area.

According to London (1964), the main indication of the presence of oil-gas in rocks is the presence of hydrogen sulfide and biogenic nitrogen, and the degree of sulfate reduction. The author recommends using the degree of sulfate reduction as a reliable exploratory criterion. The sulfate concentration decreases in the direction toward an oil accumulation. Sulfates cannot be regarded as reliable criteria if the water-bearing formation contains salt and gypsum.

The single most important common ground between hydrodynamics and log interpretations is the determination of formation resistivity (Rw ), which is related to the chemical makeup of the formation water. In waters with a high chloride-ion content, the chloride ion is (for all purposes) the resistivity-determining ion; but in cases where low-chloride salinity waters are present, other ions, particularly calcium and magnesium, can make material changes from the chloride-calculated resistivity. Chemical content and its variations can be used directly as a tool for finding oil. Variations in the chemical makeup of formation waters can be used to delineate separate reservoirs within the same formation, thereby indicating potential stratigraphic traps. The production engineer also benefits from detailed chemical analysis (Schwab, 1965).

Radioactive compounds Filonov (1969) investigated radioactive elements in underground waters of

the Devonian deposits in the Pripvatsky Depression. He found a uniformity in distribution of uranium and radium and a correlation between the increase


in dissolved solids of the waters and the increase in their radium content. He concluded that the radium concentration may be used as an indirect indicator of oil.

Gutsalo (1967) studied the geochemical relationship between radium anomalies and oil and gas deposits. In waters of the Dnepr-Donets Basin associated with hydrocarbons, the amount of Ra concentration depends on the concentration of dissolved solids and the age of the water-bearing rocks. Positive hydrogeochemical anomalies exist within the areas of hydrocarbon influence. The Ra anomalies are related t o the gas component of waters; Ra concentration is dependent on the partial pressure of hydrocarbons dissolved in water, which usually amounts t o more than 90% of the total gas pressure. The Ra concentration in these waters has a direct linear relationship to the hydrocarbon pressure. The Ra anomalies in the ground waters of the Dnepr-Donets Basin, near the gas-water or oil-water contacts, appear to owe their origin to the hydrocarbon gases, which are genetically related t o the hydrocarbon deposits.

The formation of radioactive anomalies on the earth's surface, above oil and gas deposits, is related to the migration of hydrocarbons, salts, and ions in water solutions. It is assumed that the radioactive substance is carried toward the surface by ascending waters and hydrocarbons. The migration of the water and hydrocarbons is controlled by the permeability of the rock strata. The infiltration of gaseous hydrocarbons into the surface zone may increase evaporation, which leads to the increased migration of the water from surrounding areas. This water may be capable of dissolving radioelements, redepositing them in these places of greatest evaporation, which leads to the increased migration of water from surrounding areas. Liquid hydrocarbons, because of fractionation, may deposit bituminous material which is able to extract radioactive material from ground waters. There are two schools of thought on the matter of formation of surface radioactive anomalies. They are: (1) the radioelements have a surface origin; and (2) the radioelements have a deep-seated origin (Sikka, 1963).

The deep-seated origin is substantiated by MacElvain (1963). In fact, he concluded that the determination of *l0Pb and 206 Pb in near-surface samples should be more rewarding in oil exploration than the beta radiation techniques. Furthermore, the 210Pb/206Pb ratio might indicate the age of the underlying hydrocarbon accumulation.

The amount of gases in surface soils is a function of the weather and is influenced by temperature, rain, and wind. Therefore, geochemical exploration techniques using soil samples must be designed so that samples are taken from a depth that is not influenced by the weather (MacElvain, 1963).

Filonov (1964) studied the radium and uranium contents in different oilfield waters occurring in the platformal and geosynclinal deposits, in particular, the variations of the Ra/U ratio. The results revealed: (1) that oilfield waters contained an increased Ra content and that chloride-calcium types had a higher Ra concentration than the bicarbonate-sodium waters; (2)

HYDROGEOCHEMICAL RESEARCH A N D METHODS 319

that the water enrichment in Ra occurred .because of leaching from the reservoir rocks and because of the radioactive decomposition of uranium; (3) that uranium was either absent or present in insignificant amounts in the bicarbonate-sodium waters, where it occurred in the form of a complex anion [(UOzC03)3]*; (4) that the Ra/U ratio in the waters a t the oil- water contacts was shifted in the direction of increasing Ra content; and (5) that the organic matter in oil had a definite effect on the shift of the Ra/U ratio because it removed uranium from the salt components dissolved in water, and supplied additional quantities of Ra because of the radioactive decomposition of uranium in oil.

A linear relationship between .the radium concentration and dissolved solids concentration of some water from Paleozoic and Mesozoic age strata was found (Gutsalo, 1964). Waters in contact with hydrocarbon accumulations were more highly concentrated with radium.

Vilonov (1962) investigated water-oil contact zones in several of the Soviet producing regions and found that a definite regularity in the distribution of radioactive elements exist. It was found that, in formation waters of oil accumulations, there is no definite relationship between the radium and the uranium content, and that usually uranium and thorium are present only in small quantities. The influence of oil occurrence on the distribution of radioactive elements in the formation waters of the oil accumulations appears most clearly in the zone of the water-oil contact; radium and its isotopes are concentrated in the water of this zone, and there is a relative decrease of uranium content, sometimes to zero.

Gutsalo (1969) concluded’ the following:. (1) enrichment of chloride- calcium brines with helium results from migration through rocks and is directly proportional to the amount of radium in solution - radium leached from the rocks by the underground water determines the amount of helium lost from the rocks; (2) a positive helium anomaly is formed in underground water around oil and gas accumulations; (3) the helium anomaly coincides with a positive radium anomaly; (4) the absolute value of the helium concentration at any point in the anomaly zone is dependent upon the radium concentration at the point and the time of formation of the accumulation; and ( 5 ) for any deposit of oil or gas, the areal extent of the positive helium anomaly in the formation water is dependent upon the value of the ratio of the partial pressure of the hydrocarbons to the total gas pressure.

Physical properties

Vdovykin (1963) determined the Eh and pH of formation waters and waters from rivers, lakes, and seas. Fig. 10.5 illustrates the results that he obtained. Unfiltered formation waters from petroleum producing wells had a lower Eh and a higher pH than waters taken from rivers, lakes, and seas. Filtration of the formation waters prior to analysis fof Eh and pH caused higher Eh and pH readings.


600

S O 0

4 0 0

> f 300

200

0

100

I I I I I I I I

-

-

- 0 I I

---- 1------- I I Q-

I I I I I 7 8 9 10 6 I1

- (3 PH

Fig.lO.5. Approximate pH and Eh of waters from unfiltered petroleum producing wells (A); filtered petroleum producing wells ( B ) ; and surface rivers, lakes, and seas (C). (After Vdovykin, 1963.

Fluid mechanics

Roach (1965) describes how to apply fluid mechanics t o petroleum exploration. The definition of fluid mechanics as he used it encompasses complete study of subsurface fluids including physical and chemical characteristics, whether hydrodynamic or hydrostatic, and a complete study of the characteristics of the reservoir rock.

Maps

Chloride-ion concentrations in water produced from rocks of various ages and depths were mapped in Lea County, New Mexico, using machine map- plotting techniques and trend analyses. Anomalously low chloride concentrations (1,000-3,000 mg/l) were found along the western margin of the Central Basin Platform in the San Andres and Capitan Limestone formations of Permian age. These low chloride-ion concentrations may be caused by preferential circulation of ground water through the more porous and permeable rocks (Hiss et al., 1969).

Hanshaw and Hill (1969) studied aquifer systems from: (1) Mississippian age rocks; (2) Pinkerton Trail Limestone; (3) Paradox member of the Her-


mosa formLtion; (4) Honaker Trail formation; and (5) Permian age rocks. Recharge in the Paradox Basin occurs on the west flank of the San Juan Mountains and along the west side of the Uncompahgre Uplift. A series of potentiometric surface maps were prepared for the five systems studied. With a few exceptions, most wells in formations above the Pennsylvanian age strata contain fresh to moderately saline water. Much of the strata below the Permian age rocks contained waters with dissolved solids concentrations greater than 35,000 mg/l and some areas favorable for hydrocarbon accumulations. Some of the brines in the Paradox formation contained up to 400,000 mg/l of dissolved solids. Cambrian age strata in much of Colorado is favorable for the accumulation of hydrocarbons.

Chemical analyses of water from five Cretaceous aquifers were used to compute ion ratios, which were used in conjunction with structural and stratigraphic information to interpret hydrologic conditions in the East Texas Basin. Ion ratio comparisons made by maps and diagrams show that the aquifers contain water of distinctive character, and that there are inter- connections between aquifers, especially near the Mexia-Talco Fault zone and the Sabine Uplift. A hypothesis is offered that water moves along an unconformity from the Sabine Uplift eastward toward the East Texas oilfield where it enters the Woodbine Sandstone. Ion-ratio maps show the effect of time and of rock composition upon the relative kind and amount of dissolved solids in the water because- of reactions with minerals and organic material in the rocks. The hydrodynamic component of the water in the Woodbine formation from east to west helped form and contain the giant East Texas oilfield (Parker, 1969).

Karim et al. (1966) studied three exploratory wells drilled on the east plunge of the Cordillera Isabella, Nicaragua, and all three had gas shows. A stratigraphic cross section and a localized map showing the relationship of magnetic highs obtained from an aeromagnetic survey and results of fluoroanalysis and water-gas surveys are included. The prospect of finding petroleum in coastal northeastern Nicaragua appears fair.

Water analysis integrated with the existing knowledge of the geologic framework of an area provides supplementary information t o assist the exploration geologist in solving geologic problems on both a local and a regional scale. Isoconcentration maps showing regional variations in the total solids content of the waters within a given stratigraphic unit are important. Inorganic water analyses data are useful in the correlation of porous zones, and benzene analysis is a promising hydrocarbon exploration tool (Noad, 1966).

Maps were prepared delineating: (1) surface outcrop areas of Upper Cretaceous rocks; (2) axial lines of Upper Cretaceous anticlinal structures; (3) zones of water types; (4) zones of water groups; and (5) zones of mixed waters. A diagram of chemical composition of the waters was also prepared. Using these maps, Galin and Plyushchenko (1963) selected areas in Dagestan that are favorable for the accumulation of oil and gas.


Reviews

Gerard and Feug&re (1969) concluded that geochemical exploration techniques are useful in offshore areas. Kroepelin (1967) reviewed geochemical prospecting as applied to petroleum and found that several companies had success ratios up to 59% with it in exploration. Johnson (1970) states that success ratios of about 35% can be attributed to the use of an inorganic technique of prospecting for oil and gas. The method is useful in locating stratigraphic trap accumulations and is based on the postulate that heavy-metal salts concentrate in the soil profile as a result of vertical migration of waters above an accumulation of oil.

According to Boyle and Garrett (1970), “geochemical prospecting will play an ever increasing role in the discovery of hidden ore deposits and accumulations of hydrocarbons. The methods need no longer be sold since it has now been generally recognized that they are the only direct approach to the problems of mineral, oil, and natural gas exploration. The methods are direct and have generally proved most successful when applied in conjunction with geological and geophysical exploration techniques.” Geochemical methods applied to petroleum prospecting have not reached their potential, expecially in the United States.

Karaskiewicz (1966) discussed the geomicrobiological and hydrochemical research done by the Polish Petroleum Institute in 1962-63 in the Lubel- Nadbuzan region. Specific methods such as the determination of gas dissolved in water were applied in this area, and 215 water samples were studied from the 9,500-km2 area. Anomalies produced by the bacterial activities which oxidize methane, propane, and butane were determined. Where methane was present, the bacterial microflora activity was lowest; where the biological activity was high, methane was absent.

Important aspects of geochemical prospecting are : (1) analytical methods; (2) transport mechanisms of the hydrocarbons; (3) anomalies associated with hydrocarbon accumulations; (4) statistical treatment of the data; and (5) the final result. Significant findings are mapped and interpreted to locate a target area for drilling (Kroepelin, 1967).

Case study of the Delaware sand (Bell Canyon formation), Texas, by Visher (1961)

Preliminary work was carried out on the relation of sapropelic material found in both dark shales and laminated silts, and the oil occurring in reservoir rocks. The study indicated that the frequency distribution of the radicals, - benzene, straight chain, CH3, and CH2 -, was identical in both the black shales and the residual crude present in oil saturated reservoir rocks. The entire sequence of Permian rocks from the Bone Springs Lime- stone through the Lamar Limestone member of the Bell Canyon formation is composed of dark organic sediments, deposited in a reducing environment.

CASE STUDY OF THE DELAWARE SAND 3 23

The total quantity of the sapropelic material available for the formation of oil was not determined, but 1% would be a conservative estimate, indicating that source material in the Delaware Basin is of sufficient quantity t o produce volumes of oil greater than presently discovered. The oilfields which have been discovered in the basin primarily are confined to the upper porous and permeable sands of the Bell Canyon formation. The present distribution of oil appears to be controlled by hydrodynamic conditions. Therefore, the tracing of the times and paths of migration is dependent upon reconstructing the paleohydrodynamics.

Potentiometric surface of the upper Delaware sand

A potentiometric surface map of the Bell Canyon formation was made from a two-dimensional electric analog model of the central and eastern portions of the Delaware Basin in West Texas (Fig. 10.6). The majority of pressures were bottom-hole measurements from existing fields. Only a few shut-in pressures from drill-stem tests were usable because of the short shut- in time commonly used in this area, and consequently, few tests reached true formation pressures. A pressure buildup method should have been used.

The total dissolved solids of the formation water range from a low of 90,000 mg/l in the Ford field to over 250,000 mg/l at the South Pyote field. All pressure readings were corrected for effects of varying total dissolved solids. The assumption was made that the concentrations of total dissolved solids are stratified with little mixing. Therefore, the weighted mean is between 50,000 and 120,000 mg/l.

The potentiometric surface has a hydrodynamic gradient from west to east with a component of northward flow. In the southeastern portion of the mapped area, the hydrodynamic gradient is reversed because of the influence of the eastern flank of the basin.

Stratigraphic traps are formed in areas where linear sand fingers show an updip decrease in permeability and porosity. The change in permeability and porosity between the permeability barrier and adjacent reservoir rocks, however, is not great. The Saber field, for example, has an average porosity of 25% and permeability of 70 md, and the barrier rock an average porosity of 12% and permeability of 3 md. Since in some areas this barrier rock would be considered a possible reservoir, something in addition to these changes in porosity and permeability is necessary to prevent the movement of oil into the barriers.

Under equilibrium conditions water flowing through a formation will have a greater pressure gradient across a tight zone than a more permeable zone (see Fig.lO.7). Therefore, the differential pressure in the barrier is greater than in the reservoir, and varies directly with the decrease in permeability between the two. When the oil phase reaches the barrier zone, the pressure gradient increases updip, making i t increasingly more difficult for the oil to

32

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N FO

R PE

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CASE STUDY OF THE DELAWARE SAND 325

246 k g A q cm

Fig.10.7. Relationships of hydrodynamic gradients to permeability; I = decreased hydrodynamic gradient because of increased permeability; 2 = increased hydrodynamic gradient because of decreased permeability; 3= average hydrodynamic gradient; 4 = decreased hydrodynamic gradient.

invade the water-filled rock pores. Finally, the entry pressure of the barrier rock is greater than the invading force of the oil and migration ceases.

The downdip hydrodynamic flow increases the efficiency of the trap by reducing the buoyancy effect of the oil. The hydrodynamic enforcement of stratigraphic traps can increase the oil column many times over what it would be under hydrostatic conditions and probably accounts for the development of commercial stratigraphic oil accumulations in the Delaware Basin.

Formation waters

The initial approach in the study of stratigraphic problems within the Bell Canyon formation was by the use of formation waters. Over 300 samples of formation water were collected, analyzed, and processed by computer techniques. Data collected in this manner were posted on maps (Fig.10.8-10) and contoured. Several aspects of the waters (relative concentration percentages of SO4, Mg, Ca, and total solids) show systematic variations over the basin. Variation in these parameters is related t o proximity to outcrop and the degree of transmissibility of the formation. The highest sulfate content is near the outcrop belt to the west; the calcium and total dissolved solids concentrations increase toward more impermeable rocks and areas of low circulation. In the center of the basin, the waters are characterized by very high total dissolved solids, high calcium, and low sulfate content, but in the porous and permeable fingers near the outcrop, salinites are low and sulfate is high. All gradations between these two extremes exist in the Bell Canyon formation. In areas where the sand fingers pinch out very rapidly into low- permeability sediments, the transition between these two extremes of water composition may take place in a matter of a few well locations. An excellent

3 26 EXPLORATION FOR PETROLEUM AND GAS

example of this is the Saber field (Fig.10.8-10) where a range of waters is evidenced in one homogeneous, continuous sand body.

The reason for these rapid changes in formation water compositions may be explained by permeability changes within the Bell Canyon formation. In areas of low permeability there is less circulation, less dilution, and more chance for the maintenance of an equilibrium relation between formation water and sediment. This was substantiated by the distribution of magnesium in the waters.

A series of multiple regression analyses was made on the relation of various dissolved ions in the waters to their total dissolved solids. First, all the waters were analyzed as a unit to determine the correlation coefficients and the degree of variability explained by the chosen ions. The second stage was the breakdown of the waters into three arbitrarily defined groups (based principally on salinities) to see if there were any noticeable changes in either correlation coefficients or degree of explained variance. The only significant change was in the relation of magnesium t o total solids. In those waters containing relatively low concentrations of total dissolved solids, there was a significant positive correlation, but in those with high concentrations of total dissolved solids, there was a significant negative correlation. This indicates that the relative concentration of magnesium decreases in waters of high total dissolved solids. These waters are precisely those that are found in low-permeability, fine-grained, argillaceous rocks in which magnesium would most likely be taken out of waters by diagenetic alteration of clay minerals.

The variations found in the formation waters within the Bell Canyon formation can be used as the basis of an exploration technique. Since the composition of formation waters is related t o permeability, and permeability is related to producibility of reservoir rocks, a workable relation exists between exploration objectives and water compositions. The refining of the maps of the distribution of the composition of the waters aids in defining the distribution of the sand fingers. The updip edges of the permeable sqnd fingers show increased concentrations of total dissolved solids and decreased magnesium which are related to the presence of a “barrier” (or trap) updip from the reservoir sands.

Formation water maps

Maps of the total dissolved solids content (Fig. 10.8), the chloride content (Fig. 10.9), and the calcium content (Fig. 10.10) of formation waters were prepared. The inference which may be drawn from these maps is the empirical association of oilfield occurrence versus the iso-mg/l contours of the various constituents. This empiricism shows some remarkable alignments and permits formation-water composition maps to be added to the suite of exploration tools. Some of the subtleties of constituent composition versus rock properties do not lend themselves readily t o mapping techniques but are useful for consideration (i.e., magnesium content versus low permeability

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33 0 EXPLORATION FOR PETROLEUM AND GAS

and fine-grained rocks, sulphate concentration variation with relationship to outcrop, etc.).

It is important to note on each of the constituent maps that the local variations of the iso-mg/l contours are of greatest importance and not the precise value of the contour. For example, on the total dissolved solids map (Fig. 10.8) the concentration in the Ford field is only 50,000 mg/l and ranges in a re-entrant to about 150,000 mg/l, while in the Wheat field, the range is from 150,000 mg/l to nearly 250,000 mg/l.

The overall appearance of this map (Fig. 10.8) is a series of fingering expressions. The various oilfields seem to have an occurrence relationship in the transition zone from higher to lower concentration. The Mason, Tunstill, Olds, and Saber fields occur along a transition zone from 250,000 mg/l to 50,000 mg/l. The El Mar and Grice fields are on a transition zone from 250,000 mg/l to 150,000 mg/l. The Two Freds field has a transition zone from 250,000 mg/l to about 150,000 mg/l. The Wheat and also the Ford fields occur in a similar transition zone. This relationship of oil occurrence and differential concentration is of great significance. Even in this limited area it appears that in the block from longitude 103”30’00” to 103”45‘00‘’ and from latitude 30’45’00” to 32’00‘00” there are several places which, from this empirical relationship, have some potentialities. The block immediately south of this, trending southwesterly from the Wheat and also from the Two Freds fields, needs additional study for better delineation. The area east of the Two Freds field lacks adequate control but basically shows the possibility of favorable development.

The chloride map (Fig.10.9) has a configuration similar to the total solids map. Again it is not the precise iso-mg/l contour which is of prime concern but the variation in the limited area. This rate of change from higher to lower concentration appears to be a principal key to occurrence.

The calcium content map (Fig. 10.10) does not show the prominent fingering, almost pseudodeltaic, effect that the total solids and chloride maps have. Perhaps this is because of the smaller range of values mapped. Some of the high to lower concentration effect is present and in other areas, the Wheat and Two Freds fields, the iso-mg/l closure is developed. This map is less diagnostic than the others; however, considered in conjunction with the other two maps, the coexistence of accumulation and the transition zone, even closure cannot be missed.

Formation water maps of other areas

Fig. 10.11 is a potentiometric surface map of the Arbuckle formation group in parts of Kansas, Missouri, and Oklahoma drawn by Chenoweth (1964). As ,noted on the figure, the arrows indicate the theoretical direction of the water flow which was inferred from the tilted oil-water interfaces. Detailed pressure data along with reservoir transmissibility data could be used to construct a similar map for determining detailed flow pattern.

FORMATION WATER MAPS 331

/

Kilometers 0 55.60 M I:l,wom

LEGEND

drrpru indicate ItmoretlcoI dimction of artasion flow. Infarred tmm tilted oil w01.r i"l,,t.aCe. in B"ter,Ellswrth, ord Pownee Counties. Kansas.

Arbuckle bnt ."ReWon amd'or Gmnite Wash beneath hnnaylvonion. Ellia.Rush and Barton Countlea. Kanroa .

Fig.lO.11. Potentiometric surface map of the Arbuckle formation group in South Kansas, North Oklahoma, and southeast Missouri.

The map shown in Fig.10.12 also was constructed by Chenoweth (1964) and it is a chloride map of the Arbuckle formation group in Kansas and Oklahoma. Note the dilute brines near the outcrop areas, which are diluted by meteoric recharge waters entering the outcrop. As a general rule the trapped petroleum in this group of formations is found associated with the more saline brines, and in the transition areas.

Fig. 10.13 is a map that illustrates the variation in salinity at the bottom of the lower Wilcox formation in portions of Texas, Louisiana, Arkansas, Mississippi, and Alabama. The most saline brines occur in the deeper basin areas with the dilute brines nearer outcrop areas. Fig. 10.14 is a similar map which illustrates the salinity variations in the top of the lower Wilcox formation in the same area. Fig. 10.15 illustrates the salinity variations at the base


Fig.10.12. Map of the chloride concentrations (mg/l) in the Arbuckle formation waters in Kansas and Oklahoma

of the upper Wilcox formation, while Fig. 10.16 illustrates the salinity variations at the top of the upper Wilcox formation. Fig. 10.17 is a salinity map of the lower Tuscaloosa and Woodbine formations, again most of the trapped petroleum is found in areas where the more saline waters occur and in transition areas.

Salinity maps are useful as a primary tool in petroleum exploration because they provide information concerning sand fingering, diagenetic changes that affect reservoir and source rocks, and stratigraphic traps. Occurrences of petroleum accumulations often correlate with salinity transition zones, i.e., where the salinity ranges from 50,000 mg/l to 100,000 mg/l.

I I

EEL‘ SdVN IZIBLVM NOILVNIZIOd


Fig.10.15. Salinity concentrations in waters taken from the base of the Upper Wilcox formation in portions of Texas, Louisiana, Arkansas, and Mississippi.

Less than 5,600

Fig.lO.16. Salinity concentrations in waters taken from the top of the Upper Wilcox formation in portions of Texas, Louisiana, Arkansas, Mississippi, and Florida.

CONCLUDING REMARKS 335

LEGEND

II Greater than im,ooo mg/l (as NOCI) 5.600 lo 70.000 mp/l

Less than 5.600 mg/I

Fig.lO.17. Salinity concentrations in waters taken from the Woodbine (Dexter) and Lower Tuscaloosa formations in .portions of Texas, Oklahoma, Arkansas, Louisiana, Mississippi, Georgia, South Carolina, North Carolina, and Florida.

Concluding remarks

Organic acid salts, petroleum hydrocarbons, and other organic compounds are soluble in water. The ionic composition, the pH, and the Eh of the water influence the solubilities of the organic compounds. The aqueous solubility of petroleum hydrocarbons increases with increasing temperature and pressure, and decreases with increasing water salinity. The aqueous solubility of organic acid salts increases with increasing pH.

A mechanism for the migration of petroleum or petroleum precursors, therefore, is water. It is known that petroleum hydrocarbons are generated from organic-rich rocks. The organic material in the petroleum source rocks is transformed by physicochemical reactions into petroleum precursors and/or hydrocarbons which are solubilized by water. The water phase moves the solubilized organics from the source to the reservoir where, because of temperature, pressure, salinity, pH, filtration, or organic salting-out phenomena, the organic phase separates from the water.

In the reservoir the petroleum precursors and/or hydkocarbons mature to crude oil and gas, primarily because of temperature and time. Thermal alter-


ation proceeds both in the fine-grained source rock and in the reservoir at temperatures above 115OC by abiogenic reactions. With increasing temperature the quality of the crude oil improves; however, at higher temperatures the crude oil is destroyed, leaving methane and pyrobitumen.

The primary mechanism in the migration of petroleum involves water, therefore, it follows that knowledge of certain characteristics of the water is useful in exploration for oil and gas. The chapters “Classification of oilfield waters,” and “Some effects of water upon the generation migration, accumulation, and alteration of Petroleum” discuss some of these characteristics. Fig. 10.18 illustrates some characteristics related to waters that are likely to indicate an oil or gas accumulation, and some characteristics related to waters that are likely to indicate a dry reservoir.

2 - C a type water /-

(a)

Fig.lO.18. Genetic indicators in a water associated with an oil and gas accumulation (a) compared to indicators in a water associated with a dry reservoir (b).

REFERENCES 337

References

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Anonymous, 1960b. 10.9% of U.S. wildcats produce in 1959. World Oil, 1 5 0 : l l l . Baker, D.R. 1962. Organic geochemistry of Cherokee group in southeastern Kansas and

Baker, E.G., 1960. A hypothesis concerning the accumulation of sediment hydrocarbons

Baker, E.G., 1962. Distribution of hydrocarbons in petroleum. Bull. A m . Assoc. Pet.

Billings, G.K., 1969. Geochemical petroleum exploration method, U.S. Patent,

Bond, D.C., 1962. Geochemical process. U.S. Patent, No.3,033,287. Boyle, R.W. and Garrett, R.G., 1970. Geochemical prospecting - a review of its status

Bronston, A., 1947. Geochemical data forecast major field. World Oil, 127:112-116. Buckley, S.E., Hocutt, C.R. and Taggart, M.S., 1958. Distribution of dissolved hydrocar-

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Chenoweth, P.A., 1964. Potentiometric Surface Map and Salinity Map o f the Arbuckle Formation Group in South Kansas, North Oklahoma and Southeast Missouri. Sinclair Oil Company, unpublished.

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Galin, V.L. and Plyushchenko, V.G., 1963. Hydrogeology of the Upper Cretaceous deposits of Dagestan as related to their oil- and gas-bearing properties. Zzu. Vyssh. Uchebn. Zaued. Geol. Razued., 4:120-217 (in Russian).

Gehman, Jr., H.M., 1962. Organic matter in limestones. Geochim. Cosmochim. Acta, 26 :885-899.

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Kravchinskii, Z.Ya. 1960. Comparison of chemical characteristics of waters in productive red-colored formations. Geol. Neft iGpza, 12:42-44 (in Russian)..

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Chapter 11. GEOPRESSURED RESERVOIRS

The composition of the waters in normally pressured reservoirs often differs from the composition of the waters in geopressured or abnormally high-pressured reservoirs. There are several theories concerning the cause of the geopressured zones; many papers have been written about their occurrence and causes (Burst, 1969; Dickey et al., 1968, 1972; Fowler, 1970; Harkins and Baugher, 1969; Hottmann and Johnson, 1965; Jones, 1969; Powers, 1967; Schmidt, 1973; Wallace, 1969). Knowledge of how to locate geopressured zones is important in drilling operations, because if such a zone is drilled into without adequate preparation, the well may blow out, perhaps causing a fire, loss of the well, loss of the drilling rig, or even loss of life. The usual precaution, if the driller knows of a high-pressure zone, is to increase the weight of the drilling mud; however, the continual use of heavyweight mud is much more expensive than drilling with a lighter weight mud. Drilling rig time is worth about $2,000 per day, and it costs about $44,000 per kilometer to drill a well on land. A drilling barge in the bay can cost from $4,000 to $lO,O.OO per day while a drilling ship plus a full crew costs about $25,000 per day. Considering.the foregoing costs plus the cost for a special crew to extinguish a fire at an ignited blowing well can be very expensive because the initial fee for the fire extinguishing personnel is about $25,000. Steps, therefore, are taken by the drilling company to assure that an adequate drilling rig is used, that the optimum size borehole is drilled, that the correct weight drilling mud is pumped down, that strong enough casing is inserted into the well, and that blow-out preventers are operative.

Geopressure

Dickinson (1953) defined abnormally high pressure (geopressure) as any pressure exceeding the hydrostatic head of a column of water (extending from the subsurface tapped stratum to the land surface) containing 80,000 mg/l of dissolved solids. Formations with equal or less pressures are considered normal or subnormal. In the Gulf Coast area the normal pressure gradient is about 0.107 kg m-l, or about equal to 0.21 g cm-3 of drilling mud (Harkins and Baugher, 1969). Normal pressure in the Rocky Mountain region has a gradient of 0.100 kg m-', although excep tions occur in western Montana, the Denver Basin, the Powder River Basin, and the San Juan Basin, mostly in Cretaceous rocks (Finch, 1969). (A gradient of 0.118 kg m-l is normal in the Williston Basin in North

344 GEOPRESSURED RESERVOIRS

Dakota.) Normal pressure is that which is normal for the particular area involved and is related to the salinity of the reservoir water, rock types, and geologic setting, but in general, it is that pressure exerted by a column of water from the surface to the observed subsurface formation, which is equal to and will balance the subsurface formation pressure. Abnormally high pressures are those which exceed this normal hydrostatic head.

Geostatic ratio

Abnormal pressures can be expressed in terms of a “geostatic ratio,” which is the ratio of the observed fluid pressure in a subsurface formation to the overburden pressure of the overlying sediments. This load at a given depth is approximately 0.231 kg down to depths of more than 6,100 m, because the density of rocks changes slowly with depth (Penne- baker, 1968). Any abnormal pressure will therefore have a geostatic ratio between 0.0327 and 0.0703 kg in the Gulf Coast area and between 0.0304 and 0.0703 kg

- m

in the Rocky Mountain area.

Compaction model

The compaction concept was demonstrated using a model consisting of perforated metal plate separated by metal springs in water and enclosed in a cylindrical tube (Terzaghi and Peck, 1948). The springs were used to simulate communication between deposited particles and with the initial pressure upon the upper plate, the springs d o not move because all of the pressure is supported by the water, assuming that water does not escape from the system. Relating the fluid pressure (FP) t o the total pressure (TP) one can derive an equation X=FP/TP to record various formation pressures (X) t o determine the geostatic ratio using the model.

Origin of abnormal pressures

Abnormally high pressures in a formation can be caused by compaction. Factors which may cause them are, according to Hottmann and Johnson (1965), “the ratio of shale to sand thickness, the mean formation permeability, the elapsed time since deposition, the rate of deposition, and the amount of overburden.” These parameters are interrelated in compaction, which is the controlling factor in fluid pressures within subsurface sedimentary environments (Harkins and Baugher, 1969). Dickinson (1953) reports that the fluid pressures within sediments are predominately controlled by two factors; namely: (1) the compression as a result of compaction; and (2) the resistance to expulsion of water.

Compaction begins with sedimentation and deposition of soft muds composed of up to 90% water (Wallace, 1969). In an environment where deposition continues, gradual compaction occurs whereby the muds become clay

ORIGIN OF ABNORMAL PRESSURES 345

minerals and shales. The shales are primarily clay minerals with flat or tabular grain shapes; with additional overburden, the pressure packs the grains closer together, with a resultant expulsion of water from the inter- vening spaces. In the early stages of compaction, the shale possesses high porosity and permeability, and the expelled water always flows to areas of least resistance and pressure (often porous sand). As the overburden increases, the porosity and permeability of the shale decrease until equilibrium is approached and the pressure in all directions is equal. A t this point, expulsion of additional water is limited. Tectonics, of course, could alter the subsurface environment.

Deposition and sedimentation of sand are somewhat different because the sand grains are in contact in the first stage and sand compaction is about complete with deposition. However, reduction of porosity can occur by: (1) solution of the sand grains at contact points; and (2) rearrangement of the grains because of very high pressures.

Clay beds separating aquifers are often referred to as semipermeable membranes. Such beds can separate aquifers containing waters of different salinities, causing a hydrostatic head in the direction of the more saline water.

Fig. 11.1. Sand dikes in the Simpson Sand formed by the actiqn of highly pressured subsurface waters forcing the lighter colored sand intrusively into the primary sandstone. The primary sand was formed from white beach sands during Ordovician time.


Osmotic pressure can develop, which is dependent upon osmotic efficiency of the clay bed and the differences in salinities of the two aquifers (Young and Low, 1965). According to Jones (1969), stepwise increments of osmotic pressure may develop wiih depth through a series of bedded sands and clays acting as a multistage pump, thus producing the high reservoir pressures in the northern Gulf of Mexico basin.

Fertl and Timko (1972) discuss 17 possible causes of abnormally high pressures. They are rate of sedimentation, tectonic activities, potentiometric surface levels, reservoir structures, areal salt deposition, shallow-reservoir repressuring, paleopressures, mud volcanoes, secondary precipitation of cementation constituents, diagenesis of volcanic ash, rehydration of anhydrite, diagenesis of clays, osmosis, permafrost, earthquakes, chemical, thermal chemical, and biochemical effects, and tidal disturbances.

Fig. 11.1 illustrates one type of action that results from high pressures, where sand dikes formed by the action of highly pressured subsurface waters forcing the lighter colored sand intrusively into the primary sandstone. The primary sandstone was formed from white beach sands during Ordovician time.

Abnormal pressures in the Gulf Coast area

In the Gulf Coast area, the abnormal pressure seems to be related to rapid deposition of sediments and low regional transmissibility. Fluid pressures are near hydrostatic where there is continuity with normally pressured aquifers and where the sands are sufficiently permeable to dissipate the expelled water from the compacting fine-grained rock.

In some of the deep oil and gas wells of the Gulf Coast, the pressure of the interstitial fluids (oil, gas, or water) in kilograms per square centimeter is normally the depth in meters multiplied by 0.107. This is slightly more than the pressure required to sustain a column of water to the surface. At great depths where the geological section is mostly shale, fluids at abnormally high pressures are found. Sometimes the pressures are very high, approaching 0.2 kg cme2 m-l. Often the increase in fluid pressure is abrupt, taking place in a vertical interval of 30 m or less. In other areas, the increase in pressure is more gradual, extending over 300 m of vertical section. The depth at which the pressure starts to increase ranges over a wide interval. Abnormal pressures are found at depths as shallow as 1,000 m in some offshore fields, and wells in some areas have been drilled deeper than 7,000 m without encoun- tering abnormal pressures.

Forty-one formation water samples from gasfields in southwestern Louisiana were obtained and analyzed to determine the relationships of the chemical composition of the waters to normal and abnormally pressured geologic zones (Dickey et al., 1972). The concentration of dissolved solids in the waters from the overpressured zones is generally less than in the normal pressure zones, and this knowledge is significant in electric log interpretation.

ABNORMAL PRESSURES IN THE GULF COAST AREA 347

Fig. 11.2. Slash lines showing the general area in Louisiana where the samples were obtained.

Previous work in the area suggested that the abnormally fresh waters were found in the same part of the section as were the abnormally high pressures (Dickey et al., 1968). The general locations of the wells are shown in Fig. 11.2. They were from the South Lewisburg, Church Point, Branch, South BOSCO, North Duson, Duson, Ridge, and Andrew fields, all in Acadia, and Lafayette Parishes, Louisiana. The water samples were analyzed chemically by using the procedures published by the American Petroleum Institute (1968). The analytical data are summarized in Table 11.1.

A subsurface cross section, Fig. 11.3, was constructed in a general north- south direction showing the stratigraphy and structure across seven oilfields in the area of study (Fajardo, 1968). The initial pressures of the shallower reservoirs are normal. However, below 2,450 m many reservoirs contain fluids with abnormally high pressures. The 4.9-m amplified normal curve was used to recognize the first appearance of abnormal pressures in the shale section. The fluid pressure gradients were estimated following the method described by Hottmann and Johnson (1965). Shale resistivity and fluid pressure gradient versus depth were plotted for 50 wells in different fields of the study area, and of these, 22 are included in the cross section.

All of the 41 waters belong to the chloride-calcium class of Sulin (1946), and none has the composition of meteoric water. The principal cation is sodium, although the concentration of calcium is always high. In some of the more concentrated brines, the calcium concentration is nearly 40,000 mg/l and constitutes over half the reacting value of the sodium. Magnesium is variable in amount, and in two samples it is absent. Chloride is the predominant anion, amounting always to more than 49.5% of the total reacting values. Sulfate usually is absent and never is present in concentrations greater than 0.5% of the total reacting value.

In Fig. 11.3, the top of the section is 2,100 m below sea level. The electric logs indicate the lithology, which is quite sandy down to a depth of 2,700 m

TABLE 11 .I

Formation-waters sample locations, constituents found in the waters, shale resistivity (SR), and fluid pressure gradients (FPG)

Sample Location of Depth Zone Specific Concentration (mg/l) SR at FPG number of well (m) gravity spl. depth (kg cm-2

(S-Twp-R) (60°/600F) CI HCO3 SO, B Br 1 Na Ca Mg K Li Sr Ba NH4 organic 6’) acid as acetic

1 *I 2’1 3*’ 4’1 5*1 6 7 8 9

10 11 12 13 14 15 16 17** 18 19 20 21

23 24*’ 25” 26 27 28 29 30 31 32

22*’

33*’ 3483 35*3 36” 37 38

40 41*3

39*3

73-105-34E 4,66+4,664 Bolivina-mex 2l-lOS-03E 3,643-3,645 U. Camerina 2*lOSFo3E 3,625-3,627 L. Camerina 20-10S-aE 3.613-3,615 U. Camerina 17-10S43E 4,060-4,063 Bolivina-mex O8-lOS43E 3,047-3.049 Discorbis 25-07S43E 3,325-3,327 U. Tweedel 25-07603E 3.293-3.296 L. Tweedel

U. Nodosaria Daigle U. Nodosaria Tweedel Tweedel Struma Frio Nodosaria Klumpp D Frio Frio Frio Frio U. Texana U. Texana Frio Frio Frio Nodosaria Marg howei Homeseeker Nodosaria A Horn-eker D Klumpp E Brookshire Brookshire Brookshire Brookshire Nodosaria Homeseeker 2 Marg tex U. Moicene Marginulina

1.035 1.062 1.057 1.059 1.085 1.045 1.060 1.069 1.083 1.051 1.065 1.069 1.062 1.128 1.061 1.149 1.090 1.058 1.058 1.057 1.144 1.090 1.092 1.220 1.202 l . lS3 1.139 1.070 1.144 1.145

‘-4 1.088 1.055 1.089 1.089 1.082 1.089 1.140

-D 1.120 1.069 1.082 1.050

39,000 55,600 56,600 50,000 72.800 33,300 51,700 58,000 50,900 45,300 45,600 57,900 52,600

116,000 50,900

135,000 79,300 46,600 47,900 45,800

125,000 84.500 80,300

201,000 184,000 11 1,000 119,000

100,000 109,000 80,000 44,400 77,500 78,000 72,300 75,400

129,000 120,500

55,500 74,400 49,700

61,600

387 541 826 630 448 503 180 363 507 545 574 586 579 322 330

92 334 741 788 694 135 419 363

0 0

1 1 2 76

550 66 73

270 244 171 206 234 203 80

240 539 249 482

0 49 35 18 407 62 61 22 234 62 52 21 38 37 57 21

tr. 43 81 19 50 32 37 16 0 18 21 15

tr. 26 41 18 33 35 70 2 3

0 28 38 18 tr. 29 35 22 tr. 26 56 25

0 34 45 20 0 38 128 26

67 23 43 18 223 52 154 24

0 48 169 74 60 46 40 23 72 48 52 21

ND 44 47 22 0 47 64 23

122 40 20 22 tr. 45 62 20 352 75 213 18 tr. 67 204 19 ti . 42 94 24

0 52 117 28 0 67 1 4 5 0 42 201 21 0 39 71 21

77 34 110 34 130 36 70 30

0 18 81 21 0 18 82 19 0 33 58 18 0 18 162 19 0 41 174 24 0 43 134 38

102 52 40 26 0 26 79 18

88 43 60 35

17,800 1,070 78 32,300 2,210 369 34,200 1,380 213 29,500 1,380 194 41,100 3,850 583 19.200 1,390 224 34,800 2,730 544 34,400 2,020 194 27,500 3,050 719 26,000 2,310 167 24,900 2,950 447 33,300 2,660 389 31,700 1,570 0 49,600 21,600 2.180 29,600 1,890 408 66,800 15,200 1,270 46,400 2,950 447 24,700 2,660 1,010 26,600 2,180 303 ND ND ND 61,900 15,700 159 45,800 7,390 565 45,800 3,300 972 80,600 38,800 2,140 68,900 33,200 5,770 53,600 14,300 428 52,700 18,400 1,200 35,200 3.610 17 40,600 18,300 1,090 51,800 14,400 700 47,800 2,760 35 25,800 1,510 447 44,200 3,530 836 44,400 3,270 972 41,200 3,270 564 42,600 3,370 894 77,800 4.560 0 68,800 5,610 564 32,500 3,210 136 42,800 2,950 855 29,600 1,780 141

518 247 200 204 267

85 208 230 162 134 262

192 427 31 5 813 427 172 166 157 830 324 376 782 640 798 771 137

1,150 631 392 166 236 235 294 232

375 176 264 71

i n 1

ND

10 7 6 6 6 3 4 5 6 4 4 4 5 9 9 9

10 6 5 4

15 7 9

17 17 12 18

5 17 15 10 5 2 2 3 2

ND 5 5 2 2

ND ND 246 84 ND ND 295 48 ND ND 238 96 ND YD 650 72 ND ND 178 96 P:D ND 200 120 ND ND 538 24 ND ND 301 76 ND ND 362 24 ND ND 279 96 ND ND 210 72 ND ND 254 96 ND ND 364 120 ND ND 218 144 ND ND 230 48 ND ND 250 24

0 50 202 144 0 5 377 120 0 5 206 96 0 8 96 72 0 19 243 48

ND ND 110 96 0 33 142 144

ND ND 294 48

ND ND 295 48 ND ND 279 24 ND ND 180 168 N D l ND 222 72 ND ND 368 96

0 110 349 24 ND ND 195 12 140 97 219 96 128 109 214 624 265 41 258 144 171 102 306 48 ND ND 152 ND ND ND 295 96

0 7 179 192 195 85 167 432

0 4 160 312

N D ND 282 120

0.77 0.59 0.62 ND 0.38 1.1 ND ND 1.02 0.83 0.97 ND ND 0.90 ND ND 0.60 0.84 ND 1 .o 0.94 0.35 0.70 0.50 0.35 1.4 1 .o

1 .o ND ND 0.83 ND ND ND ND 0.95 0.92 0.65 ND 0.57

0.38

0.185 0.159 0.157 ND 0.195 0.107 ND ND 0.107 0.107 0.107 ND ND 0.107 ND ND 0.157 0.107 ND 0.107 0.107 0.191 0.131 0.191 0.203 0.107 0.107 0.193 0.107 ND ND 0.107 ND ND ND ND 0.107 0.107 0.152 ND 0.16X

*’ Abnormal pressure. *’ Abnormal pressure. but normal chemically. *3 Samples 33-36 are from the Abheville field or the south and of the area sampled and appear to be in a different chemical family, S-Twp-R = section-township-range; ND = not determined.


?6 KEY *33a34 X A b n z D r e s s u r e

Normal pressure

il 4.5

I I 1 I I I I 1 I 30 40 50 60 70 80 90 100 110 120 I

CHLORIDE, g / l D

Fig. 11.4. Plot of the depth of the wells versus concentrations of chloride in the formation waters.

-‘-I , 3p

33. 034

2.5 c / K E Y

X Abnormal pressure/ ?‘Normal presauro

0 0.5 BICARBONATE, p/l

Fig. 11.5. Plot of the depth of the wells versus concentrations of bicarbonate in the formation waters.


in the north to 3,050 m in the south. Below this depth, the sands become less abundant and less widespread.

The first abnormal pressure as calculated from shale resistivity is indicated by an arrow. The location of a producing horizon from which a water sample was taken is shown by the sample number in a circle. When the water sample was taken from a nearby well, not shown on the section, it was projected onto the section and shown as the sample number inside a square in Fig. 11.3.

There is a general tendency for the dissolved salt concentration of the water samples to increase with depth. This is shown in Fig. 11.4, which shows chloride plotted against depth. Since chloride is the predominant

K E Y )< Abnormal pressure 0 Normal pressure

I

27

\

25 K

X 24

I \

I 10

CALCIUM, g/l

Fig. 11.6. Plot of the depth of the wells versus concentrations of calcium in the formation waters.


100

a0

- 60- \ 0

anion, it serves as an indication of the degree of concentration. The samples of water from abnormally pressured sands are shown as circles in x'es. All of them except 17, 22, 24, and 25 fall below the average concentration line, that is, they are less concentrated than they should be for their depth of burial. Sample 1 especially is much too weak.

Bicarbonate, while occurring in much smaller quantities, shows the reverse relation, decreasing in amount with depth, as shown in Fig. 11.5. The waters from horizons with abnormal pressures have more bicarbonate than they should, considering their depth of burial.

Calcium increases with depth, as shown in Fig. 11.6. It would be more correct t o say that there are two types of water. Type 1 includes waters with less than 5,000 mg/l calcium, all of which are shallower than 3,800 m; type 2 is water with more than 5,000 mg/l calcium, most of which is deeper than 3,500 m. The only minor constituent that indicated a significant change with depth was potassium, and it appears to increase relative to sodium. The abnormally pressured waters seem deficient in potassium for their depth.

-

-

Normal pressure

x Abnormal pressu&e-Solution o Normal pressure- A l te red rel ict bittern

O\&o

0%

'0 0

\ 0 " \ " \

O \

\ "\

.\O

A 0

0

0

SODIUM, g/l 0

Fig. 11.7. Comparison of some brines of a bittern type from the Michigan Basin with some brines from some normal and abnormally pressured reservoirs in Louisiana.

36 0

I50

I 2 5

I00

- \

2 7 5 5 - 0 0 In

50

25

0

GEOPRESSURED RESERVOIRS

X

- x

Normal pressure

x Abnormal pressure

/ X

.

X*

Sodium’=mg/l Na + mg/l Ca 40

I I I I 0.05 010 0.15 0.20

BROMIDE, g/l

!5

Fig. 11.8. Plot of Na’ versus Br from some brines from normal and abnormal pressured reservoirs in Louisiana.

Four of the waters from high-pressure sands (17, 22, 24, 25) have normal concentrations of dissolved solids for their depth. The other waters from high-pressure sands (1-5, 13, 28, 39, 41) have lower concentrations than normal. They also have less calcium, more bicarbonate, and a higher Cl/K ratio.

About 80% of the material in the Gulf Coast shale is clay. Assuming that the waters have reacted with montmorillonite, there should be a direct relationship of calcium t o sodium. Plotting the calcium and sodium data in Table 11.1 plus some data for some brines from the Michigan Basin (as shown in Fig. 11.7) indicate that a relationship of calcium to sodium does exist in the Gulf Coast waters and that they probably have reacted with montmorillonite. Fig. 11.7 also indicates that the Gulf Coast waters are not an altered relict bittern as are the Michigan Basin brines.

In an ion exchange reaction with montmorillonite, 2 moles of sodium are exchanged for 1 mole of calcium, therefore, if salt is redissolved the bromide content in solution should be proportional to the original redissolved solu-

ABNORMAL PRESSURES IN THE GULF COAST AREA 36 1

25

tion. However, because of the exchange reaction the sodium in solution should be Na + 46/40 Ca or Na'. Fig. 11.8 is a plot of Na' versus Br for the 41 samples. The data scatter to some extent but this can be expected if biogenic derived bromide is present and the presence of iodide indicates that such is the case. Fig. 11.8 indicates that re-solution of salt is a control in these samples.

Fig. 11.9 shows further evidence that the Louisiana brines were formed by re-solution of salt. For example, the dashed line in the left portion of Fig. 11.9 is a plot of Na' versus Br of salt dissolved in distilled water, and the solid line just to the right is a replot of Na' versus Br for the Louisiana brines. The next dashed line to the right is Na' versus Br for evaporating sea water, and the curved dashed line is Na' versus Br for relict brines from the Michigan Basin.

Notable differences in the waters found in the normally and abnormally pressured rocks are evident (Schmidt, 1973). The dissolved solids in the

I \* I * \ I \* I \

\ t

I f * \

9 v a p o r o t i n g h seo water * \ \

I .3: Sodium I=mg/l sodium +% mg/l calcium m>

-Re-solution solt in pure water

Southwestern Louisiano brines

I 2 3 4 BROMIDE, g/l

Fig. 11.9. Replot of Na' versus Br of the Louisiana brines (Fig. 11.8); plus data for relict Michigan brines, evaporating sea water, and resolution of salt. Resolution of salt is an important control for the Louisiana brines


normally pressured sandstones range from 600 to 180,000 mg/l, while in the geopressured sandstones the range is from 16,000 to 26,000 mg/l. The dis- solvedsolids in the water in the pores of the shales adjacent to normally pressured sandstones are lower than the dissolved solids in the water in the sandstones, but the dissolved solids concentrations are similar in the waters of the adjacent high-pressure sandstones and shales. The concentration order in shale pore water is > HC03- > Cl-, and in normally pressured sandstone water it is C1- > HC03- > S04-2.

The temperature gradient in the geopressured zone is about O.8l0C/25 m, while in the normally pressured zone it is about 0.44OC/25 m. This change in temperature gradient is believed t o be related to the porosity, where a greater porosity causes a decreased thermal conductivity (Schmidt, 1973).

The clay mineral composition in the geopressured zone is predominantly a nonexpandable type, while in the normally pressured zone montmorillonite, an expandable type, frequently occurs. This change is believed to be related to the temperature, and the heat allows the release of water from the clays at temperatures of about 93-104OC. This released water will dilute the pore water and cause the dissolved solids to decrease.

The total amount of water released by Gulf Coast shales in geopressured zones is about 13% of the total in the system (Schmidt, 1973). This can be a cause of the lower salinity of the waters found in the geopressured zones.

Fowler (1970) studied the Chocolate Bayou field in Texas and evaluated the relationships between geopressure and the migration and accumulation of hydrocarbons. He concluded that faults tend to act as barriers separating fluid systems in the area; however, cross-formational flow occurs with geopressure causing shale ultrafiltration of the waters. The ultrafiltration produces salinity variations in the waters. Hydrocarbon accumulation in the area is controlled by the hydrodynamic flow.

According to Fowler (1970), hydrocarbons are trapped in the upper sands because of slight pressure differentials across fault traps in the West Choco- late Bayou field. However, in deeper strata, abnormal pressures have caused hydrodynamic flow and pressures greater than the displacement pressure in the fault, resulting in no trapped hydrocarbons.

In essence then, sands with pressure gradients greater than 0.20 kgcm-' m-' in the Chocolate Bayou field do not contain commercial amounts of hydrocarbons. It also appears that the size of the accumulation may decrease with increasing pressure gradients up to about 0.16 kg cm-* m-'. The accumulation size may increase with pressure gradients in the range of 0.16-0.19 kg cm-2 m-' and then decreases.

Detection of abnormal pressures

Estimation of formation pressures from electrical surveys is related to the following assumptions, concerning the origin of abnormal pressures (Foster and Whalen, 1966):

DETECTION OF ABNORMAL PRESSURES 363

(1) Shale porosity is a function of net overburden pressure and normally decreases with an increase in depth.

(2) Shales with abnormal pressure will have a higher porosity than normally pressured shales at the same depth, because of the greater amounts of interstitial fluids.

(3) Sand bodies (confined by lensing, faulting, etc.) surrounded by shale will have a pressure similar to those in the shales.

Data from acoustic and resistivity logs can be used to establish a shale transit time or shale resistivity versus depth of normal hydrostatically pressured formations. Deviation from the derived curve is used t o determine abnormal pressures (Hottmann and Johnson, 1965).

The acoustic log is a function of porosity and lithology; therefore, in any given shale sequence it is primarily a measure of porosity. The acoustic response in normally pressured shales decreases in travel time (velocity increases) with increasing depth. This is the “normal compacted trend”, and the pressures in the shale are normal, or hydrostatic. Deviation from the “normal compaction trend” indicates an abnormally pressured zone. Relating the difference in the travel time of the observed formation pressure ( A T , ) t o a normal formation pressure (AT,) to the formation pressure gradient (calculated from known depths and pressures of wells in the area), a pressure gradient (AT, -AT,) can be determined. The reservoir pressure can be found by multiplying this gradient by the depth.

Fertl and Timko (1970) discuss several methods, using the theory of “departure from the normal” to detect abnormally pressured zones. Methods they discuss are as follows:

(1) Bulk density -this is a measurement of the intensity of back-scattered electrons produced by gamma-ray bombardment; this intensity varies with the bulk density of the rocks surrounding the borehole.

(2) Conductivity measurements - measure of an induction log. Electro- motive forces set up a current, which is detected by a receiver and recorded. Overpressured shales are noted by greater-than-normal conductivity reading resulting from higher-than-normal water content and porosity.

(3) Borehole temperature - geopressured as usually associated with an increase in temperature. (4) Presence of gas in mud - this is not always a good detector, for gas

can evolve from formation cuttings, as they come to the surface. One of the best means of obtaining subsurface information, other than

drilling, is the use of the reflection seismograph. This geophysical tool is a measure of time between the earth’s surface and various subsurface reflecting horizons. The differences in interval velocities between these different horizons (formations) can be used to obtain a plot of average interval travel time, which varies exponentially with depth.

The degree of departure from a “normal” plot of this travel time versus depth is related to abnormally pressured reservoirs in the Gulf Coast area (Pennebaker, 1968). This departure is noted as an increase in the normally


decreasing travel time with depth, because of the undercompacted formations. To measure the formation pore pressure, plots of equal pore pressure gradients are compared, by an overlay, to the abnormally pressured interval travel time depth plots.

Forgotson (1969), by experience with wells in the Gulf of Mexico, noted that the presence of high background gas and high trip gas, together with lower than normal shale density, does not necessarily indicate the proximity of an abnormally pressured reservoir. He believes that a minimum of 200% increase in the shale penetration rate when drilling is the best available means to predict abnormal pressures.

A recent series of papers explains how downhole temperatures and pressures can affect drilling (Fertl and Timko, 1972; Timko and Fertl, 1972). Methods of detecting abnormal pressures, compensating for them, and evaluating the hydrocarbon potential of geopressured strata are discussed.

References

American Petroleum Institute, 1968. API Recommended Practice for Analysis of Oilfield Waters. Subcommittee on Analysis of Oilfield Waters, API, RP 45, 2nd ed., 49 pp.

Burst, J.F., 1969. Diagenesis of Gulf Coast clayey sediments and its possible relation to petroleum migration. Bull. Am. Assoc. Pet. GeoL, 53:73-93.

Dickey, P.A., Collins, A.G. and Fajardo, I., 1972. Chemical composition of deep formation waters in southwestern Louisiana. Bull. Am. Assoc. Pet. GeoL, 56:1530-1533.

Dickey, P.A., Shiram, C.R. and Paine, W.R., 1968. Abnormal pressures in deep wells of southwestern Louisiana. Science, 160: 609-615.

Dickinson, G., 1953. Geological aspects of abnormal reservoir pressures in Gulf Coast Louisiana, Bull. A m . Assoc. Pet. GeoL, 37:410-432.

Fajardo, I., 1968. A Study of the Connate Waters and Clay Mineralogy. M.S. Thesis, University of Tulsa, Tulsa, Okla., 50 pp.

Fertl, W.H. and Timko, D.J., 1970. Overpressured formations, 2. How abnormal pressure-detection techniques are applied. Oil Gas J., 68:62-71.

Fertl, W.H. and Timko, D.J., 1972. How downhole temperatures, pressures affect drilling. World Oil, 174(7):67-70; 175(1):47-49; 175(2):36-39, 66; 175(4):45-50; 176(2): 47-50.

Finch, W.D., 1969. Abnormal pressure in the Antelope field, North Dakota. J. Pet. Technol., 21: 821-835.

Forgotson, J.M., 1969. Indication of proximity of high pressure fluid reservoir, Louisiana and Texas Gulf Coast. Bull Am. Assoc. Pet. GeoL, 53:171-173.

Foster, J.B. and Whalen, H.E., 1966. Estimation of formation pressures from electrical surveys - offshore Louisiana. J. Pet. TechnoL, 18:165-171.

Fowler, Jr., A.W., 1970. Pressures, hydrocarbon accumulation, and salinities - Chocolate Bayou field, Brazoria County, Texas. J. Pet. TechnoL, 22:411-423.

Harkins, K.S. and Baugher, 111, J.W., 1969. Geological significance of abnormal formation pressures. J. Pet. TechnoL, 21:961-966.

Hottmann, C.E. and Johnson, R.K., 1965. Estimation of formation pressures from log- derived shale properties J. Pet. TechnoL, 17:717-721.

Jones, P.H., 1969. Hydrodynamics of geopressure in the North Gulf of Mexico Basin. J. Pet. TechnoL, 21:803-810.

Pennebaker, E.S., 1968. Detection of abnormal pressure formations from seismic field records. Presented at API Southern Dist. Meet., San Antonio, Texas, March 6-8, 1968, API Paper, No. 926-13C.

REFERENCES 365

Perry, D.R., 1969. A Correlation of Reserves and Drive Mechanisms with Reservoir Pres- sure Gradients on Geopressured Gas Reservoirs in Southwest Louisiana. M.S. Thesis, Southwest Louisiana University, Lafayette, La., 54 pp.

Powers, M.C., 1967. Fluid-release mechanisms in compacting marine mudrocks and their importance in oil exploration. Bull. Am. Assoc. Pet. GeoL, 51:1240-1254.

Schmidt, G.W., 1973. Interstitial water composition and geochemistry of deep Gulf Coast shales and sandstones. Bull. Am. Assoc. Pet. Geol., 57: 321-377.

Sulin, V.A., 1946. Waters of Petroleum Formation in the System o f Natural Waters. Gostoptekhizdat, Moscow, 96 pp.

Terzaghi, K. and Peck, R.R., 1948. Soil Mechanics in Engineering Practice. John Wiley and Sons, New York, N.Y., 56 pp.

Timko, D.J. and Fertl, W.H., 1972. How downhole temperatures, pressures affect drilling. \ World Oil, 175(5):73-81; 175(6):79-82; 175(7):5*62; 176(1):45-48; 176(4):.

Wallace, W.E., 1969. Water production from abnormally pressured gas reservoirs in South

Young, A. and Low, P.F., 1965. Osmosis in argillaceous rocks. Bull Am. Assoc. Pet.

62-65.

Louisiana. J. Pet. Technol., 21 :969-982.

Geol., 49:1004-1008.

Chapter 12. COMPATIBILITY OF OILFIELD WATERS

Waters used for the secondary recovery of oil by waterflooding usually contain a number of inorganic salts and sometimes organic salts in solution. It is common practice t o test the compatibility of the injection water and water in the formation before starting a waterflood operation. Often this test is performed by mixing the injection water with the formation water in a glass container and observing to determine if a precipitate forms. The precip itate or scale can be analyzed to determine its composition.

Waters are compatible if they can be mixed without producing chemical reactions between the dissolved solids in the waters and precipitating insoluble compounds. The precipitated insoluble compounds are undesirable because they can reduce the permeability of a porous petroleum-productive rock formation, plug input wells in waterflood systems, and cause scale formation in water pumps and lines.

Some of the more common ions that frequently occur in oilfield waters and that cause precipitation in incompatible waters are: Ca+2, S P 2 , Ba+2, Fe+?, HC03-, and

Common reactions are:

CaC1, + Na2S04 +=

CaC1, +MgS04 += c a w 0 3 )2 -b

CaC12 + 2NaHC03 += SrC1, + NaS04 +=

SrClz +MgSO, +=

BaC12 +NaS04 +=

BaCl2 +MgSO, += Fe + H2S -b

Fez03 + 6H2S +=

2NaC1+ CaSO, 3- MgClz +CaS04 3- C02 + H 2 0 + CaCO, J- 2NaC1+ C02 + H 2 0 + CaCO 3- 2NaC1+ SrSO, 3- MgC12 +SrS04 J- 2NaC1+ BaSO, -1 MgC12 +BaS04 3- H2 + FeS 3- 6H,O + 2Fe2 S3 5.

A relatively insoluble compound CA where C is the cation and A is the anion will precipitate from an aqueous solution if:

where ac = the cation activity, a A = the anion activity in the solution, and SCA = the solubility product of the compound CA. When two salts with a common cation (CAI and CA2 ) are in equilibrium in a solution, the following will hold:

36 8 COMPATIBILITY OF OILFIELD WATERS

a~~ I ~ A , = &!Al PCA,

If a A l l a A , > SCA /SCA,, CA, will precipitate, and CA2 will dissolve if a~~ I ~ A , <SCA,ISCA,.

Deposition of scale in both primary and secondary recovery producing wells and formations is a very costly problem in the petroleum industry. The scale not only restricts production but also causes inefficiency and production equipment failure. Scale deposits are caused by mixing incompatible waters and by environmental changes during the production of well fluids. For example, as production begins, the pressure drops in the vicinity of the wellbore, allowing dissolved gases to escape from solution. The loss of C02 can cause calcium carbonate t o precipitate.

The decrease in pressure also can cause the vapor pressure of the brine to increase. The temperature of the brine will decrease because heat energy is required to vaporize the water, causing calcium sulfate to precipitate.

Wellbore and formation damage

In several case studies Vetter and Phillips (1970) found that calcium sulfate deposits form in both primary and secondary petroleum production operations. The scale forms within the formation and causes production loss and permanent damage. In many cases damage to the formation cannot be corrected even by fracturing. Research has indicated that sodium carbonate can cause the metathesis of anhydrite and gypsum to calcium carbonate. This might work in a formation that is partially plugged. For example, a water containing sodium carbonate could be injected into the formation and allowed to react with the scale. An acidified water then could be injected into the formation to remove the carbonate and hopefully clean the formation, allowing recovery of more oil.

Potential scale deposition should be predicted as soon as the well begins production, and the correct inhibitor should be added immediately rather than following the common practice which is to pull the tubing after a production decline and find scale on the metal surface. Scaling can occur within the formation and never show up on the tubing. Pressure drops are the primary cause of calcium sulfate scaling within a formation, when the formation brine is saturated with calcium sulfate.

Important variables related to scaling are: (1) Temperature of the formation in relation to solubility of the possible

scale former in the fluids passing through it. CaS04 becomes less soluble

WELLBORE AND FORMATION DAMAGE 369

with increasing temperature (Blount and Dickson, 1969), while BaS04 becomes more soluble (Templeton, 1960).

(2) Subsurface pressures change for any system, with the highest pressure found while the fluid flows through the formation. The greatest pressure change is at the sand face of the producing well (Vetter and Phillips, 1970), which causes this area to be where solubility changes are the greatest. Depo- sition of scale at this point is the most damaging to oil production and the most difficult to discover or to remedy. Very few data are available on pressuresolubility relations of most scale forming compounds, but CaSO, has been shown to decrease in solubility with decrease in pressure at NaCl concentrations t o 10% (Fulford, 1968).

(3) Brine concentration, exclusive of precipitating compounds, also influences scale formation. Most electrolytes in ionic form cause an increase in the solubility of compounds which form scales. The solubility normally increases with increasing electrolyte concentration unless some other solubility equilibrium is reached. This can occur, for example, when BaS04 saturation level is reduced because of increasing amounts of Ca+2 ion in the solution (Davis and Collins, 1971). Other properties of brine known to influence the solubility levels of scale formers are gases in solution, hydrogen- ion concentration, ion pairs, and dissolved organic chelates (Weintritt and Cowan, 1967).

Waterflooding of petroleum reservoirs has been successfully carried out for many years. Large quantities of petroleum are produced through secondary recovery by forcing water (usually a brine) into an oil sand which has become unproductive by primary production methods. However, the efficiency of the operation is often low, and the amount of petroleum remaining in the sand after waterflooding can be as high as 50% of the original accumulation (Shaffer, 1967). One of the reasons such a high proportion of the oil remains unrecovered is because the injection pressures become economically too large to continue forcing water through the sand to displace the oil. The gradual deposition of solid material precipitating from the water closes the permeable channels and slows the flow at the producing well.

Dilution of the water injected into a formation often occurs, and additional makeup water is necessary. The slow mixing of connate (interstitial) waters of the formation or the introduction of water from associated aquifers, both underground and on the surface, contributes to the instability of the injection water.

The deposition of scale in wellbores, sand faces, and piping has reduced oil production in many fields. Removal of scale is difficult, often impossible, and methods to avoid its formation need additional development. Scaling results from the precipitation of a solid from a formation water or from injection water in waterflood operations. The most common causes of scale are: (1) temperature and/or pressure changes to which the formation water is subjected; (2) dilution with makeup water (in secondary recovery opera-

370 COMPATIBILITY OF 0 ILF IELD WATERS

tions) or mixing with other formation water containing incompatible ions; (3) evaporation causing increased concentrations of dissolved solids allowing saturation to be reached; (4) supersaturation caused by formation water flowing through and dissolving slightly soluble solids.

When the composition and temperature of a brine, saturated with CaSO,, remain constant, precipitation will occur if the pressure drops. Scaling is not likely with increasing pressure under the same conditions. However, these conclusions must be modified if the brine is flowing through beds conkaining soluble compounds of calcium or sulfate or if another water source is altering the brine concentration. Because of moderate rise in brine temperature as it travels betwsen the injection wellhead and the bottomhole and the rapid rise in pressure, scaling of CaS0, is not likely in the injection well.

The formation of BaS0, scale is worthy of special attention. Most barium compounds are relatively insoluble, and large volumes of brine often are necessary to cause heavy BaS0, scale. The most unique characteristic of this compound is its crystal growth (Weintritt and Cowan, 1967). It will remain in a supersaturated solution for an unpredictable time and then will precipitate slowly and in a crystal form which has not been duplicated in the laboratory. Some observers attribute this phenomenon to the requirement of a unique solid crystal acting as a seed to promote BaSO, precipitation. Furthermore, the forming crystal adheres to other larger solids suspended in the solution or attached to the associated solid phase. This causes the scale to occur in larger quantities than if it were pure barite.

In the Raleigh field, Smith County, Mississippi, a scale consisting of con- centric rings of prismatic barite commonly occurs. The barite prisms are about 0.5 mm in length and contain up to 1% strontium and lead.

The pumping equipment in the Pisgah field, Rankin County, Mississippi, often is plagued with a scale composed of metallic lead containing small fragments of steel. The steel is from the pumping mechanism but the lead must be from the formation water because the amount of dissolved lead ranges up to 100 mg/l. Maintenance of the wells to remove the lead scale occurs as often as every 10 days.

Knowledge of the solubilities of BaS0, and SrS0, in solutions containing NaCl, CaCl,, and NaHCO, needs to be increased to better understand various precipitation reactions that occur when waters containing these salts mix. Information concerning the effects of heat and pressure upon these reactions is lacking.

Solubility of calcium compounds in various salt solutions

Frear and Johnston (1929) measured the solubility of calcite in water saturated with carbon dioxide and obtained an activity of 4.8 x at 25OC. Ellis (1963) determined that the solubility of calcite was significantly less in the laboratory salt solutions than in hydrothermal solutions with similar ionic strength.

SOLUBILITY OF CALCIUM COMPOUNDS 371

Stiff (1952) developed a graphic method of predicting the tendency of oilfield waters to deposit calcium sulfate. Diagrams can be used to find the maximum solubility of a salt in waters of similar composition. This information is useful in predicting that a given brine has a scale forming tendency. However, better pressure and temperature data in respect to their effect on scale formation are needed.

Akin and Lagerwerff (1965) studied the solubility of calcite in relation to ionic strength. The soluble salts used were NaC1, NaHCO,, and CaC12; the ionic strength of the solutions ranged up to about 0.09 and their data agreed well with the Debye-Huckel theory. They also studied the effect of Mg" and S04-2 and found that the solubility of calcite was enhanced by these ions relative to theoretical values.

Ostroff and Metler (1966) determined the solubility of calcium sulfate dihydrate in the system NaC1-MgC12-H20 in 5.50 molal NaCl and 0.340 molal MgC12 admixtures at 28", 38', 50°, 70°, and 90'C. Their results indicate that the solubility increases in the presence of small amounts of MgC12 in NaCl solutions up to about 2.5 molal NaC1. The MgC12 effect decreases in higher molalities of NaCl until at about 4 mold NaCl a plateau is reached.

Shaffer (1967) studied the solubility of gypsum in sea water and sea-water concentrates. He found that the solubility product of gypsum is greater in the highly concentrated brines and also that in these brines it increased with increasing temperature.

Glater et al. (1967) developed a method to measure calcium sulfate scaling thresholds in saline water samples at 100'C. They found a correlation of ionic strength with calcium sulfate solubility, and used a gSaphical method to relate scaling threshold to the concentration of calcium and sulfate ions in saline water.

Pytkowicz et al. (1967) measured in situ the pressure coefficient of the aragonitic oolites with pH electrodes, Their results indicate that the pressure coefficient or the apparent solubility must be known to obtain accurate solubility data at high pressures.

Fulford (1968) found that the solubility of gypsum or anhydrite increases with pressure because of a small decrease in total volume as the scale dissolves. Subsequently with a pressure drop a supersaturated solution forms and gypsum precipitates. In very concentrated brines this does not occur because the solubility of gypsum in very concentrated brines is less dependent upon pressure. He presented several equations to calculate anhydrite and gypsum solubilities.

Blount and Dickson (1969) determined the solubility of anhydrite in NaCl solutions at 100'-450'C and 1-1,000 bars. They found that anhydrite solubility increased with temperature and NaCl concentrations.

Glew and Hames (1970) determined the solubilities cf gypsum, disodium pentacalcium sulfate, and anhydrite in sodium chlor,de solutions. Their results indicated that the solubilities of these comr#ounds decreased in chloride solutions with molalities greater than 3.5.


Vetter and Phillips (1970) included the effects of complicated downhole phase equilibria to develop an improved thermodynamic method to predict deposition of calcium sulfate. According to them the calculated solubility is as accurate as the experimentally determined solubility; however, additional data are needed concerning the solubility of gypsum in brines at high pressures. These data are needed to determine which CaS04 compounds are formed under high pressure in brines. Knowledge of pressure drops either at the wellhead or within the reservoir is important to determine where scale deposition occurs.

Solubilities of the sulfates of barium and strontium in saline solutions

Neuman (1933) published results of studies of BaS0, solubility in aqueous solutions of potassium, magnesium, and lanthanum as chlorides and nitrates. His data show that BaS04 solubility increases with the increasing complexity of the major solute, and in the order (3, -1) > (2, -1) > (1, -1) of equal molality solutions.

Gates and Caraway (1965) analyzed California oil-well scale and found in a BaS0,-type scale significant amounts of strontium along with iron, calcium, magnesium, and some carbonate. Weintritt and Cowan (1967) studied the unique characteristics of BaS04 -scale deposition and concluded, “the presence of strontium in barium sulfate scales deposited from oilfield waters appears to be common.” All of the sulfate deposits analyzed contained strontium sulfate in concentrations ranging from 1.2 to 15.9%, and barium sulfate in concentrations ranging from 63.7 to 97.5%.

Templeton (1960) studied the solubility of BaS04 in solutions at 25OC and at sodium chloride molalities between 0.1 and 5.0. He found that at constant ionic strength the solubility of BaS0, increases with increasing temperature, and observed that calcium sulfate exhibits an inverse reaction with increasing temperature.

Experimental determination of some solubilities of the sulfates of barium and strontium

A radioisotope-tagged solution of Na2 SO4 was prepared from which aliquots were taken (Davis and Collins, 1971). The radioactive isotope was 35S. One aliquot was used to precipitate BaS04 by addition of an excess of BaCl,; a second portion was used to precipitate SrS04 by addition of appropriate equivalents of SrC12. These suspensions were stirred and allowed to settle. Following a 2 4 to 48-hour settling period, the precipitates were washed onto a 0.45-pm pore size filtering medium, and the washings were continued until the sulfate ion in the filtrates could not be further reduced. The tagged precipitate was removed from the filter, dried in an oven at 105OC, and transferred to storage vials. Standard samples of the sulfates were prepared by chelation in a 0.W solution of EDTA. Various strengths of

RESULTS AND DISCUSSION 373

5-80 mg/l of BaSO, and 50-800 mg/l of SrS04 were made and used as reference counting samples for all of the sulfate determinations.

A nonionic detergent (Triton X-100) and toluene emulsion (Patterson and Greene, 1965) were prepared, whereby l-cm3 sulfate samples in brine could be counted with greater than 20% efficiency. The emulsion forms a clear gel and permits a homogenous dispersion of the aqueous phase in the fluor with no salting out.

Solutions of various salts, such as those usually found in formation waters, were made up in strengths of 0.005-1.77 molal, and tagged solid barium or strontium sulfate was added. The chlorides of sodium, calcium, magnesium, and potassium were prepared, as were solutions of sodium bicarbonate, sodium borate, and potassium bromide. All of the solutions were stored in plastic bottles. To determine sulfate solubility, a 20-cm3 portion of one of the prepared salt solutions was transferred to a small plastic stoppered vial, and 0.1 g of the solid, tagged sulfate was added. This suspension was shaken in a wrist-action type shaker for 72 hours and then allowed to settle a minimum of 24 hours without opening the vial.

The samples were prepared in duplicate to assure equilibrium, and the operation was repeated when better precision was needed. The temperature of the suspension was raised briefly above the stabilized room temperature (25OC k l 0 C ) with a heat lamp during the shaking period, but no change was permitted during the last 24 hours nor during the settling period. When the sample container was opened, it was quickly filtered through a double Whatman No.42 filter paper, and 1 ml was transferred t o a counting vial which contained 12 ml of the Triton emulsion and 7 ml of deionized water. The sample then was counted in a liquid scintillation counter for 50 minutes. The chelated sulfate standards were counted in the same time period. By this method, the correction for radioactive decay could be omitted and the soluble sulfate values determined from a graph of the chelated standards (in mg/l) versus the counts per minute. Barium was analyzed by emission spectroscopy, but adequate precision at levels of 1 mg/l and less was difficult to achieve in the presence of ionic-strength salts encountered in some solutions.

Results and discussion of the experimental investigation

The values obtained from solubility measurements are shown in Table 12.1. The amounts of the alkaline sulfates which dissolve in other electrolyte solutions are tabulated alongside the total ionic strength of each solution. Ionic strength is the most useful concept yet developed to include the combined effects of the activities of several ionic species in a solution. Lewis and Randall (1923) state, “in dilute solutions, the activity coefficient of a given strong electrolyte is the same in all solutions of the same ionic strength.” It is defined as s = H m 1 2, ’, where m 1 = the ionic molality, and 2, = the charge of the ion in solution, the summation being taken over all ions, positive and negative. By definition, the activity of the dissolved species approaches the concentration value (molality) a t infinite dilution.

374 COMPATIBILITY OF OILFIELD WATERS

10.0 0.0

6.0

4.0

0 I

0 x 2 . 0

Since the thermodynamic solubility product Ku = x mso, x y2 and since y equals unity at zero ionic strength, a plot of log mso, versus the ionic strength function would extrapolate to zero concentration where log KuS = log rnso,. Fig. 12.1-3 give plots representing six electrolytes and the values of Ku'h are determined graphically. The value for the sulfate solubilities in pure water was determined experimentally and agreed with values in the literature.

In Fig. 12.1, the plot of BaS04 solubility versusds for the six electrolytes is almost identical at low ionic strength, a phenomenon to be expected from the statements above. The extrapolated KuS values of all systems are 1.05 x loe5 (within experimental limits). This fact must be correlated with the nature of the equation defining ionic strength. The square of the ionic valence gives the Mg+' and Ca+' ions four times the numerical weight of the Na+ and K+ ions. Molality values would indicate that the bivalent ions cause increased solubility effects.

Because borates are present in many oilfield waters, sodium borate was included to find differences in sulfate solubility in electrolytes containing a complex ion. As shown in Fig. 12.1 and 3, the solubility deviated from that of monatomic electrolytes, and the relationship described does not hold at higher solubilities of electrolytes containing complex ions.

Another ion commonly found in mineral waters is bicarbonate. Many water-bearing zones contain limestone and dolomite which slowly erode in water of low pH. The water carries away carbonates and bicarbonates. In this study, NaHCO, solutions of 0.005-1.0 molal were saturated with tagged

- KEY - - - - -

0 CoC12 -

- A No2 84 07 -

__ - MgC12 -

A KBr 0 NaCl X KCI

- -

- - 0 0 v) 0

lI. m 1.0 0 0.8

0.6 k a 0.4 _I

J 0 H

0.2

0. I

0 + SO4 Mo I o I i t ies 0 + SO4 Mo I o I i t ies 1

0 0.5 I .o I .5 2.0 2.5

4 l O N l C STRENGTH

Fig. 12.1. Concentration of saturated Bas04 in strong electrolyte solution.


TABLE 12.1

Solubility of Bas04 and SrS04 in electrolyte solution

Major solute Bas04 5r504 (molality) major solute system major solute system

Bas04 total ionic SrS04 total ionic (mg/l) strength (mg/l) strength

ca Cl2 0.010 0.015 0.020 0.025 0.045 0.050 0.090 0.100 0.136 0.200 0.226 0.300 0.400 0.456 0.500 0.934 1.000 2.000

M m 2 0.005 0.010 0.015 0.020 0.025 0.049 0.050 0.074 0.099 0.125 0.196 0.254 0.474 0.525 0.902 1.637

(5.0)*

(17.3)*

(16.3)* (10.8)*

(2.9)*

(44.5)*

6.2

7.6

11.5

15.5

17.7

16.2 16.3

16.6

11.3 2.5

5.4

6.9

9.8

13.3

18.0

25.9

32.0 33.2

0.03016

0.06013

0.15020

0.30027

0.60030

0.90028 1.20028

1.50028

3.00019 6.00004

0.02979

0.05982

0.1 4927

0.29 693

0.58831

1.42244

2.70655 4.93257

21 4 247

295 260

50 8

590

757

1,152

1,942

172 203 233

295 394

422

530

731

1,063

0.0347 0.0504

0.0815 0.1403

0.2819

0.4197

0.6959

1.3947

1.8438

0.0188 0.0344 0.0499

0.0805 0.1571

0.2324

0.2866

0.7782

1.5993

- * See footnote at end of Table.


TABLE 12.1 (continued)


Bas04 total ionic SrS04 total ionic strength (mg/l) strength (mg/l)

Na Cl 0.010 0.01 5 0.020 0.025 0.050 0.086 0.100 0.172 0.200 0.257 0.431 0.500 0.869 1 .ooo 1.771 2.000

KCl 0.010 0.015 0.020 0.025 0.050 0.067 0.100 0.200 0.202 0.338 0.500 0.684 1.000 1.396 2.000

(5.3)*

(5.6)*

(7.3)*

(11.3)*

(22.3)*

(35.7)*

(3.7)*

(25.8)*

3.6

4.2

5.4

7.1

10.0

14.8

20.2

27.2

4.2

4.9

6.3

8.6 11.2

16.8

21.6

27.2

0.01006

0.02007

0.05009

0.10012

0.20017

0.50025

1.00035

2.00047

0.01007

0.02008

0.05011

0.10015 0.20019

0.500 29

1.00037

2.00047

134 149

172 199 265

332

420 525

699

7 60

144 169

167

375

396 502

742

802

0.0129 0.0182

0.0288 0.0543 0.0914

0.1756

0.2667 0.4423

0.8840

1.7875

0.0131 0.0185

0.0286

0.0754

0.2109 0.3492

0.7001

1.4139

* See footnote at end of Table.

BaS04. However, only trace amounts of barium were found in solution, though the sulfate content increased with the amount of NaHCO, in solution. This apparent anomaly can be reconciled by the ionization of the HC03- ion into CO,-*, which in appreciable concentration would reduce the Ba+2 ion concentration according to the solubility product K,, = M B ~ x

MC03.


TABLE 12.1 (continued)


Bas04 total ionic SrS04 total ionic (mg/l) strength (mg/l) strength

XBr 0.010 0.015 0.020 0.042 0.050 0.084 0.100 0.126 0.200 0.211 0.426 0.500 0.866 1.000 2.000

Na2 B4 0 1 0.010 0.013 0.020 0.039 0.050 0.065 0.100 0.200

Pure Water

(3.6)* 4.1

4.7

6.3

8.2

11.0

16.2

21.8 (23.9)* 26.7

6.0

7.8

12.9

(23.7)* 21.0 (33.9)* 34.8

2.5

0.01007

0.02008

0.05011

0.10014

0.20019

0.50028

1.00037 2.00046

0.03010

0.06014

0.15022

0.30036 0.60060

0.00004

152 163

215

262

3 20

420 509

669

320

600

690

114

0.0133 0.0186

0.0467

0.0900

0.1335

0.2207 0.4378

0.8812

0.0462

0.1307

0.2100

0.0025

* Parentheses indicate barium ion and sulfate. ion determinations made separately.

The effect of high concentration of CaClz on BaS04 solubility is indicated by the solid curve of Fig. 12.1. At concentrations of 2 molal, the BaS04 solubility has dropped to values close to that of the compound in pure Hz 0. The maximum value is reached between 0.2 and 0.4 molal where the decline begins. The accompanying broken line of Hg. 12.1, which is a plot of Ba+2 + SO4-' ions determined separately, shows the reduced solu-

378 COMPATIBILITY OF 0 IL F IE LD WATERS

- Ka = 2.4 x -

I I I I I I I

-1 IONIC STRENGTH

Fig. 12.2. Concentrations of saturated SrS04 in strong electrolyte solutions of NaCl, KCl, and KBr.

4 IONIC STRENGTH

Fig. 12.3. Concentrations of saturated SrSO4 in strong electrolyte solutions of MgClz, CaClz , and Na2 B4 0,.


bility of the Ba ion caused by the equilibrium Ca+’ + S04-2 * CaSO, (Ksp

The effect of the ions of strong electrolyte solutions on SrS04 solubility is similar to that observed when BaS04 solubility was studied. The Na+, K+, C1-, and Br- ions have approximately equal effect, and all determined values fall on a common curve (Fig. 12.2). The increase in sulfate solubility is marked in dilute solutions but reaches a maximum a t concentrations with ionic strength near 1. This is the average value calculated for sea water. When bivalent ions Mg+’ and Ca+2 are used in the strong electrolyte (Fig. 12.3), the SrS04 solubility remains of the same relation t o the total ionic strength as for the monovalent ions.

A study of the system SrS04-NaHC03 -H2 0 was limited by the insolu- bility of SrCO, . The ionization of the bicarbonate to H+ and COSw2 would result in the precipitation of any Sr+’ which dissolves and leaves the S04-2 in solution. This relationship is similar t o the BaS04 -NaHC03 -H2 0 system and is worthy of special note. That is, when carbonate or bicarbonate waters are diluted or intermixed with waters containing barium or strontium, an unstable solution is formed.

Experimental data indicate that maximum sulfate solubility in strong electrolytes begins at an ionic strength of approximately 1. When the principal cation in solution is the Ca+2 ion, sulfate solubility decreases after the ionic strength exceeds unity. Blount (1965), when measuring solubility of CaSO, in the system CaS04-NaClLH2 0, and Lucchesi and Whitney (1962),

< 1.95 10-4).

TABLE12.11

Sulfate solubilities in synthetic brines ~ ~ ~~~

Concentration (molal)

brine 1 brine 2 brine 3

Na+ Ca+’ Mg+’ K+ c1- Br- 1-

Barium sulfate solubility Bas04 (mg/l) Bas04 (molality)

1.2179 0.0250 0.0206 0.0051 1.3019 0.0125 0.0001

60 2.57 x

1.7399 0.0374 0.0823 0.0051 1.9650 0.0188 0.0000

63 D4 2.70 x

2.4359 0.0499 0.0411 0.0193 2.6113 0.0250 0.0001

66 D4 2.83 x o4

Ionic strength (s) 1.3600 2.1038 3.0278

Strontium sulfate solubility SrS04 (mg/l) 813 922 , 958 SrS04 (molality) 44.26 x lo4 50.19 x lo4 52.18 x lo4 Ionic strength (s) 1.3777 2.1239 3.0487


when measuring SrS04-NaC1-H2 0 solubility equilibria, found similar maximums. By using ionic-strength calculations in place of weight per unit volume, the predictions of mineral water stability become more accurate and dilutions more feasible.

Three synthetic brines were made with salts concentrations in the range of many formation waters and containing the major salts found in these waters. Table 12.11 gives these concentrations and results of a BaS04 and a SrS04 solubility determination. The values found when plotted against the ionic- strength function of the brine fall on the same curve as the barium salt in Fig. 12.1 and the strontium salt in Fig. 12.2. No carbonates were added to these synthetic brines.

Brine stabilization

Efforts to stabilize the brines used in petroleum production have been extensive and successful in many cases, but the complexity of the problem in other cases is reported. Water treating units are considered necessary in waterflooding operations, but none fully satisfy the operator’s apprehension that there may be plugging within the reservoir. Addition of solubilizing, chelating, and clarifying agents to the brine has helped, but economics limit the quantities used. Tests for compatibility of the fluids as they exist in the formation and in the wellbore give erroneous results because the subsurface environment cannot be fully duplicated a t the surface.

To aid brine stabilization programs, several studies of the solubilities of various relatively insoluble compounds have been made as previously discussed. Usually the results of these studies are reported as solubility products of various pure compounds (CaS04, BaS04, CaCO, , etc.) in the presence of other ions, dissolved gases, ion pairs, and various sized crystals of the compound under study. Some efforts have been made using mixed cations and anions in solution with the compound under study, including limited study of sulfates in sea water or synthetic sea water (Shaffer, 1967). Various easily measured parameters such as percent chlorides, total solids, and ionic strength have been plotted against solubility product of the potential scale former. Very little correlation suitable for direct field application has been found. For example, the author has measured BaS04 solubility in CaC12, MgC12, NaC1, and other salt solutions using ionic strength as the common property. However, a synthetic sea water containing these compounds and having comparable ionic strength will dissolve double the weight of BaS04 in milligrams per liter with respect to any solution containing a single salt.

Fulford (1968) and Vetter and Phillips (1970) proposed useful formulas and graphs to use in predicting scaling from calcium sulfate. Fig. 12.443 are included for possible use in predicting potential scale problems from calcium sulfate, strontium sulfate, and barium sulfate. The figures are plots of molal solubility versus ionic strength. The advantage of this plot is that the ionic strength of any given water can be calculated from its chemical composition,

BRINE STABILIZATION

y 12-

381

K E Y

IONIC S T R E N G T H

Fig. 12.4. Solubility of CaSO4 versus ionic strength of aqueous solutions (Ostroff and Metler, 1966).

t

IONIC S T R E N G T H

Fig. 12.5. Solubility of SrS04 versus ionic strength of CaClz, MgClz, NaCl, KCl, and KBr (Davis and Collins, 1971).

1

aqueous solutions containing

and the solubility of a given compound is a direct function of the ionic strength of the solution. Therefore, a very good approximation of the solubility of a given compound in a given water solution can be made. For example, if a water with an ionic strength of 0.1 contains 0.001 molal of strontium sulfate, it can be assumed that the water is undersaturated with respect to strontium sulfate as illustrated in Fig. 12.5. However, if the water contains 0.003 molal of strontium sulfate it is oversaturated and some treatment should be made if the water is to be reinjected.


01 I a I I I , 1 1 1 I , I I I I I I I I , I , 1 , 1 ,

0.01 0.02 0.040.06 01 a2 04 060.0 1.0 2 4 6 8 IONIC STRENGTH

3

Fig. 12.6. Solubility of Bas04 versus ionic strength of aqueous solutions containing CaClz, MgClz, NaCI, KCl, and KBr (Davis and Collins, 1971).

Similar curves can be made using appropriate solubility data for calcium carbonate and for iron compounds. However, it should be noted that application of this technique only gives an estimation of the maximum solubility of a compound in waters of similar ionic compositions. Better data on pressure and temperature and how they affect the solubilities are needed before adequate prediction equations can be developed.

Mixing of subsurface waters

Mixing of surface and subsurface waters results in solutions which are either saturated or undersaturated with relatively insoluble compounds such as calcium carbonate, calcium sulfate, strontium sulfate, and barium sulfate. These compounds are considered because they often are found in scales formed because of mixing of formation waters.

Hydrodynamic potentials caused by differences in elevation, weight of the overlying fluids and rocks, secondary cementation of rock pores (Levorsen, 1967), temperature differences, osmotic pressures, and chemical and physical reactions cause subsurface waters t o move (Hubbert, 1953). Popov and Goldshteyn (1957) described a large hydrodynamic system of de- scending fresh water and ascending saline water which could mix to form a fresh-saline water mixture. Henningsen (1962) found that recharge waters into Trinity aquifers were two types of water from strata of different lithology and with basinward movement of the waters they mixed to form a third type of water. Mixing of fresh waters with encroaching sea water occurs according to Kohout (1960), Columbus (1965), and Upson (1966).

MIXING OF SUBSURFACE WATERS 383

z

I- 4

0 1.200-

a

Estimating strontium sulfate saturation in waterflood makeup brines (Biles, 1 9 72)

L

The data in Tables 12.1 and I1 were used by Biles (1972) to estimate the saturation point of strontium sulfate in waterflood makeup waters. Ac- cording to him, brines used as makeup water for waterflood operations often are more concentrated in dissolved solids than are the single solute samples shown in Table 12.1. However, considering that the sodium concentrations are 96, 93, and 97 mole %, respectively, in the synthetic brines 1, 2, and 3 shown in Table 12.11, it appears reasonable in lieu of experimental data to extend the NaCl data to the higher.concentration range with these data.

Fig. 12.7 is a plot of the milligrams per liter of strontium sulfate in solution as a function of the total ionic strength of the solution. The data were taken from Table 12.1 and 11. A smooth curve can be plotted for Fig. 12.7 if the strontium sulfate value at 1.7875 total ionic strength (Table 12.1) is ignored. This curve can be extrapolated for use in estimating the amount of strontium sulfate in milligrams per liter that is likely to be soluble in more concentrated brines. A similar curve could be plotted for the solubility of barium sulfate.

Consider a brine that does not contain the stoichiometric combining weight ratio of strontium and sulfate as shown in Table 12.111. To compare the amount of strontium sulfate apparently at equilibrium in this brine with the solubility data in Tables 12.1 and 11, it is necessary to use another approach. The solubility product of a solute A, Bm is determined by the molalities of the ions composing the solute and their activity coefficients:

"--"I

I I I I 1) 2.0 3.0

TOTAL IONIC STRENGTH 3

Fig. 12.7. Solubility of strontium sulfate versus ionic strength of the solution (J. Biles, written communication, Cities Service Oil Company, Tulsa, Okla., 1972).


TABLE 12.111

Composition of a brine that does not contain a stoichiometric combining weight ratio of strontium and sulfate*

Ion mg/l me/l Molalit y

Na+ K+ ca+' Mg+' Ba+' sr+' Fe" c1- s04-'

49,000 220

11,500 2,400

25 1,000 101

106,140 170

2,130 6

57 4 197

< 1 23 4

2,990 4

2.24 0.00589 0.303 0.104 0.00018 0.012 0.00189 3.15 0.00189

Total 170,556

* Total ionic strength = 3.54; density at 22OC = 1,120 g/l; grams H20/1 = 950.

The activity coefficients are determined primarily by the total ionic strength of the solution, and in a solution saturated with the solute A, B, :

If the total ionic strength is unchanged, Y B ~ and [K,,/(YA~ Y B ~ ) ] are constant. Therefore, the concentration of A in equilibnum with a given concentration of B in a saturated solution of A, B, is defined:

Plotting the data in Tables 12.1 and I1 for the solubility of SrS04 in sodium chloride and synthetic brine solutions as the product of the molalities of strontium and sulfate versus total ionic strength, as shown in Fig. 12.8, indicates that the brine in Table 12.111 is undersaturated in SrS04 by d(280 x lo-') - (227 x lo-') molal. This method is in error to the extent that the SrS04 solubility is affected differently by the ions in the brine in Table 12.111 than by the ions in the brines shown in Table 12.11. Neverthe- less, this approach is valuable in that a reasonable estimate can be made of the degree of undersaturation of SrS04.

Now consider the advisability of mixing the brine shown in Table 12.111 with another brine which contains less dissolved solids and a comparable percentage of cations as sodium and about 1,850 mg/l of sulfate. To determine the solubility of SrS04 in various mixtures of waters, the product of the weighted average molalities of strontium and sulfate was determined for

MIXING OF SUBSURFACE WATERS 385

- 240 -

200 -

KEY

0 In NaCl solutions A In synthetic brines

TOTAL IONIC STRENGTH 3

Fig. 12.8. Solubility of strontium sulfate as a product of the molalities of strontium and sulfate versus the ionic strength of the solution (J. Biles, written communication, Cities Service Oil Company, Tulsa, Okla., 1972). Filled square shows the product of the molalities of (Sr )( SO4 ) in Table 12.111 brine.

6

9 t

E

a.

0 a a

J

a w

z

I-

3 I- 3

2

a

600 -514 g / kiloliter

500

* 200

100 ?? 0

m

100 TABLE 12.X BRINE, percent

Fig. 12.9. Plot of the supersaturation of a mixture of the brine shown in Table 12.111 with a brine containing 1,850 mg/l sulfate versus the Table 12.111 brine in percent (J. Biles, written communication, Cities Service Oil Company, Tulsa, Okla., 1972).


each mixture and compared with the comparable values in Tables 12.1 and I1 and Fig. 12.8. It was determined that a maximum supersaturation of 514 g/kl occurred when the mixture contained 60% of the brine shown in Table 12.111 as illustrated in Fig. 12.9. Mixtures containing less than 9% and more than 97% of the brine shown in Table 12.111 were undersaturated in &SO4 when mixed with a brine containing 1,850 mg/l of sulfate. The same error mentioned in the above paragraph will be present, but the correction would not greatly affect the value obtained using solubility data from Table 12.11.

References

Akin, G.W. and Lagerwerff, J.V., 1965. Calcium carbonate equilibria in aqueous solutions open to the air, I. The solubility of calcite in relation to ionic strength; 11. Enhanced solubility of CaC03 in the presence of Mg” and SO4’-. Geochim. Cosmochim. Acta, 29: 343-360.

Blount, C.W., 1965. The Solubility o f Anhydrite in the Systems C a S 0 4 - H z 0 and CaS04 -NaCl-H2 0 and Its Geologic Significance. Ph.D. Dissertation, University of California, Riverside, Calif., 179 pp.

Blount, C.W. and Dickson, F.W., 1969. The Solubility of anhydrite (CaS04) in NaCl-H’O from 100 to 45OoC and 1 to 1000 bars, Geochim. Cosmochim. Acta, 33:227-245.

Columbus, N., 1965. Viscous model study of sea water intrusion in water table aquifers. Water Resour. Res., 1:318-323.

Davis, J.W. and Collins, A.G., 1971. Solubility of barium and strontium sulfates in strong electrolyte solutions. Environ. Sci TechnoL , 5:1039-1043.

Ellis, A.J., 1963. The solubility of calcite in sodium chloride solutions at high temperatures. Am. J. S c i , 261:259-267.

Frear, G.L. and Johnstonb J., 1929. Solubility of calcium carbonate (calcite) in certain aqueous solutions at 25 . J. A m . Chem. SOC., 51:2082-2093.

Fulford, R.S., 1968. Effects of brine concentration and pressure drop on gypsum scaling in oil wells. J. Pet. Technol., 20:559-564.

Gates, G.L. and Caraway, W.H., 1965. Oil well scale formation in waterflood operations using ocean brines, Wilmington, Calif. US. Bur. Min. Rep. Invest., No.6658, 28 pp.

Glater, J., Ssutu, L. and McCutchan, J.W., 1967. Laboratory method for predicting calcium sulfate scaling thresholds, Environ. Sci Technol, 1:41-52.

Glew, D.N. and Hames, D.A., 1970. Gypsum, disodium pentacalcium sulfate, and anhydrite solubilities in concentrated sodium chloride solutions, Can. J. Chem., 48:3734-3738.

Henningsen, E.R., 1962. Water diagenesis in Lower Cretaceous Trinity aquifers of Central Texas. Baylor Univ. Geol. Studies, Bull., 3~38.

Hubbert, M.K., 1953. Entrapment of petroleum under hydrodynamic conditions, Bull. Am. Assoc. Pet. Geol., 37:1954-2026.

Kohout, F.A., 1960. Cyclic flow of salt water in the Biscayne aquifer of southeastern Florida, J. Geophys. Res., 65:2133-2141.

Levorsen, A.I., 1967. Geology o f Petroleum (revised by F.A.F. Berry). W.H. Freeman, San Francisco, Calif., 724 pp.

Lewis, G.N. and Randall, H.M., 1923. Thermodynamics. McGraw-Hill, New York, N.Y., 723 pp.

Lucchesi, P.J. and Whitney, E.D., 1962. Solubility of strontium sulfate in water and aqueous solution of hydrogen chloride, sodium chloride, sulfuric acid and sodium sulfate by the radiotracer method. J. AppL Chem. (London), 12:277-279.

Neuman, E.W., 1933. Solubility relations of barium sulfate in aqueous solutions of strong electrolytes. J. Am. Chem. SOC., 55:879-884.

REFERENCES 387

Ostroff, A.G. and Metler, A.V., 196:. Soltbility of calcium sulfate dihydrate in the system NaCl-MgC12-H20 from 28 to 70 C. J. Chem. Eng. Data, 11:346-350.

Patterson, M.S. and Greene, R.C., 1965. Measurement of low energy beta-emitters in aqueous solution by liquid scintillation counting of emulsions. Anal. Chem., 3 7 : 85 4-85 7.

Popov, A.I. and Goldshteyn, R.I., 1967. Hydrologic zoning of hydrostatic systems as a mineralizing factor in the stratal cover of Central Asia. Dokl. Akad. Nauk S.S.S.R., Earth Sci Sect. , 17:118-120 (transl.).

Pytkowicz, R.M., Disteche, A. and Disteche, S., 1967. Calcium carbonate in sea water at in situ pressures. Earth Planet. Sci Lett . , 2:430-432.

Shaffer, L.H., 1967. Solubility of gypsum in sea water and sea water concentrates at temperatures from ambient t o 65 C. J. Chem. Eng. Data, 12:183-188.

Stiff, H.A., 1952. A method for predicting the tendency of oilfield waters to deposit calcium sulfate. AIME, Pet. Trans., 195:25-28.

Templeton, C.C., 1960. Solubility of barium sulfate in sodium chloride solutions from 25' to 95'C. J. Chem. Eng. Data, 5:514-516.

Upson, J.E., 1966. Relationships of fresh and salty groundwater in the Northern Atlantic Coastal Plain of the United States. U.S. Geol. Surv. Prof. Paper, No.550-C, pp. 2 3 5-2 4 3.

Vetter, O.J.G. and Phillips, R.C., 1970. Prediction of deposition of calcium sulfate scale under down-hole conditions. J. Pet. TechnoL, 22:1299-1308.

Weintritt, D.J. and Cowan, J.C., 1967. Unique characteristics of barium sulfate scale deposition. J. Pet. TechnoL, 19:1381-1394.

Chapter 13. VALUABLE MINERALS IN OILFIELD WATERS

In the early days of the oil industry, oilfield brines were allowed to flow by natural drainage into streams until it was noted that some of the once good fishing streams contained less fish. Fur-bearing animals had disappeared in these areas and dead trees and barren soils now bordered these same streams that once had luxurious vegetation. A few years prior to 1935, litigation pertaining to pollution of fresh water was taking a heavy toll from oil operators. In certair, older oil producing areas, extensive plots of ground still are barren, with no living vegetation. The litigations against oil operators combined with legislation for fresh-water protection to force better disposal techniques.

At first, evaporation ponds were employed; however, usually more brine drained into fresh-water aquifers than evaporated. Until recently a widely employed practice for disposal was the dumping of oil brines into salt-water bodies when they existed nearby. This disposal method was practiced along the Gulf of Mexico and in California. Authorities in these areas insisted that oil separation be highly efficient to prevent damage to fish and oyster popu- lations. Recently the State pollution boards have ruled that oilfield brines can no longer be dumped into surface salt-water bodies. In California excess oilfield waters are being injected into porous subsurface formations as rapidly as the injection systems can be constructed.

The Plains States are not only situated in a hard water beit, but seldom have they had an overabundance of usable or surface ground waters. For this reason, State legislatures passed laws for the protection of fresh-water supplies, allowing the return of oilfield brines to subsurface formations and allowing the repressuring or waterflood of oil properties with salt water. Subsurface brine disposal has since become the common practice. Since the laws were passed to allow subsurface disposal, more legislation has both forced such disposal and set up tight controls for it. A survey of cost data on subsurface injection in 1968 showed that subsurface disposal costs ranged from 6.6 to 19.8 cents per m3. These figures were based on operating costs plus 5-year amortization.

Costs vary with the amount of treatment necessary before injection, the number of production wells per injection well, and the costs of drilling injection wells or the depth of the injection formation. The depths of disposal wells normally encountered required no injection pressure. The brines flow readily into the receiving formations under the gravity head alone.

390 VALUABLE MINERALS IN OILFIELD WATERS

Most of the 1.23 billion m3 of saline water that is produced yearly with petroleum is an expense to oil producers even though some of these waters contain salts yielding valuable elements which might be economically recovered (Angino, 1967). Elements found in some brines in economic concentrations are magnesium, calcium, potassium, lithium, boron, bromine, and iodine. Many of them are recovered by chemical companies from sea water, salt lakes, and subsurface saline waters (Collins, 1966; Brennan, 1966).

The recovery of minerals from saline waters dates back to the first time that someone precipitated a compound from a salt solution. Precipitation is the most used separation process employed in separating minerals from sea water or subsurface brines. Research continued on the separation methods which show economic promise in mineral separation from saline waters.

The Office of Saline Water, U S . Department of the Interior, supports research aimed at mineral recovery processes to be integrated with fresh- water plants. The object of this research is to reduce the cost of the produced fresh water by selling the extracted minerals at a profit. Now consider mineral recovery as a means of reducing the cost of oilfield brine disposal. There are additional advantages to mineral removal other than profits from the sale of the mineral. For instance, magnesium in sea water causes great expense because of scale formation in fresh-water plants.

Recovery of iodine and bromine from oilfield brines

Iodine

Iodine consumption in the United States exceeds domestic production. The Dow Chemical Company is the sole domestic producer of iodine. 75% of our domestic consumption is imported from Japan and Chile (Miller, 1965). Chilean nitrate deposits furnish most of the world’s supply of iodine. The United States and Japan obtain iodine from subsurface brines. In Michigan, Dow Chemical liberates iodine from brines by chlorination and blows the iodine out with air. Japan recovers iodine from brine by the cuprous iodine, electrolytic, or active carbon methods.

In the United States, iodine was discovered in an oilfield brine by C.W. Jones in Louisiana in 1926. The Dow Chemical Company and Jones combined to produce iodine from a brine well in Louisiana in 1928. At that time, iodine sold at a price between $9 and $11 per kg. In 1929 General Salt Company began extracting iodine from oilfield brines in California. General Salt halted operations when Chile cut the iodine price to $3.30 per kg. In 1931 Deepwater Chemical Company began to produce iodine from oilfield brines in California. Deepwater Chemical halted recovery of iodine from brines in the late 1950’s.

The Dow Chemical Company moved its iodine recovery operation from Louisiana to the California oilfield brines in 1932. The move was made for two reasons. The first reason was that California brines contained 60 ppm

RECOVERY OF IODINE AND BROMINE 391

iodine as compared to Louisiana’s 35 ppm. Secondly, the Dow Chemical Company was producing the brine in Louisiana from its own brine wells. In California the brine was produced by oil producers, because older wells produced 10 m3 of brine for every cubic meter of oil.

The Dow Chemical Company used two methods to obtain brine in Cali- fornia. The first was by paying royalties to oil producers for brines of high quality which were delivered at one pick-up point. The second was from an extensive brine gathering system which Dow built to collect the brines from independent producing companies. The second method of disposal was done for the producers in lieu of royalties. At one time, Dow operated three iodine recovery plants in California. Only one of the plants utilized a complete iodine recovery process.

In 1961 Dow began iodine recovery from Michigan brines at Midland, Michigan. These brines are not oilfield brines and although the Michigan brines contain only 35 ppm, compared to California’s 60 ppm, Dow found the Michigan operation less costly. Oilfield brines of California have two disadvantages. First, the brine source near DOW’S operation dwindled, and secondly, production costs in California rose.

Several economic advantages were available in the Michigan operation. For example, the iodine recovery process was integrated with processes for the recovery of calcium chloride, magnesium hydroxide, magnesium sulfate, bromine, potassium chloride, and magnesium chloride. The Midland operation boosted iodine recovery by using brines which were heated to 91°C for other extraction processes. The absence of oil in the Michigan brines negated the cost of oil removal. In California, oil removal is necessary to prevent interference with the oxidation step in the recovery process. The brine feed for the Midland operation is composed of brines produced from various strata in order t o obtain the desired feed for the most economical products.

Bromine

Bromine is another element that is recovered from oilfield brines. One plant that is located in Arkansas recovers bromine from the Smackover formation in the Catesville field. The bromine recovery project was originally included as part of the plans to unitize the field in 1956.

TABLE 13.1

Bromide recovery economics at Catesville

Minimum economical production Designed production Designed brine feed Plant cost Plant payout period

900,000 kg/year 1,800,000 kglyear 1,400 m3 /day

6 years $ 1,000,000


TABLE 13.11

Profitability of Catesville bromide project

Return o n investment Profit as sales percent Profit per m3 processed Investment Profit per year

16.7% 14.3% $ 0.346

$ 180,000 $ 1,100,000

Location of a bromine plant at Catesville offered several important advantages such as high bromide content (up to 6,000 mg/l) of the brine, field operation under a single company (unitization), excellent rail and road facilities, low-cost fuel, and regional market outlets. Production of Smackover brine in 1956 was approximately 190 m3 daily from four oil wells. This quantity of brine was not quite economical for a bromine recovery plant. Additional pumping equipment was installed in some of the wells in order to provide 795 m3 of brine daily for the bromine recovery project. Depleted oil wells later were employed for brine production to raise the plant feed to 1,430 m3 daily. Table 13.1 shows the initial economics associated with the bromine project as reported by Kincaid (1956).

The economic data presented in Table 13.1 are based on the bromine prices of 1956. In 1956 the price of bromine was 66 cents per kg. The price fluctuates with supply and demand. The data shown in Table 13.11 were calculated by assuming that all of the bromine is sold at 70 cents per kg, that the total investment is not more than $1.1 million, and that the payout time is 6 years (Cox, 1967).

Minerals recovered from saline waters

Sodium chloride

Minerals are recovered from practically every type of saline water. By far the largest recovery is that of sodium chloride in solar evaporation processes. From the point of view of oilfield brine disposal, where solar evaporation is possible, the cost of disposal is small. The salts recovered, if any, would probably pay for the construction of evaporation pits.

Lithium

Lithium is produced from brines by Foote Mineral Company at Silver Peak, Nevada, and by American Potash and Chemical Corporation at Trona, California. American Potash and Chemical Corporation recovers a coproduct lithium sodium phosphate from Searles Lake, California, brines. However, the largest lithium production is from lithium ore mined in North Carolina

MINERALS RECOVERED FROM SALINE WATERS 393

by Lithium Corporation of America. Domestic production of lithium has not been reported since the mid-l950’s, because individual companies do not want to disclose confidential data. In 1954 about 36,000 metric tons were produced in the United States. The staff of the U.S. Bureau of Mines (1968) reports that both the lithium industry and the government are hampered by restrictions on publishing statistical data on the production and consumption of lithium metal, alloys, and compounds. These restrictions inhibit the determination of requirements, the evaluation of market potentialities, and the planning of future action.

Potassium

Tallmadge et al. (1964) report that the commercial recovery of potassium from brines only has been attempted on a pilot plant scale. Precipitation appears the most promising either by the addition of a selective agent specific to potassium, or by fractional crystallization of saturated brines.

Potassium compounds occur in many rocks and minerals, but the commercial sources are limited to soluble salts in bedded salt deposits and brines. The major deposits of potassium salts in the United States are part of the Permian Salt Basin that underlies parts of Colorado, Kansas, Oklahoma, Texas, and New Mexico, and the Paradox Basin of southwestern Colorado and southeastern Utah. However, commercial beds of potassium minerals have been found only in New Mexico. Commercial operations have been limited to about 140 km2 east of Carlsbad, New Mexico. These deposits were discovered by oil well drillers. Commercial recoveries on a limited scale are made from the brines of Searles Lake, California, and Bonneville Flats, Utah.

Rubidium

The rubidium-producing industry is very small. During 1958 rubidium production in the United States was only about 100 kg annually, and during that year some new technical-grade rubidium compounds were prepared from alkali carbonate residues of lithium operations. As with many other minerals found in oilfield brines, the production of rubidium is not published because it is withheld as confidential company data. However, with current accumulated stocks and a very small consumption, it is doubtful that the recovery of rubidium from brines would be economical even at $935 per kilogram.

Cesium

Cesium, both as a metal and as an industry, is similar to rubidium. The demand for both is small, and the known uses are few. Both cesium and rubidium are obtained commercially from lepidolite, a lithium mineral.


Cesium and rubidium are byproducts of the lithium industry, and both are recovered from the residues of the lithium production process are precipitation from solution. The high concentrations of cesium and rubidium in the residues and the fact that the amount therein greatly exceeds demand virtually preclude their removal from oilfield brines on a competitive basis.

Magnesium

Magnesium comprised one-third of the value which Collins (1966) attributed to the minerals wasted by oilfield brine disposal, and the price used was that of magnesium metal. In the primary.meta1 form, magnesium com- mands its highest price. When magnesium is sold as contained in other compounds, its value is less than 2 cents per kg as compared to 77 cents per kg for primary magnesium. Magnesium and magnesium compounds are produced from the following four raw material sources: (1) sea water; (2) dolomite; (3) ores other than dolomite; and (4) evaporite deposits and lake and well brines. In 1963, well brines, bitterns, and sea water combined with calcined dolomite or lime accounted for more than half of the domestic production of magnesium compounds used as chemicals, filters or bases in many industrial products including basic refractories.

Magnesium and magnesium compounds are produced and recovered by several companies in the United States. The Dow Chemical Company produces magnesium chloride crystals, magnesium chloride fluxes, and magnesium hydroxide from well brines and calcined dolomite at Ludington, Michigan. The Michigan Chemical Company produces precipitated magnesium carbonate, magnesium hydroxide, and magnesium oxide from well brines and calcined dolomite at St. Louis, Missouri. The Dow Chemical Company produces magnesium chloride, caustic-calcined magnesia, and magnesium hydroxide from sea water and oyster shells at Freeport, Texas. Magnesium compounds are recovered from solution by precipitation of magnesium hydroxide. This method is so economical that a large part of the production of magnesium and magnesium compounds in the United States is derived from sea water. The Dow Chemical Company is the major source of primary magnesium and in 1963 it had a capacity at Freeport, Texas, of 50,000 metric tons per year; at Velasco, Texas, the capacity was 34,000 metric tons. In 1963 the U S . production of primary magnesium was 69,000 metric tons.

The Dow process for magnesium recovery from sea water first precipitates magnesium hydroxide. The hydroxide source is calcium hydroxide made from oyster shells. After settling and thickening, a slurry of 17% magnesium hydroxide is attained and neutralized with hydrochloric acid to form a 15% solution of magnesium chloride. After evaporation and dehydration, the resultant 48% magnesium chloride solution is mixed with dried magnesium chloride to form a paste. The paste is dried to granules which consist of 74% magnesium chloride, and the granular material is the feed to electrolytic cells


which produce magnesium metal and chlorine. The chlorine is then converted to hydrochloric acid which is used in the neutralization step. Shreve (1956) lists three economic factors of importance in the precipitation of magnesium hydroxide. They are: (1) the source of the hydroxide; (2) the dewaterirg procedures used for removal of the magnesium hydroxide from the dilute solution; and (3) the purification of precipitates.

The source of the hydroxide is the major economic deterrent factor against the increased use of well brines. Sea water provides the magnesium, and the sea also furnishes the oyster shells for calcium hydroxide production. For well brine feed, dolomite often is employed, and a large source of dolomite must be economically available. Tallmadge et al. (1964) report that waste sodium hydroxide has been tested in Japan, but in most areas, calcium salts are the least expensive sources of the hydroxide. Thus the choice of a raw material must be belanced in cost against plant size and market. While Michigan brines contain four to five times the magnesium concentration of sea water, the reduced size in necessary equipment for processing the brine does not completely overcome the cost of producing and disposing of the brine. This would appear to make oilfield brines more attractive than other subsurface brines if a hydroxide source is available at an equivalent expense.

Tallmadge et al. (1964) report methods for extracting magnesium from brines by methods other than hydroxide precipitation. However, none appear economically attractive when compared to precipitation unless combined with other processes or products. Among those studied are solar evaporation to produce chloride, use of ion-exchange resins with lime and carbon dioxide or waste liquor from the ammonia-soda process, and elec- trolysis.

Calcium

Calcium production from brines does not appear economical when compared to the source of the world’s calcium consumption. The largest amount of calcium is produced by the mining of mineral deposits (notably gypsum) found extensively throughout the world. Proposals for methods to recover calcium from brines have been made and are under study, but to compete commercially beyond extremely small, local demands, considerable research is needed.

Mixed salts

Mixed salts are precipitated by evaporation of sea water and brines, producing crude separations. The costs of these separations are low compared to those of highly purified compounds or metals. There are several drawbacks which prevent greater use of this type of recovery. The product does not command a high price, the plant must be at the brine sburce, there must be solar evaporation conditions, and a local market must exist for the majority


of the mixed salts. Uses which have been suggested include heat-treating salt baths in the steel industry, raw materials for refractory or catalyst manufacture, and fertilizer components.

Precipitation other than by solar evaporation is accomplished by cooling or adding chemical agents. Simple cooling may be all that is necessary for more concentrated brines, but fractional crystallization is necessary for dilute brines such as sea water. Again local markets dictate whether cooling or freezing processes will yield the correct products for a particular area. Adding chemicals to precipitate a specific product is the most fruitful of the nonsolar evaporation processes. Most of the processes have been aimed at the production of fertilizer. Potassium and magnesium are the minerals in sea water that are most valuable for use in fertilizers. Salutsky and Dunseth (1962) report that metal ammonium phosphates (MAP) containing magnesium, calcium, iron, manganese, copper, and many other trace metals comprise a high-analysis fertilizer.

The production of metal ammonium phosphates (MAP) in the United States was started by W.R. Grace and Company in 1960 on a semicom- mercial scale. The method which Grace used to produce MAP was not disclosed until 1962 after it was patented. The fertilizers are nonburning, long-lasting sources of nitrogen, phosphorus, and various trace metals. Be- cause of their low solubility, MAP’s will not cause salt injury to seeds or plants.

In magnesium ammonium phosphate, practically all of the P z 0 5 is available, and the size of the MAP granules applied to plants determines how long the nutrients will be available. Thus, availability of nutrients can be controlled by granulation and, since growing time varies from crop to crop, MAP’S can be tailored to a specific crop (Anonymous, 1961). Therefore, fewer applications are necessary with MAP’S than with fertilizers of higher solubility and high nitrification rates. W.R. Grace and Company developed the MAP process for two purposes.

First, it is useful to remove scale-forming materials from sea water before desalination. Secondly, it would yield the valuable, high-analysis fertilizer, magnesium ammonium phosphate. In 1962, W.R. Grace and Company (Anonymous, 1962) reported that the process was ready for the pilot plant. The process is based on phosphate precipitation. To descale sea water and produce high-analysis fertilizer at the same time, wet-process phosphoric acid and anhydrous ammonia are added continuously to raw sea water. This precipitates the scale-forming elements - calcium, magnesium, iron, and other metals - as metal ammonium phosphates and other phosphates. The precipitated solids are removed by settling, and the descaled sea water is pumped to the saline water conversion plant. The descaled water holds only 1% of the original magnesium and 5% of the original calcium. The slurry of MAP’s is dewatered t o about 35--40% solids by continuous centrifuges and thin it is heated to 90°C. This converts MAP hexahydrate to monohydrate. The slurry is filtered, washed, mixed with recycle fines, and granulated. Fig.


I I

Set t l ing ond Descoled sea wotek thickeninq

1

1

t Dehydration

Filtrotion ond wos hing

Wash

Gronulotion

Drying Crushing

I k 1

Undersize Oversize Screeninq I

Finished product to storoge

Fig. 13.1. Diagramatic flowsheet for producing descaled sea water and fertilizer.

13.1 shows a process flowsheet for producing descaled sea water and fertilizer.

Several questions surround the economics of the process. For a plant descaling 3,800 m3 of sea water per day (output: about 10,000 metric tons per year of fertilizer), the fertilizer would have to command a price higher than that of conventional farm fertilizers. The estimate assumes 1962 market prices for raw materials (phosphoric acid and ammonia) and does not take credit for the increased value of the descaled sea water. The cost is just about the same for Grace’s present method of producing MAP’S. Because of its premium quality, MAP can go to the market as a specialty product.

In the phosphoric acid-ammonia process, 2 moles of ammonia per mole of MAP are lost. to ammonium chloride in neutralizing the phosphoric acid. Using disodium phosphate in place of the acid loses no ammonia, and using monosodium phosphate only loses ‘1 mole of ammonia. If a cheap method were developed for producing the sodium phosphates, ammonia waste would be reduced. The simplest method for producing sodium phosphates involves


the neutralization of phosphoric acid with either dilute sodium hydroxide or soda ash. Caustic soda and chlorine can both be produced from sodium chloride brines.

Chlorine

Chlorine is the most abundant element in oilfield brines, and the removal of all chlorides from oilfield brines would virtually desalt the brine. How- ever, present commercial methods for the extraction of chlorine from brines requires evaporation to acquire a saturated brine. Solar evaporation first produces the saturated brine, then electrolytic processes are employed to generate chlorine gas. The largest production of chlorides from brines is from solar evaporation of sea water and salt lake brines. Many oilfield brines are very close to saturation with sodium chloride at surface temperatures. Sub- surface brines are employed as raw materials for chlorine production, but the amount produced is not significant when compared to surface brine production.

Shreve (1956) describes the methods still in use for chlorine production. Caustic soda and chlorine are coproducts in the electrolytic process. Purifica- tion of the brine is necessary to produce a purer caustic soda and lessen clogging of the cell diaphragm with consequent increased voltage demand. Calcium, iron, magnesium, and sulfate must be removed. The higher concentrations of magnesium and calcium in oilfield brines cause greater expense in brine purification unless the removed compounds can be sold. Hydrogen, caustic soda, and chlorine are the products of this type of recovery. The hydrogen presents a disposal problem and is frequently made into other compounds such as hydrochloric acid or ammonia or is employed for hydrogenation of organic compounds.

Iodine and bromine

Iodine and bromine are two minerals which have closely related processes for recovery from brines. Both are displaced from ions to elements in solution by chlorination and then stripped from solution by air. When bromine is liberated by chlorination, iodine is oxidized to the iodate ion. After bromine is stripped from solution, the iodate ion can be reduced to free iodine by treatment with ferrous chloride and then stripped by air as was the bromine.

The greater portion of bromine production in the United States is from well brines. Slightly over 50% of the domestic production is from well brines, 35% comes from sea water, and the remainder comes from oil well brines and saline lake brines. Substantial expansion recently completed by two producers of bromine from brines should give the industry sufficient capacity for several years t o supply the expected increase in markets (Miller, 1965). The 2-million-kilogram-per-year plant designed for oilfield brines in Arkansas by Michigan Chemical represented 50% of the domestic production


at that time. In 1963 the domestic production of bromine was about 12 million kg.

The recovery of bromine from brines and sea water is accomplished by displacement of the bromide ion with chlorine. The resulting free bromine dissolved in water is then stripped from the solution with air and recovered. A large number of modifications to the basic process (developed by the Dow Chemical Company) have been proposed and patented from time to time. Tallmadge et al. (1964) report that studies are being carried out on the effect of pH, temperature, organic impurities, chlorine concentration, and foreign ion concentration on the displacement reaction between the bromide ion and chlorine gas. The use of chlorine water rather than gas for the displacement step has been suggested to reduce the adverse effects of magnesium and calcium interference where more concentrated brines are used. Activated carbon with adsorbed chlorine also has been proposed as a means of carrying out the displacement step.

Iodine production in the United States uses oilfield brines and sub-surface brines exclusively. Dow Chemical is the sole domestic producer of crude iodine. Dow extracts iodine from oilfield brines in California and from deep- well brines in Michigan. Roughly 1.1 million kg of crude iodine were imported from Chile in 1963 and about 0.5 million kg were imported from Japan. Japanese production of iodine is almost exclusively from deepwell brines, while Chilean production is from nitrate deposits containing the minerals lautarite and dietzite. Miller (1965) reports that Chilean reserves are in excess of 1 billion tons as a byproduct of the nitrate minerals industry. It was price cuts by Chile that forced all domestic producers except Dow out of iodine production; however, the recent nationalization of the Chilean mines has changed the picture and pushed the price of iodine to about $5.06 per kg.

Multiproduct production

Tallmadge et al. (1964) report that it is very probable that the most economic system for removal of minerals from sea water may involve two or more recovery steps in some integrated fashion. Only a few multiproduct processes are operated on a commercial scale. The Dow plant in Midland, Michigan, is such a plant. The first step in studying multiproduct processes is t o determine how much of each product can be sold. The second step is to determine the engineering design and production costs for such a plant.

Angino (1967) has pointed out that several processes exist that can be set up to recover elements from petroleum-associated waters. These existent methods and new methods should be utilized and developed to conserve the natural resources dissolved in brines and to aid in the abatement of soil and fresh water pollution. The recovery methods used may include desalination (Christensen et al., 1967), ion exchange (Klein et a1.,'1968), and ion exchange plus other methods (George et al., 1967; Waters and Salutsky, 1968).


Fig. 13.2. How gas, oil, and brine are separated after production from subsurface strata.

Fig. 13.2 illustrates a wellhead through which gas, oil, and water are produced from a subsurface formation. Often they are produced as a mixture and it is necessary to separate them in a tank such as that illustrated and sometimes referred to as a gunbarrel. In this tank the water or brine will settle to the bottom with the oil interface forming over the brine, and the gas will rise to the top. The gas is drawn off the top, the oil is pumped off the top of the water and stored in an oil tank, and the water is siphoned from the bottom into a skimming tank for further oil-water separation. The water is siphoned from the bottom of the skimming tank into a settling pond where additional oil-water separation occurs. The brine or water could be pumped from the settling pond to a chemical plant for recovery of valuable elements or to an injection well.

Fig. 13.3 illustrates a possible scheme for recovery of some elements plus fresh water from the brine. For example, the raw brine could be concentrated by a desalination process which would also yield fresh water. Sulfate then could be taken from the concentrated brine and used to produce sulfur or sulfur compounds. Next, iodine could be recovered, then bromine, followed by calcium, sodium chloride, and magnesium as suggested in the figure. The remaining sludge could be dried and disposed of as a solid or it could be recycled for additional recovery of elements.

FRESH-WATER PRODUCTION 401

RAW B R I N E

1 DESALINATION I P R O C E S S I-* PRODUCT

F R E S H WATER

CONCENTRATED B R I N E

SULFATE I P R E C I P I T A T I O N I-* PRODUCT SULFUR AND SULFUR COMPOUNDS

I O D I N E I RECOVERY

PRODUCT I O D I N E AND I O D I N E COMPOUNDS

t. I BROHINE RECOVERY

PRODUCT BROMINE AND BROMINE COMPOUNDS

SODIUM CHLORIDE RECOVERY

PRODUCT CALCIUM coMp0uM)s

PRODUCT SODIUM CHLORIDE

OR SODA ASH

AND CHLORINE

---l--- + SLUDGE CONTAINING CALCIUM, STRONTIUM, BARIUM, MAGNESIUM AND OTHER ELEMENT COHPOUNDS. THE SLUDGE CAN BE D I S P O S E D A S A S O L I D OR RECYCLED FOR CHEMICAL RECOVERY

PRODUCT MAGNESIUM AND MAGNESIUM COMPOUNDS

Fig. 13.3. Diagramatic flowsheet for producing fresh water and valuable elements from brines.

Fresh-water production

Dwindling fresh water supplies and polluted supplies have increased research on how to best obtain fresh water from saline water. Several plants throughout the world produce fresh water from sea water. The price of water for municipal purposes is a highly specific thing. The availability of fresh water and costs of obtaining it vary from place to place. Conventional


water supplies range in cost from a few dollars per 1,000 m3 to over $260 per 1,000 m3.

The average cost of conventional water supplies in the United States was $100 per 1,000 m3 in 1952. This was chosen as the goal for saline water conversion costs. Several authors have estimated ultimate costs of saline water conversion based on thermodynamic considerations. Dodge and Eshaya (1960) have examined the minimum expected costs for saline water conversion. Prior to their calculations, other authors reported sea water conversion costs to be ultimately less than $79 per 1,000 m3. Dodge and Eshaya expanded earlier work to look at departure from isothermal operation, finite product recovery, differential as opposed to single stage operation, and salt concentration in the feed. They found that $90 dollars per 1,000 m3 is the smallest cost for desalination of sea water.

Consider the case for converting brackish water with 5,000 ppm sodium chloride. For converting 50% of the feed to fresh water, 187 kWhr per 1,000 m3 was the power requirement. For 35,000 pprn sea-water conversion, the power requirement was 1,530 kWhr per 1,000 m3. Both calculations were for 50% recovery of fresh water from feed, where the average power costs used in determining conversion costs are 1.5 cents per kWhr. At this rate, the difference in power costs for sea water over brackish water is $20 dollars per 1,000 m3.

Oilfield brines contain up to seven times the concentrations of dissolved salts compared with sea water. Would the power be seven times again as expensive per 1,000 m3? At over $132 for power and $92 for other costs, the cost of obtaining fresh water from oilfield brines probably would be prohibitive when consideration is given to the other sources for feed to a conversion plant in the same area. An additional factor is that most oilfield brines with their high concentrations are nearly saturated. Removing 50% of the water would in essence leave a precipitated salt. Therefore, since no conversion processes under study deal with saturated brine effluents, it is not technologically feasible to completely desalt oilfield brines at this time.

Preliminary economic evaluation

The “brine refinery” concept (Collins, 1966) yields a processing plant the size of a large petroleum refinery. The market prices used were for the recovery and sale of the pure elements. The $3 billion in sales from 0.95 billion m3 of brine is the highest sales income possible that would result from recovering and selling the minerals in the form that gives the highest unit price.

Consider what is probably the best case of a “brine refinery”, a system that would gather 22 million m3 per year. The cost of gathering and disposing of this brine would be approximately 9.4 cents per m3. The question is whether or not minerals could be sold at a profit such that the disposal expense would be negated or a profit made. First, the minerals to be

PRELIMINARY ECONOMIC EVALUATION 403

sold must be determined. At 7 ppm lithium, 163 metric tons per year could be produced. This is a large fraction of present consumption and probably would depress the sale price. The same holds true for most other elements of such a refinery.

The assumptions lead to a brine refinery that would process 22 million m3 per year and sell $35 million of minerals. Assuming a 15% return on investment and a profit of 15% of sales, the plant would require $35 million- investment and yield 23.6 cents per m3 of brine processed. The original disposal operation without mineral recovery was such that only $6 million was invested. The “brine refinery” would turn brine disposal into a profit. But the new investment is six times that for disposal only. I t is doubtful that any large oil producer would be interested in a 15% return on investment, and small ones would never gather the cash.

Would a chemical company be interested in such an operation since they operate at about a 15% return? Companies that currently remove minerals from brines use brines that are more concentrated in the minerals desired. It is doubtful that a process could combine several less economical operations into a more economical one, and this would probably be true even if the brine was supplied to a chemical company free of charge. Only in the special case where an oilfield brine contained a concentration very near to a brine that would be the most economical for separation would the oilfield brine be a best alternate. Therefore, a tax incentive for pollution abatement or some other economic incentive such as price increase of recovered chemicals is necessary.

Other economic factors

Table 13.111 illustrates the approximate amount of valuable chemicals per 1 million kg of brine produced from a given depth should contain before it can be considered of economic value at present market conditions. The values shown in Table 13.111 should allow a profit if conventional or better recovery operations are utilized. The marketed end product will influence the selection of the recovery operation as well as the delivered price. The

TABLE 13.111

Dollar value of dissolved chemicals a brine should contain per million kg of brine produced from a given depth

Value of dissolved chemicals Depth of well (m)

$ 462 760 $ 968 2,130 $ 1,430 3,050


TABLE 13.W

Amount of element necessary in 1 million kg of brine to produce a chemical worth $ 550 at the market

Element in the brine

Sodium Potassium Lithium Magnesium Calcium Strontium Boron Bromide Iodide Sulfur

Concentration of element (ppm/106 kg of brine)

50,000 14,000

170 8,000

11,000 4,000 1,400 1,700

250 5,300

Market product

sodium chloride potassium chloride lithium chloride magnesium chloride strontium chloride strontium chloride sodium borate bromine iodine sodium sulfate

price information used to make the approximations was taken from the U.S. Bureau of Mines (1968).

Factors that must be considered in evaluating a saline water as an economic ore are the cost of bringing it to the factory, the cost of the recovery process, and the cost of transporting the recovered products to market. Assuming that a brine is produced only for the purpose of recovering its dissolved chemicals, a prime factor is the cost of pumping the brine. I t will cost less to produce the brine from a shallow well than from a deep well. Therefore, neglecting other factors, a brine must contain a certain amount of recoverable chemicals before it can be considered economically valuable, and the farther it must be pumped, the more chemicals it must contain.

Today the possibility of recovering elements from brines that are pumped to the surface is increasingly important because the brines present a pollution hazard if their disposal is improper. Consider the fact that 1 m3 of brine containing 100,000 ppm of chloride is capable of polluting 400 m3 of fresh water so that they are unfit for human consumption.

Table 13.IV illustrates the value that chemicals recovered from brines have at the market; however, because the market fluctuates, these values are approximate. The column on the left indicates the elements that are found in petroleum-associated brines, and the second column indicates the concentration that a given brine must contain before it can be used to produce a given amount of chemical. For example, a brine containing 50,000 ppm of sodium will contain sufficient sodium in 1 million kg of brine to produce sodium chloride worth about $550.

The data in Table 13.IV indicate that some petroleum-associated waters contain sufficient sodium to establish them as economic for the production of sodium chloride. This is not necessarily true, because factors such as


market demand, ease of recovery, and proximity to market may be discour- aging in certain geographic areas. Such factors must be fully considered before startup of a chemical from brine recovery operation. One important goal that should not be discounted nor overlooked is developing a means of ultimately disposing of these brines so that they are not a pollution hazard. Coupling of this goal with the fact that many of these brines contain economic concentrations of several elements should make such recovery operations more attractive. Additionally, several important chemicals can be produced from these elements instead of those shown in the market product column in Table 13.IV. An example is soda ash, which is a basic chemical in many manufacturing processes. Furthermore, the figures shown in Table 13.111 are applicable only if the brine is produced solely for the recovery of its dissolved chemicals. If the brines are pooled from several petroleum production operations, the cost of pumping the brine becomes less, and the necessary amounts of chemicals dissolved in 454,000 kg of brine become less.

At the present time, many petroleum-associated brines are injected into subsurface strata, and it is assumed that they are thus disposed of permanently (Crouch, 1964). However, this method of disposal appears subject to question, because in some instances, fresh waters apparently have been polluted by disposal of brines. Subsurface disposal operations are suspected in certain areas as possibly contributing to increased earthquakes and ground tremors (Evans, 1966; Bardwell, 1966).

The storage of brines in earthen pits is known to cause pollution of nearby soils and streams. Such ponds which have been abandoned for 10 years still contribute to soil pollution (Bryson et al., 1966). Sound conservation should favor the recovery of valuable elements from brines, and with proper planning, the recovery processes should aid in the ultimate disposal of unwanted brines. Conservation of this type not only will develop new resources, but will benefit the oil producer and the national economy and will aid in abating pollution of soils, potable waters, and streams.

Work necessary for an exact preliminary evaluation

Aries (1954) spells out the marketing research techniques employed in the chemical industry. There are ways to quickly determine where a market for a product is. Usually these places are currently served by some producer or another. If the competition is located far from the market, then an evaluation of a closer area source is readily made. To find product users, the following methods and approaches are utilized: advertising, company analysis, product analysis, industry analysis, use analysis, and other miscel- laneous methods. If new markets must be found, the following types of work are utilized: personal interview, questionnaire, trade analysis, company records, and published sources. Before an economic analysis can be made for a given area, probably several man-months of the listed methods would be


required. The product of this type of market study would be a list of elements and compounds that could be sold from a given place. The quantities and prices obtgined would then allow an economic calculation of the production costs.

With the quantities, prices, and production costs in hand, it is still not a simple matter to determine what type of plant to operate. Regardless of whom the investor might be, he will want to know what return on investment he will get, what risk is involved, and what payout period exists for the project. Depending on the investor, he may want to limit the plant size by the amount of money he can invest. This does not simply scale down the plant. It may rearrange various ratios of certain products produced in order to give the investor the combination of profits, return on investment, risk, and actual size of investment that he desires.

Locations o f valuable brines

Table 13.V lists the approximate geographic locations where subsurface saline waters containing valuable elements are found. The numbers in the left column of the table correspond to the numbered arrow locations on Fig. 13.4. The second column in the Table indicates the age of the geologic strata from which the waters were obtained. These waters are in or near oil- productive sedimentary basins. Concentrations of various elements present in the waters are given in columns 3 through 11 of Table 13.V. These concentrations are representative of one or more subsurface waters from each location; however, the concentrations should not be considered typical of all subsurface waters in an area or stratum. For example, some waters near location 1 from Mississippian age strata may contain 1,000 ppm of bromine, while other waters 80 km away, but from the same geologic strata, may contain 3,600 ppm of bromine. The elemental composition of ocean water is consistent; the composition of subsurface saline waters is inconsistent.

Fig. 13.5 is a map showing some areas in the United States where brines containing high concentrations of sodium are found. The solid circles on the figure represent areas where brines containing 75,000-80,000 mg/l of sodium can be found, the open circle represents brines containing 80,000-95,000 mg/l, and the triangle represents brines containing more than 95,000 mg/l.

Fig. 13.6 is a map showing some areas in the United States where brines containing high concentrations of calcium are found. On this figure the solid circle represents brines containing 20,000-30,000 mg/l of calcium, the open circle 30,000-50,000 mg/l, and the triangle more than 50,000 mg/l.

Fig. 13.7 is a map illustrating some of the areas in the United States where high concentrations of magnesium in brines are found. On this figure the solid circle indicates brines containing 5,000-10,000 mg/l of magnesium, the open circle 10,000-30,000 mg/l, and the triangle more than 30,000 mg/l.

PR

EL

IMIN

AR

Y E

CO

NO

MIC

EV

AL

UA

TIO

N

ll

c

TABLE 13.V

Geographic location, geologic age of saline water-bearing strata, and concentration of some of the elements found in the brine's

Location* Age of subsurface Concentration (ppm)

strata lithium sodium potassium magnesium calcium strontium boron sulfur chloride bromide iodide

c 1 2 3 4 5 6 7 8 9

10 11 12 13

Mississippian Permian Permian Devonian Cambro-Ordovician Pennsylvanian Jurassic Miocene Devonian Devonian Mississippian Devonian Devonian

10 30 40

100 ND

5 100 1 5 25 60

10 90

*

28,000 100

55,000 66,000

8,000 51,000 68,000 73,000 74,000 14,000 16,000 58,000 72,000

40 1,000 2,500

10,000 ND

100 4,000

600 700

8,000

3,000 9,000

2,000

10,000 25,000 9,000 5,000

11,000 600

5,000 6,000 5,000

15,000 11,000

5,000 4,000

60,000 100

30,000 40,000 20,000 10,000 30,000 30,000 30,000 70,000 14,000

35,000 20,000

3,000 5

ND 2.000 ND 1,000 ND ND

900 1,500

800 1,000 ND

40 ND 90 ND ND 10 ND 60 ND

300 ND ND ND

400

400 100 350

30 60 60

600 400

20 60

4

20,000 179,000

166,000 198,000

79,000 98,000

175,000 ia4,ooo 182,000 200,000 90,000

143,000 186,000

9,000 3,200 ND 1,200

700 ND

600 5,000

200 2,000 2,500 1,500 1,300 1,800

40

25 20

ND

ND 1,000

10 20 40 40 40 30 20

* See arrows in Fig. 13.4. ND = not determined.


Fig. 13.5. Approximate geographic locations of brines containing high concentrations of sodium.

Fig. 13.6. Approximate geographic locations of brines containing high concentrations of calcium.


LEGEND ' 5,000- 10,000 mg/l 0 10,000-30,000 A > 30,000

Fig. 13.7. Approximate geographic locations of brines containing high concentrations of magnesium.

Fig. 13.8. Approximate geographic locations of brines containing high concentrations of bromine.

DISPOSAL BRINES 41 1

Fig. 13.8 is a map illustrating some of the areas in the United States where high concentrations of bromide in brines are located. On this figure the solid circle represents brines containing 1,500-2,000 mg/l of bromide, the open circle 2,000-3,000 mg/l, and the triangle more than 3,000 mg/l.

Disposal brines

In an attempt to acquire as much information as possible about salt water disposal facilities in the various States, the literature was surveyed and State and Federal agencies and oil companies were contacted. The acquisition of a true compilation of the exact number of disposal facilities, disposal wells, and total number of barrels of brine injected was an impossible task without a large surveillance force; however, the data in Table 13.VI are reasonably representative.

To determine the value of the minerals in the brines flowing into these disposal systems, samples were obtained from 40 systems. The samples were analyzed for concentrations of lithium, sodium, potassium, magnesium, calcium, boron, ammonium, sulfate, bicarbonate, chloride, bromide, and iodide.

Table 13.VII lists the state, county, subsurface formation, and dissolved solids (DS) from which the brine samples were obtained. The specific gravity of each sample plus the ionic values determined in the laboratory also are given in Table 13.VII. Sample 1 is sea water, sample 2 is a brine that contains a high concentration of iodide, and sample 3 is a brine from which bromine currently is extracted.

Worth and value estimates

The estimates of the value of a brine are related to the market and the recovery process. The market is dependent upon demand; however, in the following estimates the demand was not considered. According to Chris- tensen et al. (1967):

Brine value = market value of products - operating costs exclusive of brines value - fixed costs - profit

The maximum value of a brine can be found by letting the “return on investment” equal zero, and the brine worth is:

Brine worth = brine value + profit = market value of products - operating costs - fixed costs

The brine value is less than the brine worth by the amount of profit expected. Although the information necessary to obtahi an accurate calcula-

TABLE 13.VI

States where oilfield brines are disposed, total number of subsurface salt water disposal wells (SWDW) and largest disposal facilities

State Total number of Largest SWDW SWDW SWDW Remarks SWDW ( m3 /day) 2 4700 m3 /day 2 1590 m3 /day

Ah. Alaska Ariz. Ark. Calif. Colo. Fla. Ill. Ind. Kans. KY. La. Mich. Miss. Mont. Nebr. Nev. N. M. N. Y. N. D. Ohio Okla. Pa. S. D. Texas

Utah W.Va. wyo.

14* no data

4 421 216

25* 5

no data 325

3,150

1,304 52 2 370 20 0

3

300

62 28*

4,900

60**

-

-

- -

7,173**

3** 95** 19*

2,385

191 9,221

25,120 2,544

954

159 3,180

111

318 1,113

239 135

2,703

31 8 318

-

-

- -

0 5

0

0

0

0 0 0 0 0 0 0 0 0

0 0

143 0 159 0

0 14

0

0 2** 0

0 0 0 0 0 4 0 0 0

0 0

0 0

+ bromine plant effluent

average SWDW is 21 7 m3 /day average SWDW is 32 m3 /day

only 7 producing wells for State

2 2

most of this is by ponding P

ponding used 2 _. P U 8

number of SWDW permitted from 1950-1971

5 2 -- -

* Salt water disposal Systems that may have more than one salt water disposal well per system. * * Approximate.

TABLE 13.VII

Analyses of some disposal brines, seawater, and a proven economic brine*

Brine State County Formation Sp. gr. Constituents (mg/l)

Na Ca Mg K Li B NH4 CI Br I SO4 HCOi DS

1 Seawater 2 Okla. 3 Ark. 4 Kans 5 Kans. 6 Kans. 7 Kans. 8 Kans 9 Kans.

10 Ark. 11 Ark. 12 Ark. 13 Ark. 14 Ark. 15 Ark. 16 Ark. 17 Ark. 18 N.M. 19 N.M. 20 N.M. 21 N.M. 22 N.M. 23 Texas 24 Texas 25 Texas 26 Texas 27 Texas 28 Texas 29 Texas 30 Texas 31 Ala. 32 Ala. 33 Ala. 34 La. 35 La. 36 La. 37 Calif. 38 Calif. 39 Ariz. 40 Okla. 41 Okla. 42 Miss.

- - Kingfisher Oswego Columbia Smackover Pawnee Arbuckle Barton Arbuckle Butler Hunton Ellis Arbuckle Pratt LKC-Arb Barton LKC-Arb Palm Graves Ouachita L. Graves Ouachita L. Graves Union Smackover Union Smackover Union Smackover Union Smackover Columbia Smackover Lea San Andres Lea Devonian Lea Devonian Lea Penn Lea Devonian Gaines Devonian Cherokee Woodbine Rusk Petit Cherokee Woodbine Wood Woodbine Wood SubClarkville Wood Paluxey Hopkins Paluxey Mobile Rodessa Mobile Rodessa Mobile Rodessa LaSalle Wilcox Calcasieu - Cameron Miocene Fresno - Kern Kern Apache L.Hermosa Woods Hunton Oklahoma Wilcox Wayne Wilcox

1.025 10,500 1.124 56,250 1.230 74,000 1.036 14,430 1.025 9,850 1.012 5,990 1.034 16,800 1.020 9,400 1.050 23,300 1.046 19.900 1.048 21,100 1.046 20,500 1.192 64,200 1.192 63,900 1.199 63,300 1.191 64,500 1.162 54,500 1.020 9,150 1.036 18.200

400 1,350 8,300 260

44,440 4,340 2,480 700 1,450 490

760 260 2,630 690 1,200 320 4,300 1,300 3,500 900 3,800 1,030 3,800 930

34,500 3,950 38,500 3,850 36,300 4,040 37,300 3,895 27,600 1,315

1,500 500 1.850 500

1.028 i3:goo i$oo 340 1.043 21,600 2,840 770 1.039 19,350 2,400 410 1.025 12,380 1,970 365 1.056 30,000 8,650 345 1.153 58,700 10,320 1,130 1.070 36.200 3.300 690 1.065 34;OOO 10;530 110 1.037 21,200 840 205 1.076 34,600 6,750 970 1.010 5,640 630 40 1.031 12,180 5,630 480 1.039 14,500 6.750 550 1.052 18,400 8,860 680 1.064 35,600 1,650 600 1.084 44,800 3,960 230 1.076 42.600 2,335 135 1.026 13,600 1,855 780 1.000 210 70 5 1.012 7,760 1,520 50 1.123 57,600 10,120 1,640 1.151 68,750 13,270 2,460 1.003 2,880 50 10

380 180

4,410 260

75 70

190 105 160 200 160 140

1,845 1,945 1,370

3,500 245 370

20 150 560 400 105 790 860 550 360 250

50 400 320 460 31 0 300 200 200

15 20

1.000 980

10

2,000

0.17 4.6 14 18

370 20

3 3

10 5 5 5 5 5

160 180 170 165 230

5 10

2 10 10

5 2

35 2 5 2

10 2 5

10 10

5 5 5 1 1 1

10 10 0

200 10 10 0 5 3

12 10 16 12

140 150 140 140 160

10 0 0

40 5 5

40 10 0 5

10 20 10 0

12 30 25 10 12

5 0 0

40 0 0

-

300

20 30

0 0 0

30 45 40 40

320 260 260 100

50 70 60 0

90 0

100 50 50 40 10 25 40 0

90 80 90

250 25 12 0 0

12 260 140

0

-

19.000 98,300

202,050 32,850 19,460 10,380 30,500 1 7 , Y O O 45,100 42,200 43,100 42,400

178,100

197,600 182,600 150,000

17,800 32,650 24,300 42,600 37,240 22,400 49,100

135,500 61,300 57,100 31,800 68,700

8,350 29,400 37,000 47,540 62,500 74,600 68,900 28,870

330 11,600

115,500 138,600

3,861

180,800

65 1,500 5,725

60 50 20 50 50

150 500 400 600

2,450 2,340 4,800 3,390 3,500

50 30 25

210 40 40

270 210 400 370 180 100

70 40 50 30 70 25 30 15

2 20

326 540

3

0.06 1,300

15 10

5 2 2 3

10 10 10 10

5 5 5

10 5 3 0 0 5 2 0

30 30 35 30 35 25

5 10 10 12 20 20 20 20 0

12 150

10 0

3,468 180 220

2,000 2,350 1,400 2,880 1,100 2,270

0 0 0

650 440 350 255 190

2,000 2,260 2,000

360 1,630

610 240 270 30 90

0 420 120 710 300 400

0 0 0 0

40 0

350 520 410

140 50 95

450 350

60 315 250 260 170 160 60

100 190 200 600 200

1,000 500 600 380 490 590 400

0 300 400 450 300 500 190 160 140 380 140 300 240 130 170 120

85 255

35,308 166,652 335,865

53,290 34,123 18,855 54,072 30,332 76,895 67,439 69,819

286,420 292,560 345,235 295,955 241,250

32,329 56,428 42,687 69,055 62,137 38,865 89,232

207,045 103.1 57 103,200

55,107 11 2.185 15,417 49,135 59,742 76,652

101,410 124,115 114,549 45,616

803 21,165

187,096 225,365

7,479

68,495

c

* Sp. gr. =specific gravity; DS = dissolved solids,


TABLE 13.VIII

Formulas for calculating maximum worth, brine worth, and brine value ____

Maximum worth = ( X i ) (market value of compound i)*

Brine worth = M.W. - (market cost + fixed charges)

Assume: brine worth = M . W . 4 . 7 5 (M.W.) Also assume: brine value = M.W. x 0.1

* X = amount of compound, and i = number of compounds.

tion of brine value can be gained only by detailed market research, an estimate can be made by assuming which products will be recovered from the brine, calculating their market values, and relating the total values (or a single product value) back to the brine value after assuming that the brine worth equals a fraction of the total value.

Table 13.VIII presents formulas for calculating the maximum worth, brine worth, and brine value. In this study, the maximum worth was calculated

TABLE 13.IX

Value of assumed recoverable compounds used in calculating brine value

Cation Compound

Na NaCl (rock) Mg MgClz (99%)

MgS04 Li LiCl (technical) Sr SrC13 K KCl Ba BaClz (technical) Ca CaClz NH4 NH4 C1

Anion Compound

Cation ($/ton*)

18.09 259.38 346.99

11,515.10 518.89

58.88 284.29 120.64 412.26

Compound ($/ton)

7.11 66.14 69.22

1,87 3.91 286.60

30.86 187.39

43.54 138.89

Anion ($/ton) Compound ($/ton)

B NazB40, * lOHzO c1 NaCl (rock) so4 NazS04 (salt cake)

MgS04 Br NaBr I NaI (U.S.P.) HC03 NaHC03 (303 CaC03

519.72 55.39 11.72 7.11 45.64 30.86 86.75 69.22

1,135.69 881.84 9,114.61 7,716.10

81.24 59.03 26.20 15.71

* Metric tons.

WORTH AND VALUE ESTIMATES 41 5

TABLE 13.X

Value of brine constituents*

Assumed brine composition (kg/rn3 of brine):

Calcium Magnesium Potassium Lithium Boron Sodium Bromide Iodide Sulfate Bicarbonate

Assumed products (kg):

NaCl CaCl2 MgCl2 KCl LiCl Na2 B4 0 7 10H2 0 NaBr NaI MgS04 NaHCO

23.36 2.25 5.27 0.34 0.31

57.65 1.95 0.04 0.11

145.60

146.01 64.73

8.75 10.06

2.05 2.97 2.52 0.04 0.13 0.10

at $ 7.ll/ton** = 1.04 at $ 43.54lton = 2.82 a t $ 66.14/ton = 0.58 at $ 30.86/ton = 0.31 a t $ 1,873.91/ton = 3.84 at $ 55.39lton = 0.16 at $ 881.841ton = 2.22 at $ 7,716.10/ton = 0.31 at $ 69.221ton = 0.01 at $ 59.031ton = 0.01

Maximum worth = $ 11.30

Brine worth = $ 11.30-314 (11.30) = $ 2.82/m3

Brine value = $ 11.30 x 0.1 = $ 1.13

* Assuming: 75% of market cost is operating and fixed charges. ** Metric tons.

from the market value of compounds that can be derived from the ions found in the brine. This is not necessarily the mdimum worth because the bnnes contain some ions other than those determined. For example, the brines probably contain strontium, barium, rubidium, manganese, etc.

Table 13.IX gives the values of chemicals (Anonymous, 1971; U.S. Bureau of Mines, 1969) that were used to calculate the brine worth of a sample, as shown in Table 13.X. Note that the brine worth in Table 13.X depends upon the products that are assumed to be recovered, and that 75% of the market cost is operating and fixed charges.

Table 13.XI illustrates the values that were found for brine worth and brine value for each of the brines collected for the study. Also shown in Table 13.XI is a ratio of brine value for a commercial brine (brine 3) over the disposal brine. Only brines 2, 13, 14, 15,16, and 17 hadratios of less than 2,


TABLE 13.XI

Brine worth, brine value, and ratio commercial brine value/disposal brine value

Brine Brine worth ($ /m3)

1 2 3 4 5 6 7 8 9

10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42

0.19 3.69 3.86 0.28 0.17 0.10 0.28 0.14 0.39 0.41 0.41 0.82 2.38 2.50 2.99 2.61 2.48 0.18 0.22 0.16 0.33 0.25 0.19 0.52 1.11 0.48 0.64 0.26 0.51 0.10 0.32 0.37 0.53 0.34 0.38 0.33 0.23 0.01 0.17 1.06 0.96 0.02

Brine value

0.08 1.45 1.55 0.P1 0.07 0.04 0.12 0.06 0.16 0.17 0.17 0.33 0.95 1.00 1.19 1.04 0.99 0.07 0.09 0.07 0.13 0.10 0.08 0.21 0.33 0.19 0.25 0.11 0.05 0.04 0.13 0.15 0.21 0.14 0.15 0.13 0.09 0.01 0.07 0.42 0.39 0.01

($/m3) ~ _ _ ~ _ _ ~

Ratio State

19.38 1.07 1.00

14.09 22.14 38.75 12.92 25.83 9.69 9.12 9.12 4.70 1.63 1.55 1.30 1.49 1.57

22.14

Sea water Okla. Ark. Kans. Kans. Kans. Kans. Kans. Kans. Ark. Ark. Ark. Ark. Ark. Ark. Ark. Ark. N.M.

17.22 22.14 11.92 15.50 19.37

7.38 4.70 8.16 6.20

14.09 31.00 38.75 11.92 10.33

7.38 11.07 10.33 11.92 17.22

155.00 22.14

3.69 3.97

155.00

N.M. N.M. N.M. N.M. Texas Texas Texas Texas Texas Texas Texas Texas Ala. Ala. Ala. La. La. La. Calif. Calif. A r k Okla. Okla. Miss.

indicating that the majority of the brines probably do not contain enough valuable minerals to be considered commercial by themselves. However, these six brines may warrant further investigation, it sufficient brine is available.

CONCLUSIONS 417

Brine 1 is sea water, and some chemicals are recovered from sea water. Therefore any brine that is disposed of in large volumes and has a ratio of less than 20 may warrant investigation as a source of minerals because these brines may be considered as polished ores. Brine 40 along with brine 2 may contain commercial amounts of iodine. Although the current market for iodine is attractive, this market may change, depending upon the interna- tional political atmosphere. Nevertheless the market for iodine once established should be fairly stable.

Brines 38 and 42 cannot be considered brines; in fact, brine 38 is almost potable and with little treatment would be potable. Brine 42 could be used for irrigation and as drinking water for certain types of livestock.

Conclusions

Some brines contain valuable minerals that if recovered would help pay for part or all of their disposal costs. Recovery of certain minerals and potable water should lower the potential of the disposed brine as a pollutant. Brine value and brine worth formulas should be applied to disposal waters to determine the relative value of their recoverable minerals.

References

Angino, E.E., 1967. Dissolved salts in oilfield brines - a wasted resource? In: E.E. Angino and R. Hardy (Editors), Proceedings 3rd Forum o n Geology of Industrial Minerals -State GeoL Sum. Kansas, Spec. Distrib. PubL, No.34, pp.120-125.

Anonymous, 1961. Grace moves ahead with new fertilizer. Chem. Eng. News, 39:83-84. Anonymous, 1962. Descaling: route to MAP. Chem. Eng. News, 40:52--53. Anonymous, 1971. Current prices of chemicals and related materials. Oi4 Paint, Drug

Rep., 200:24-37. Aries, R.S., 1954. Marketing Research in the Chemical Industry. Chemonomics, New

York, N.Y., 220 pp. Bardwell, G.E., 1966. Some statistical features of the relationship between Rocky Moun-

tain arsenal waste disposal and frequency of earthquakes. Mountain Geol., 3: 37-42. Brennan, P.J., 1966. Nevada brine supports a big new lithium plant. Chem. Eng.,

7 6 : 86-8 8. Bryson, W.R., Schmidt, G.W. and O’Connor, R.E., 1966. Residual salt of brine affected

soil and shale, Potwin area - Butler County, Kansas. Kansas State Dep. Health, Bull., 3( 1): 28 pp.

Christensen, J.J., McIlhenney, W.F., Muehlberg, P.E., Hunter, J.A., Heintz, J.A., Jebens, R.H. and Bacher, A.A., 1967. A feasibility study on the utilization of waste brines from desalination plants, I. U.S. Off. Saline Water Res. Dew. Progr. Rep., No.245, 359 PP.

Collins, A.G., 1966. Here’s how producers can turn brine disposal into profit. Oil Gas J., 64: 11 2-1 13.

Cox, R.L., 1967. An examination of the feasibility of mineral recovery from oilfield brines. Dep. Chem. Pet. Eng., Univ. Kansas, 41 pp., unpublished.

Crouch, R.L., 1964. Investigation of alleged groundwater contamination Tri-Rue and Ride oilfields, Scurry County, Texas Texas Water Comm. Rep., No.LD-O464MR, 16 PP.


Dodge, B.F. and Eshaya, A.M., 1960. Thermodynamics of Some Desalting Processes. Advanced Chemistry Series, No. 27. American Chemical Society, Washington, D.C., 246 pp.

Evans, D.M., 1966. The Denver area earthquakes and the Rocky Mountain arsenal disposal well. Mountain Geol., 3’: 23-26.

George, D.R., Riley, J.M. and Crocker, L., 1967. Preliminary process development studies for desulfating Great Salt Lake brines and sea water. U S . Bur. Min. Rep. Invest., No.6928, 34 pp.

Kincaid, E.E., 1956. Two moves pay off at Catesville. Oil Gas J., 54:96-98. Klein, G., Cherney, S., Ruddick, E.L. and Vermeulen, T., 1968. Calcium removal from

Miller, W.C., 1965. Bromine. US. Bur. Min. Bull., 630:159-164. Salutsky, M.L. and D u m t h , M.G., 1962. Recovery of Minerals from Sea Water by

Phosphate Precipitation. Advanced Chemistry. Series, No. 38. American Chemical Society, Washington, D.C., 199 pp.

Shreve, R.N., 1956. The Chemical Process Industries. McGraw-Hill, New York, N.Y., 2nd ed., 1004 pp.

Tallmadge, J.A., Butt, J.B. and Solomon, H.J., 1964. Minerals from sea salt. Ind Eng. Chem., 56:44-56.

U.S. Bureau of Mines, 1968. U.S. BuMines Minerals Yearbook, Metals, Minerals, and Fuels. Washington, D.C., Vol. 1-11, 1208 pp.

U.S. Bureau of Mines, 1969. U S . BuMines Minerals Yearbook, Metals, Minerals, and Fuels. Washington, D.C., Vol. 1-11, 1194 pp.

Waters, Jr., O.B. and Salutsky, M.L., 1968. Separating potassium and sodium sulfate from brines and bitterns. U.S. Bur. Min., W.R. Grace Company, U.S. Patent, No.3,402,018.

sea water by fixed-bed ion exchange. Desalination, 4:158-166.

Chapter 14. SUBSURFACE DISPOSAL

Because many oilfield waters contain appreciable quantities of dissolved solids that are capable of polluting fresh waters and lands, they must be disposed of in some manner. One of the most generally used methods of disposal is injection into a subsurface aquifer. Sedimentary rocks that were deposited in an ancient marine environment are the most likely type to possess the necessary geologic characteristics for injection sites. The technology for the installation of disposal wells for oilfield wastes is highly developed, and a similar technique has been applied to disposal of other types of wastes (Donaldson, 1964). It is believed that about 75,000 wells have been drilled in the United States for salt-water injection and disposal wells by oil companies (Smith, 1970).

History of brine disposal operations

Wells for the production of salt water were in operation in the United States as early as 1800, 59 years before Col. Drake brought in the first oil well. Salt well operators were not happy with the discovery of oil in some of their operations and not knowing what to do with the oil, they often moved to new locations to avoid the “messy nuisance” which spoiled their operation. Today salt water is the messy nuisance that oil-well operators must handle.

Early oil operators simply allowed the produced brines to run off into streams or drain into fresh-water aquifers. Landowners were so ecstatic over the royalty payments that the oil producers could do whatever they desired with the salt water. Landowners simply took their checks and moved into new locations. Then population density increased, fresh water was being polluted, farm land was damaged, and land was more valuable because of its increasing scarcity compared to the population. Therefore, controls on oilfield brine disposal became necessary.

The salt-water brine pond was used as an early method of keeping the brines from fresh-water drainage; however, earthen ponds often leak, and this method polluted fresh-water supplies. Sometimes these brine ponds were called evaporation ponds. However, it was found that in the majority of cases, evaporation and rainfall compensated each other, with the brine volume continually increasing (Jones, 1945). In west Texas, evaporation ponds are successful as a means of brine disposal. In the colder climates, winter usually caused a continuous gain in brine pond gage height. These gains were

SUBSURFACE DISPOSAL 420

not overcome in the summer months. In cases where evaporation ponds are well-lined to prevent drainage, the problem of how to handle the salt deposits begins to mount up. Where solar evaporation conditions are favorable, very little salt is needed for the roads when it snows because it seldom snows there.

The expense of oilfield brine disposal is the least where salbwater bodies are nearby, but even here some care must be taken. The oil content must be less than 30 pprn for disposal into the oceans in coastal areas, otherwise, the oil collects on the shore and becomes a hazard to oyster and fish life. Along the Gulf of Mexico strict controls by wildlife authorities and oyster and fish industries monitor the brines disposed in the Gulf. A small quantity of oil gives both fish and oysters a bad taste.

Subsurface injection

Injection may not be the proper word since pressure is not always necessary. The Plains States are in a hard water belt and have the strictest controls on subsurface disposal. Whether or not subsurface disposal expenses should always be considered the 'most expensive means of disposal is debatable. Pressure maintenance by injected brine assists oil production rates. Oilfield brines are also used for waterflooding; therefore, not injecting the brine may decrease production and result in a more expensive method of disposal.

Shallow well disposal was one of the first subsurface disposals employed where a shallow well is defined as one using a horizon less than 305 m in depth. A shallow well takes considerable input brine for a time, but increasing pressures become necessary as time goes by and this continually increases disposal costs. Shallow wells are also more likely to allow the injected brine to reach fresh-water supplies in some areas.

When a deep-seated bed is known to be available, it is less costly in the long run to make use of the deeper formation. Deep disposal wells accept immense volumes of brine by gravity, and eliminating the necessity of injection pressures reduces disposal expenses. It often was discovered that clogging occurred near the bore of the injection well and treatment was necessary to reduce clogging. Today treatment plants compose a large fraction of the subsurface disposal operations.

Early in the history of subsurface brine disposal, legislation simply allowed any means of disposal. Since then legislation has for all practical purposes forced subsurface disposal and set up tight controls and safeguards for protection of fresh water. In the 1930's, the Railroad Commission of Texas allowed the increase of oil allowable by 1 m3 for every 50 m3 of brine returned to subformations. The increase was fixed at a maximum of 0.8 m3 (Laurence and Leusler, 1958) and this incentive program did a great deal to encourage subsurface disposal of brines in the East Texas field.

PRESENT-DAY TECHNOLOGY 421

Present-day technology in subsurface disposal

Several areas of research in the handling of brines were opened because of the subsurface disposal of oilfield brines. The most notable problems encountered were scaling in the salt-water lines, corrosiveness of brines, in- efficient separation of oil from the water, and poor well cements. Today, methods to correct most of these problems are available.

The scaling problem is a culprit which causes large expenses in brine- handling operations. Morris (1959) describes the method which the East Texas Salt-Water Disposal Company (1953) uses for handling scale formation. Asbestos-cement pipe is used almost exclusively in their salt-water gathering system. This pipe does not deteriorate from salt-water use and has been found quite practical to prevent corrosion. However, accumulation of scale often occurs to such an extent that the inside of the pipe must be cleaned regularly to maintain injection capacity. Sections of 8-inch lines often are reduced by scale to 2-inch lines over a period of years.

The East Texas Salt-Water Disposal Company (1953) had the maintenance responsibility for 611 km of such pipeline. To accomplish this they had four pipeline-cleaning crews at work 5 days a week cleaning pipelines exclusively. The most efficient method for scale removal was scrapers. The scraper is forced through the pipeline by pump pressure applied against a rubber cementing plug. The plug is followed by a wire brush, and a second type of scraper is used where high temperatures are used to treat water-oil emulsions. The scale deposits in this case are too hard to be removed by a wire brush, and the scraper used to remove this scale is mechanically operated by a flexible cable. Table 14.1 compares the costs of pipeline cleaning methods (Morris, 1959).

Treating oilfield brines before injection is necessary to remove suspended solids which clog the formation. When a brine is brought to the surface in East Texas, the temperature changes from 64OC to atmospheric. The pressure reduces from an average of 74 kg/cm2 to atmospheric. Carbon dioxide and petroleum gases, which were dissolved in the salt water, are allowed to escape. Oxygen and other elements of the air mix with the elements of the salt water creating many precipitates.

TABLE 14.1

Comparative costs of pipeline cleaning methods

Pipe size Costs ($/m)

(cm) cleaning machine acidizing replacement

10.2 0.249 0.958 4.04 15.2 0.174 1.919 5.77 20.3 1.050 4.259 7.64 25.4 1.234 5.899 9.61

422 SUBSURFACE DISPOSAL

Scale-forming precipitates are removed by settling tanks. Elements that will precipitate in the well are chemically precipitated and removed, and oil is skimmed from the settling tanks. Smaller oil particles are removed by using baffles in the skimming process. Aeration is used to oxidize ferrous compounds and cause them to precipitate for filtration. A high aeration efficiency tends to reduce the chemical treatment costs.

Chlorination is used as an oxidizing agent to control algae and bacterial growth because algae. and bacterial growths cause plugging problems in the treatment plant as well as in the injection wells and disposal formations. Chemical treatment with hydrated lime and alum removes iron compounds, calcium compounds, and small amounts of hydrocarbon products. Small floc particles which remain in suspension after chemical treatment to cause precipitation are removed by filtration.

Where a closed system can be operated, treatment costs are decreased. Exclusion of oxygen prevents oxidation of iron, maintains a low corrosion rate and prevents the growth of aerobic bacteria. Laurence and Leuszler (1958) point out that the maintenance of pressure on the system will hold carbon dioxide in solution and reduce the precipitation of calcium and magnesium carbonates. In some cases a closed system will maintain the stability of the water for reinjection into the producing formation with little or no treatment. Usually a closed system will require only oil skimming and filtration, but in some cases chemicals and bactericides are necessary to control bacterial growth in a closed system.

Economics and oilfield brine disposal

Investments and operating costs for oilfield brine disposal systems are difficult to obtain and compare because of differences in accounting systems used by various oil operations. Some operations have brine disposal costs incorporated into oil production costs, others only separate costs of treating and report it as brine disposal costs.

Elliston and Davis (1944) reported a survey taken in the early 1940’s. They report investments for 256 systems totalling $4.2 million and operating costs totalling $1.2 million for 86 systems. Disposal costs then range from a few cents per m3 to 63 cents per m3. The main variables controlling the costs were the amount of treatment necessary, the size of a system, and the well depth necessary to dispose of the brine. East Texas Woodbine formation disposal averaged approximately 12 cents per m3 injected. Brine from the El Dorado field in Kansas averaged about 6.3 cents per m3. Operations where one disposal well served only eight production wells yielded a cost of 44 cents per m3. A case where one disposal well served 15 production wells gave a disposal cost of only 5 cents per m3. In general, the more brine disposed into one well, the smaller the cost.

A small operator or even a major company is not economically justified in installing a deep disposal well if the development limit of his lease or field is

ECON OM ICS 423

only one or two producing wells. Some deep disposal wells show a potential capacity of 1,600-3,200 m3 of brine intake per day under actual test. Therefore, it is evident that it is possible for several operators to use the same disposal well.

The largest oilfield brine disposal association is the East Texas Salt-Water Disposal Company. This company serves the East Texas oilfield located in northeast Texas, which is located in parts of five counties, and the company handles approximately 90% of the brine produced in this field. In 1942, with disposal costs averaging in excess of 12.6 cents per m3 and the amount of produced brine increasing, the disposal company was formed by 250 large and small operators. During the second year of operation, costs of disposal dropped to about 10.7 cents per m3. Table 14.11 shows the history of disposal costs for the East Texas Salt-Water Disposal Company (1953).

Table 14.11 shows that although there was a large difference between the costs of labor, equipment, materials, etc., from 1944 through 1958, the company’s cost per m3 of disposed brine changed very little. This probably indicates that in this case, increasing costs have been balanced by technologi- cal improvements. The amount of brine disposed per year roughly follows inverse variations to disposal cost variations. In the data gathered by Elliston and Davis (1944) on disposal system costs, investment amortization was roughly 63% of the total disposal costs. With greater fixed costs than variable operating costs, the unit costs should increase as the amount of brine injected decreases.

TABLE 14.11

East Texas Salt-Water Disposal Company’s costs

Year Brine injected Total cost before taxes ($/m3

_ _ (m3)

1942 88,600 0.450 1943 6,454,000 0.108 1944 12,606,000 0.088 1945 14,034,000 0.090 1946 17,546,000 0.089 1947 21,666,000 0.086 1948 22,932,000 0.087 1949 22,715,000 0.091 1950 21,535,000 0.091 1951 19,458,000 0.096 1952 19,310,000 0.089 1953 18,320,000 0.086 1954 18,514,000 0.092 1955 20,O 27,000 0.084 1956 20,979,000 0.084 1957 21,488,000 0.086 1958 21,969,000 0.087

SUBSURFACE DISPOSAL 424

The East Texas Salt-Water Disposal Company is considered a public utility under the Statutes of Texas, which simply gives the company a monopoly on salt-water disposal in the East Texas field. The company has in excess of $6 billion invested in over 630 km of pipeline& 35 treating plants, 64 collection centers, 212 centrifugal pumps, and 60 injection wells. All of this investment is not in one integrated gathering system, but in several small systems for different producing areas.

One small system which services a producing area is made up of three collection centers, three treatment centers, and five injection wells. In the design of a disposal system for a producing area, the location of treatment plants, collection centers, and injection wells must be optimized. Pumping costs and pipeline costs dictate the economic size and location of collection centers and treatment plants are highly automated, requiring little attention. Pipelines for gathering brines are laid to obtain gravity flow where possible.

The unit disposal costs for a particular field are determined by several factors. The more brine produced in an area, the lower the unit disposal costs. An open disposal system requires more treating than a closed one, hence higher costs. An area where gravity flow is attained for most of the brine will yield lower costs. With the costs of brine disposal per barrel remaining constant, oil producers still realize higher disposal costs on a total basis. As an oilfield is produced, the produced brine per m3 of oil increases.

While the disposal costs in subsurface brine disposal are to be minimized, the expenditure is not without benefit to the oil producer. Some produced brines are combined with additional brine-well production for waterflood purposes. Here the brine is injected into the oil-producing formation in order to displace more oil toward the oil wells. Another value of the brine injection is in pressure maintenance. The pressure in an oil reservoir decreases as the oil and brine are produced. This increases the costs of pumping the oil to the surface. Returning the brine to the reservoir formation helps to maintain the pressure. In the East Texas field the pressure dropped from 114 kg/cm2 to 70 kg/cm2 before the subsurface brine disposal program was inaugurated. The brine disposal halted the decreasing reservoir pressure. Now additional brine from other formations is added to the oilfield brine and the reservoir pressure has increased. As Morris (1960) points out, it is estimated that brine disposal in the East Texas field is responsible for the availability of an additional 95 million m3 of oil. An oilfield with 16 million m3 of oil recovery is considered a major field in the oil industry.

Injection well versus disposal well

An injection well in an oilfield waterflooding operation is a well into which water or brine is injected to sweep in-place oil out of the formation and into an oil-production well. A primary production oil well producing from a water-drive reservoir, i.e., already under a natural flood, usually is not subjected to a waterflood operation except possibly peripheral injection.

ACCEPTABLE GEOLOGIC AREAS 425

Water is injected into an oil reservoir that does not possess a natural water drive; this injection water is obtained from water supply wells, and in many cases some of it is recycled.

In oilfield waterflooding operations, an injection well is used to introduce water (often brine) into the strata to be flooded. In such an operation the oil-water interface is kept as uniform as possible to clearly sweep in-place oil out of the formation and to a production well, i.e., to obtain maximum sweep efficiency. The injection pressure and injection rate usually are low and slow during the beginning of a waterflood, and the input well usually is not fractured because channeling is thus less likely.

Disposal wells are used in oil-production operations to dispose of the waters that are produced with petroleum from a natural water-driven reservoir, and some petroleum reservoirs produce large quantities of such brine water. Disposal wells usually are fractured so that the subsurface formation will accept large quantities of fluids at little or no injection pressure; many of these wells initially operate on a vacuum. In a disposal operation, a uniform flood front and absehce of channeling is not required. The primary consideration normally is to put large amounts of fluid into a reservoir at the least possible cost.

Acceptable geologic areas

Most of the major synclinal basins contain favorable locations for deep well injection (Warner, 1967). The most acceptable areas are in porous sedimentary rock strata, e.g., sandstone, limestone, or dolomite. Such strata are found under about 50% of the land area in the United States, mainly in the Central Plains States and southwest coastal areas.

Some areas such as the west coast are underlain by complex geologic strata, which has not been satisfactorily studied. Areas where volcanic rocks are present at the surface usually are not acceptable for disposal wells. McCann et al. (1968) reported on possible disposal sites in the New York area of the Appalachian Basin. They found some suitable and some un- suitable areas. Hardaway (1968) reported on the possibilities of waste disposal in a structural syncline in Pennsylvania and found that disposal into certain horizons appeared promising but that additional seismic and well-test data are needed. Similar studies were made by Briggs (1968) for the Michigan Basin; Edmund and Goebel (1968) for the Salina Basin; Garbarini and Veal (1968) for the Denver Basin; and Peterson et al. (1968) for the San Juan Basin.

In summary, the most likely acceptable areas are found in the Puget Willimette Valley and Great Valley of California, in the Mid-Continent and Great Plains, on the Gulf coast, in the central and eastern Great Lakes area, and in much of the Mississippi River drainage basin. Areas that are likely to be unacceptable are the Western Mountain ranges; the Ozark, Wichita, Arbuckle Llano Uplift area; the Mexia fault area; the Atlantic Coast area; the

4 26 SUBSURFACE DISPOSAL

Appalachian Mountain area; most of the New England States; and certain areas near western Lake Superior and Lake Michigan.

Geologic maps

To conduct a feasibility study of a project in depth, it is desirable to have a suite of maps that show the following (L.R. Reeder, written communication, 1972): (1) surface geology; (2) subcrop at various horizons; (3) structure; (4) tectonics; ( 5 ) convergence; (6)isopachs of various reservoirs; (7) potentiometric gradient of various reservoirs; (8) depth to base of fresh water zones; (9) fresh-water wells; (10) all wells other than fresh-water wells, showing total depths.

Suitable disposal zones

The development of subsurface disposal operations by the oil industry indicates that almost all types of rocks possess large enough porosities and permeabilities to accept large amounts of fluid under favorable conditions. The injected wastes must be confined t o the disposal formation so that fresh water and other valuable natural resources are protected. Some of the characteristics that are required of an acceptable disposal zone are as follows:

(1) The rocks in the disposal strata should have large porosity, permeability, and thickness so that a significantly large volume is available for fluid injection at relatively high rates and at reasonably low pressures.

(2) The disposal reservoir should be of large area extent suitable for injection of large quantities of fluid.

(3) The reservoir rocks should be uniform and not too heterogeneous to allow calculations concerning the behavior of injection fluids, injection pressures, and possible fluid rock reactions. (4) The injection zone should contain brackish or salty water (a

salaquifer). Waters containing more than 1,000 mg/l of dissolved solids are used for domestic, irrigation, and industrial water in some areas (Warner, 1968). (5) The proposed injection zone must be separated from fresh-water zones

both laterally and vertically. Such a zone should be vertically below the level of fresh-water circulation and confined vertically by strata that are impermeable. A rule of thumb is the depth at which a confined salaquifer is present; however, this is not always applicable because in some areas salaquifers overlie fresh-water aquifers.

( 6 ) There should be no unplugged or improperly plugged wells penetrating the proposed zone in the vicinity of the disposal well.

(7) The fluids to be injected should be compatible with the rocks in the injection strata and with the fluids in the strata. If they are not, precipitates will form and plug the well. Wastes incompatible with the native fluids can

EVALUATION OF THE DISPOSAL ZONE 427

be injected behind a buffer zone; however, it is difficult to buffer the rock strata to prevent incompatible fluid and rock reaction (Gabarini and Veal, 1968).

(8) The injection zone should have a low internal hydraulic pressure to allow a sufficient margin for injection of fluids without causing hydraulic fracturing of the surrounding strata and to assure a long operating life of the disposal well.

(9) The potential injection zone should be surrounded above, below, and laterally by impermeable strata or aquicludes. Many potential zones are surrounded above and below by such strata, and the lateral movement can be monitored in the injection zone. Good seals to prevent fluid movement are provided by anhydrite, clay, gypsum, marl, salt, slate, and unfractured shale.

(10) The hydrodynamic gradient, if any, of the proposed disposal formation should be determined so that the path of movement can be calculated.

Evaluation of the disposal zone

To evaluate a disposal zone requires a detailed study of the geology of the area and maps showing the surface geology, tectonics, surface and subsurface structure and stratigraphy, salinity, potentiometric gradient, and presence of all wells in the area. The information to construct the maps can be obtained from studies outlined in Table 14.111 (Ross, 1968).

Drill cutting samples and cores are taken during drilling. The various logs and drill-stem tests can be run after the entire hole, or a portion of it, has been drilled. Pumping and injectivity tests can be performed through the drill pipe and an open-hole packer before the well is completed or through casing or tubing after the well is completed.

TABLE 14.111

Method of obtaining data to evaluate a disposal zone

Necessary information Methods

Fresh-water zones

Porosity

Permeability

Minerals in strata core samples Fluid pressure in strata Subsurface formations and

Temperature of strata temperature log Injectivity profile

State agencies, Federal agencies, drill exploitation well, and log electric log, sonic log, radioactive log, core samples drawdown test, pressure buildup test, micrologs, core samples

drill-stem tests electric log, sonic log, drilling log, core

thickness samples, radioactive log

injection test, differential temperature log, spinner log, radiotracer log


Reservoir transmissibility

The reservoir transmissibility can be calculated using knowledge obtained from the following first two items, but it is influenced and may change during disposal operation because of phenomena associated with items shown in (3) through (8). (1) Core analysis data. (2) Reservoir transient tests (Matthews and Russell, 1967). (3) Behavior of fractured reservoirs;

(4) Artificially induced fractures (DeLaguna, 1966). (5) Dissolution of rock by injected fluid. (6) Accidentally induced fractures. (7) Plugging from suspended solids;

opening of natural fractures during pumping (Snow, 1968)

bacteria; corrosion products.

(8) Plugging by clay swelling. (9) Plugging by incompatibility of fluids (Ostroff, 1964).

Compressibility of rock and water

Both the reservoir rock and interstitial fluid are compressible to a very small degree. It is the compression factor that provides the space needed t o inject extraneous fluids into an otherwise full reservoir. Waters and rock in the salaquifer are compressed by the injected waste liquids in an ever- expanding cylinder away from the wellbore. Since the rock and water compressibility is of small magnitude, the salaquifer must be of large areal extent to distribute the pressure buildup. If the formation is confined by faulting, sand pinch-out, or restricted permeability in the region of the disposal well, a very limited area will be available to compress the formation rock and water, and pressure will build up rapidly or injection rates will decline to a point where the operation becomes impractical.

Water compressibility

The compressibility of pure water is known to be dependent upon the pressure, temperature, and gas in solution in the water. Note that there is a wide range of compressibilities and that increasing pressures reduce the value, whereas increasing temperatures enlarge it. The compressibility of pure water at 408 atm and 93.3"C is approximately 4.2 x lo-" cm2/dyne. Since with increasing depth higher pressures and temperatures are encountered, it is expected that compressibility will increase, but the magnitude will depend upon the relative increases in pressure and temperqture.

A t a given pressure and temperature, the effect of gas in solution in pure water is to increase the compressibility over that of pure water at the same

EVALUATION OF THE DISPOSAL ZONE 429

pressure and temperature. A graphical method of correction for gas solubility indicates that the effect of gas solubility on the compressibility of water is great, and a reservoir water containing 3.56 m3 of natural gas per m3 will have a compressibility approximately 18% greater than that of pure water at the same temperature and pressure (Amyx et al., 1960).

Rock compressibility

The porosity of sedimentary rocks has been shown by Krumbein and Sloss (1963) to be a function of a degree of compaction of the rock. The compacting forces are a function of the maximum depth of burial of the rock. Sediments which have been buried deeply, even if subsequently uplifted, exhibit lower porosity values than sediments which have not been buried a great depth.

Apart from the effect of compaction on grain arrangement, rock minerals are also compressible. Three kinds of compressibility must be distinguished in rocks: (1) rock matrix compressibility; (2) rock bulk compressibility; and (3) bore compressibility (Amyx et al., 1960). The compressibility of each parameter above is the fractional change in volume of that parameter with a unit change in pressure. Data correlated with “net overburden pressure’’ indicate that the pore compressibility is a function of pressure. In summary, pore volume compressibilities of consolidated sandstones are in the order of 7 x lo-” to 14 x lo-’’ cm2/dyne.

Critical pressures of confining beds

Impermeability of overlying and underlying beds is essential. So that the possibility of breakthrough from pressure of injection and pressure from evolved C 0 2 or thermal expansion does not take place, all operating pressures should be below the critical pressures needed to fracture the formations. The value of the critical pressure usually ranges from 0.11 to 0.33 atm/m of well depth. To design adequate surface and pumping equipment and to accurately evaluate the hydrologic properties of the disposal formation, injectivity tests should be made. If possible, the test should be made at the critical input pressure; i.e., the point at which the formation begins to fracture. This point will determine the maximum safe injection pressure (McLean, 1969).

Natural and artificial escape routes

Joints, faults, fractures from excessive pumping pressures, formation oub crops, and unplugged or poorly plugged wells all represent potential escape routes for injected waste fluids. Many operations can be conducted within the restrictive limits established by the factors above, and some of the factors can be corrected. However, each deserves serious consideration .in conducting a feasibility study for deep-well disposal.


Art i f icial fracturing to increase permeability

Permeability may be increased by artificially fracturing the formation and propping the resulting fractures with silica sand, glass beads, aluminum pellets, or other such agents. Accidentally induced fractures may be produced when critical pressures are exceeded in pumping. Unless these fractures are propped, they will usually close and subsequently heal when pressure is relieved. In any case, the natural tendency will be for fractures to be horizontal when they are developed at depths of less than 305 m and to be vertical when developed at depths greater than 305 m. However, several sophisticated methods are being tried to direct the fractures below 305 m into the horizontal plane (L.R. Reeder, written communication, 1972). The generally accepted theory is that the attitude of the induced fracture is related to the regional stress and is oriented in a direction perpendicular to the least principal stress.

Pressure-dista n c e t ime relationship

An important but little understood consideration is the pressure effects at various distances from the wellbore for given times and volumes of injected fluids. Where legal situations may develop, or where disposal is conducted in the vicinity of potentially valuable mineral deposits, this factor becomes very important. This information is useful in predicting long-range reservoir performance and design of injection equipment and the effect on unplugged wells in the vicinity. Equations have been developed which describe fluid withdrawal from water wells. These equations can be used t o describe the converse condition; that is, fluid injection into a subsurface formation. The rate at which the pressure increases in a formation and the distance that this higher pressure moves radially out from the injection well can be computed for a specific injection rate from non-equilibrium equations. If equilibrium flow conditions are approached, however, their equations are no longer applicable. As water is continuously pumped into a homogeneous uniform aquifer of infinite areal extent, the pressure radius will increase but at a decreasing rate because of the expanding storage area available (Davis and Dewiest, 1967).

Potentiometric levels and gradients should be determined for disposal reservoirs to help analyze and anticipate fluid movement and monitoring methods needed. Depleted oil or gas reservoirs often make ideal reservoirs for the disposal of oilfield brines or other types of liquid waste, because of the volume available as a result of the production of oil and gas.

Semipermeable beds

Shales and beds of clay at one time were considered impermeable to fluids but it now is postulated that ground waters are transported across these

EVALUATION OF THE DISPOSAL ZONE 43 1

beds. This postulate assumes that the beds act as semipermeable membranes where the membranes separate waters of different salinity. Transport of water across a shale can result in lower pressure on one side of the shale versus higher pressure on the other side. Assuming that the shale acts as a membrane, the lower pressured side will be the effluent side and will contain filtered or fresher water while the high pressured side will contain the more salty water which will become even more salty as the filtration process proceeds.

Because hydrodynamic conditions exist in many ground-water aquifers, it should be a mandatory requirement that the hydrodynamic conditions of the proposed sedimentary disposal aquifer be thoroughly determinzd. Water flow in aquifers usually is determined by use of contour maps cf water elevation in wells plus aquifer permeability and aquifer thickness. This method will not give a true calculation if much water is transported through semipermeable shale or clay beds. Pressure maps are necessary in establishing such transport and the low-pressure aquifer should be used for a disposal site rather than the high-pressure aquifer.

t Injection

Fig.14.1. Cross section of disposal well.


Considerations during drilling and well completion

Fig. 14.1 is a cross section of a disposal well. Note that it is cased through the entire fresh-water zone and cemented to a competent horizon below the fresh-water zone. The annulus of the well is filled with an inhibitor fluid under pressure, and the well is equipped with a continuous monitor to detect casing or tubing failure. The well shown in Fig. 14.1 is completely lined with cement to a bottom competent zone. The materials used for tubing, casing, or valves can be carbon steel, plastic, fiberglass, stainless steel, etc., depending upon requirements.

Core samples taken during drilling operations should be reacted with the proposed liquid waste to determine what reaction might occur and how to prevent or inhibit the reactions if they are likely to damage the well; for example, to determine what precipitates form and what gases evolve to give pressure increases.

Treatment facilities, such as filtration, pH adjustment, and additives, probably will be necessary. For example, the quantity of solids in the fluid and their plugging characteristics with the disposal zone must be determined. If the quantity of suspended solids is excessive, their concentration must be reduced by filtration, settling, decantation, or gas flotation (Amstutz and Reynolds, 1968). A reduction in permeability of the injection horizon and resulting increase in injection pressure or decrease in injection rate can occur as a result of plugging of the pores. Plugging can be caused by suspended solids or entrained gas in the injected fluid, reactions between injected and interstitial fluids, autoreactivity of the waste at aquifer temperature, and pressure and reactions between injected fluids and aquifer minerals. Plugging at or near the wellbore can also be caused by bacteria, mold, and fungi.

Selm and Hulse (1959) state that the chemical reactions between injected waste and interstitial water which can cause plugging precipitates to form are as follows:

(1) Precipitation of alkaline earth metals, such as calcium, barium, strontium, and magnesium, as relatively insoluble carbonates, sulfates, orthophosphates, fluorides, and hydroxides.

(2) Precipitation of heavy metals, such as iron, aluminum, cadmium, zinc, manganese, and chromium, as insoluble carbonates, bicarbonates, hydroxides, orthophosphates, and sulfides.

(3) Precipitation of oxidation-reduction reaction products. Additional causes of formation plugging in disposal wells are as follows:

(a) partial decomposition or dispersion of salaquifer minerals yielding solid matter in suspension; (b) viscosity increases with an increase of pH; (c) coalescence of gel films at constrictions in pores; and (d) complete gelation of the entire advancing front. These reactions impair the flow the greatest when they occur near the wellbore and the least when they are far removed from the wellbore.

Clay minerals occur in sedimentary rocks and are known to reduce the

FLUID TRAVEL 433

permeability of sandstones to water as compared to their permeability to air. The water permeability of a clay-bearing sandstone decreases with decreasing water salinity, decreasing valence of the cations in solution, and increasing pH of the water.

Quartz, feldspars, carbonates, micas and clays, and iron oxides generally constitute the main components in sandstone aquifers. Limestone and dolomite are primarily carbonates but, if impure, may contain as much as 50 percent noncarbonate minerals such as quartz and clay minerals. Quartz, feldspars, and micas are nonreactive except in highly alkaline or acid solutions. Carbonate minerals are soluble in acids. The reaction of carbonate minerals with acid wastes can be beneficial, if no undesirable precipitates form and if the generation of CO, gas does not cause excessive pressure buildup or plugging of the injection zone.

Surface treatment or injection of a compatible liquid (buffer liquid) to move the indigenous brine away from the wellbore before the injection of incompatible waste liquid are two methods of preventing precipitation. If the incompatible fluids do mix later and precipitate solids, they form only at the mixing front and are at such a distance from the wellbore that pore volume is more than ample to contain solids without detectable restriction of injection.

Waste waters that are stable on the surface can become unstable at aquifer temperature and pressure. This instability can lead to polymerization of resin-like materials as suggested by Selm and Hulse (1959). Other reactions, such as the precipitation of calcium carbonate, can occur because of the decreased solubility of dissolved gas at high temperature (Ross, 1968). Case (1970) presents several methods that are useful in handling waters and analyzing problem scales.

Organic growths causing operational problems are rare in deep-well disposal projects. Most injected liquids contain sufficient heavy metals and toxic organic or inorganic solutions to provide unfavorable environments for any type of bacterial life. Amstutz and Reynolds (1968) note that fungi can exist and proliferate under a wider range of environmental conditions than can slimes, algae, or bacteria and are more likely to be encountered than the other three types of organisms. He cites an operational problem where fungi growth was encountered in a system disposing of spent sulfuric acid with a pH of 2.8. Problems with organic growths are most likely to appear where liquids are stored or passed through open ponds.

Fluid travel

The pressure radius increases but at a decreasing rate when a liquid is pumped into a homogeneous uniform aquifer of infinite areal extent because of the available expanding storage area. Nonequilibrium equations can be used to compute the distance that the higher pressures move out radially from the injection wellbore and the rate at which the pressures increase


(Wright, 1969; Davis and Dewiest, 1967; Ferris e t al., 1962). Hydraulic gradients and potentiometric levels should be determined for disposal zones to calculate and monitor the injected fluid movement.

Hazards of underground waste disposal

Contamination of shallow aquifers

Unplugged or poorly plugged wells that penetrate zones into which waste is being injected provide escape routes by which the waste liquid can reach and contaminate shal!ow fresh-water aquifers. This has been common in oilfield experience and is a factor to consider whenever an operation is conducted in the vicinity of old wells.

Vertical fracturing caused accidentally by excessive injection pressures or during the process of hydraulic fracturing acts in a manner similar to unplugged wells if the fractures breach the impermeable horizons isolating the injection zone. Surface contamination may occur if there is some malfunc- tion or material failure of surface or well equipment.

Earthquakes

The most notable example of a hazard attributed to deep-well disposal thus far is the Rocky Mountain arsenal well located about 16 km northeast of Denver 1,581 m above sea level, completed September 11, 1961. The well was drilled to a total depth of 3,671 m, and injection was made into a zone of fractured gneiss from 3,650 to 3,671 m. From March 1962 until February 1966, a volume of 0.625 million m3 was injected at a maximum rate of 1.95. m3/minute and 75 atm (average rate 0.76 m3/minute and 34 atm). The seventh week after injection began, an earthquake of magnitude 1.5 was recorded (April 24, 1962). From April 24, 1962, through August 1967, 1,514 earthquakes were recorded with magnitudes ranging from 0.5 to 5.3; all were relatively shallow in origin and from an area about midway between central Denver and the arsenal well (Hollister and Weimer, 1968).

Present consensus is that the earthquakes are products of a regional stress field of tectonic origin, triggered by the local incremental strain from injection into the arsenal well. In several aspects, however, the stress-strain relationship in the vicinity of the arsenal well seems not to have been resolved fully. Injection-triggered earthquakes were tentatively identified.

State regulations and tax incentives

Regulations

Regulations concerning construction and operation of disposal wells are not standard and vary from State to State (L.R. Reeder, written communica-

STATE REGULATIONS AND TAX INCENTIVES 43 5

tion, 1972). Missouri, Ohio, Texas, and West Virginia have regulations dealing specifically with disposal wells. Apparently no States have regulations which specifically prohibit disposal wells; however, Ohio permits disposal only into the Mountain Simon sand. Texas probably has the most specific and perhaps the most equitable regulations, which are obtained from the Texas Water Development Board. Some of their regulations shown on their Form GW-14 are as follows:

“A preliminary report is required before application can be processed. This report should include but not necessarily be limited to the following information:

(a) An accurate plat showing location of proposed injection well. (b) A map indicating location of water wells and all artificial penetrations

(oil and gas wells, exploratory tests, etc.) of the proposed injection interval(s) in the general area of the proposed injection well. Reasonable diligence shall be used to locate such penetrations. Well and abandonment records for all exploratory oil and gas tests located within the area owned and operated by application should accompany map. (Details within 5 km radius generally acceptable.)

(c) Description of local topography and geology pertinent to injection program. Depth of deepest strata containing fresh water or water of suitable quality for potential beneficial development as determined by well development and/or electrical logs. (Generally required minimum of 91 m of shale between injection zone and base of fresh water.)

(d) A detailed description of the chemical, physical, and biological characteristics of the waste to be injected. Complete chemical analyses of all inorganic constituents should be reported in ppm or mg/l. If organic fractions are present, all such constituents should be reported in ppm, mg/l, as individual percentages by weight, or in other appropriate terms.

(e) The anticipated average and maximum rate of injection in gallons per minute or barrels per day. Estimated yearly volume of injected waste and anticipated life of project. (Semiannual reports of monthly volumes, injection rates, pressures, cumulative volume, workovers.)

(f) Data on completion and operation of proposed injection well: (1) Total depth of well. (2) Casing size, grade, type, weight, and setting depth of all strings; size

and type of tubing; name, model, and depth of tubing packer setting. (3) Cement-type and volume of cement to be used on each casing string

and calculated top of cement behind each string. Describe and give percent of all cement additives. Run a cement bond log.

(4) Proposed injection interval( s) and perforations. This should include the interval(s) to be utilized initially and the entire zone requested for future development.

(5) Diagramatic sketch of proposed well. (6) Anticipated maximum and average wellhead injection pressures. (7) Description of possible hydraulic fracturing and/or acidizing pro-

grams, if anticipated.


(8) Description of proposed injectivity tests. (Logs must be run and submitted. Cement Bond Logs should be specifically required but are not (L.R. Reeder, written communication, 1972).

(g) Characteristics of injection interval(s). (1) Lithology, porosity, permeability, temperature. (2) Natural reservoir fluid pressure and equivalent hydrostatic head;

fluid saturation and chemical characteristics; and fracture gradient or critical injection pressure.

(h) Compatibility of injected waste and formation fluids. (i) Calculated rate of fluid displacement by injected waste and directions

(j) Description of program to monitor water quality in fresh-water

(k) Surface installations.

of dispersion.

aquifers.

(1) Detailed description of pretreatment process and facilities to be used (include flow diagram if available).

(2) Description of type of materials to be used in pretreatment facilities and transmission lines.

(3) Description and location of all waste retention ponds, if such are to be used in conjunction with the injection well.

In the event an existing well is to be converted to an injection well, applicant should submit a complete electric log, all other logs or surveys performed on the well, and complete casing and cementing data.”

Tax incentives

Some states give preferential tax advantages to enterprises utilizing subsurface disposal for water pollution abatement. The following examples were taken from Wright (1969).

(1) Connecticut. Exempts pollution control facilities from property tax. (Conn. General Stats. Anno., Sec. 12(81)(51), (Supp. 1966).)

(2) Florida. Very limited incentive. Provides lower valuation on control facility for ad valorem tax purposes; no tax on sale of facility, etc. (14A Fla. Stat. Anno., Sec. 403.241.)

(3) Georgia. Exempts control facilities from ad valorem tax. (Georgia Code Anno., Sec. 2-5405.)

(4) Idaho. Exempts facilities from ad valorem tax. (Idaho Code Anno., Sec. 63-105T.)

( 5 ) Illinois. Provides limited incentive, much like Florida, exempts portion of value of facility from tax on sale of property. (Ill. Anno., Stats., Ch. 120, Sec. 502.)

(6) Indiana. Exempts personal property from ad valorem tax when the same is used for pollution abatement. (Ind. Stats., Anno., Sec. 64-241.)

(7) Massachusetts. Exempts control facilities from ad valorem tax. Also gives credit against corporate or income tax for portion of cost of facility. (Mass. General Laws Anno., Ch. 59, Sec. 5 (Supp. 1968).)

COSTS OF DISPOSAL SYSTEMS 437

( 8 ) Michigan. Exempts data certified facilities from personal property taxes and taxes on sales of fixtures. (MCLA, Sec. 323.356.)

(9) Minnesota. Exempts facilities from ad valorem tax. (Minn. Stats. Anno., Sec. 272.02.)

(10) New Hampshire. Provides limited exemption by reduced assessment for property taxes purposes. (Rev. Stats. Anno., Sec. 149: 5-A.)

(11) New Jersey. Exempts water or air pollution abatement equipment of devices from ad valorem taxes. (NJSA 54:4-3.56.)

(12) New Yorh. Exempts facilities from ad valorem tax. (N.Y. Real Property Tax Law, Sec. 477.) Also provides deduction for expenses associated with pollution control. (N.Y. Tax Law, Sec. 208( 9)(g), 612( h), 706( 9).)

(13) North Carolina. Exempts facilities from ad valorem tax. Also gives credit against corporate or income tax. (N.C. General Stats. Sec. 105-296) (Supp. 1967).)

(14) Ohio. Exempts facilities from personal property taxes, franchise taxes and sales and use taxes. (Ohio Genl. Code, Sec. 6111.31, Ohio Water Pollution Control Act 1967.)

(15) Oklahoma. Provides credit against income tax liability for cost of facility. (82 Okla. Stats., 923.)

(16) Oregon. Provides credit against corporate or income tax. (Ore. Revised Stats., Sec. 314.250.)

(17) South Carolina. Exempts facilities and equipment from ad valorem tax. (S.C. Stats., Sec. 65-1522(50).)

(18) Washington. Provides that owner of facilities may have exemption from ad valorem tax or a credit in a like amount against use of business occupation tax. (RWS 82.04.20.)

(19) Wisconsin. Provides deduction for expenses associated with pollution control (Wis. Stats. Anno., Sec. 71.04(26), 71.05(1)(b)5, and 71.05(2B)); exempts facilities from ad valorem tax (Wis. Stats. Anno., Sec. 70.11(21); also provides accelerated depreciation of control works. (Wis. Stats. Anno., Sec. 71.04( ZB).)

Costs of disposal systems

Rice (1968) gave some investment costs of disposal systems for disposal of oil-associated brines, and at that time he estimated that where large volumes of water from several oil or gas wells are to be disposed of the average cost per well amounted t o $7,900. Pretreatment of the brines such as oil removal by gravity separation, flotation, or filtration adds to the cost of disposal and will vary with the type of operation (Wright and Davies, 1966). Treatment to insure compatibility of the injected waters to prevent deposition in the injection well and plugging adds to the cost (Ostroff, 1963). Bleakley (1970) described Shell Oil Company’s salt water disposal operation in its Southern Region Onshore Division. The cost of the total initial installation was $6


million, and they disposed 58,800 m3 of brine per day from 28 fields. Brine disposal costs can represent 2% of net oil sales and up to 25% of total lifting costs (Smith, 1970).

Conclusions

The storage capacity of potential salaquifers, although considerable in certain areas, is nevertheless limited if long-term continuous disposal is concerned, so that space should be treated as a natural resource. Deep-well disposal has been successful in many cases, and the evidence for questionable operations is inconclusive. However, a high success ratio does not preclude caution in the use of the method. Neither does it relieve the operators of the responsibility of close monitoring of the injected fluids and the reservoir, and the meticulous maintenance of the well facilities.

Additional research is needed to develop better methods of evaluating potential disposal reservoirs, of confining and monitoring the lateral movement of fluids in disposal zones, and of determining the rate of mixing of injected fluids with native fluids. Regulations and laws concerning disposal operation should be standardized.

References

Amstutz, R.W. and Reynolds, L.C., 1968. Is the earth’s crust going to waste, 11. Types of fluids injected and treating procedures Presented at Natl. Pet. Refiners Assoc., Mid- Continent Regional Meet., Wichita, Kansas, June 12-1 3, 1968.

Amyx, J.W., Bass, Jr., D.M. and Whiting, R.L., 1960. Petroleum Reservoir Engineering. McGraw-Hill, New York, N.Y., 610 pp.

Bleakley, W.B., 1970. Shell’s SWD meets pollution standards. Oil Gas J., 68:144-146. Briggs, Jr., L.I., 1968. Geology of subsurface waste disposal in Michigan Basin. In: J.E.

Galley (Editor), Subsurface Disposal in Geologic Basins: A Study o f Reservoir Strata - Am. Assoc. Pet. Geol., Mem. 10, pp.128-153.

Case, L.C., 1970. Water Problems in Oil Production. The Petroleum Publishing Company, Tulsa, Okla., 133 pp.

Davis, S.N. and Dewiest, R.J.M., 1967. Hydrogeology. John Wiley and Sons, New York, N.Y., 463 pp.

DeLaguna, W., 1966. Disposal of radioactive wastes by hydraulic fracturing. NucL Eng. Design, 3:338-352, 432-438.

Donaldson, E.C., 1964. Subsurface disposal of industrial wastes in the United States. U.S. Bur. Min. Inform. Circ., No.8212, 34 pp.

East Texas Salt-Water Disposal Company, 1953. Salt-Water Disposal East Texas Field. Petroleum Extension Service, Austin, Texas, 116 pp.

Edmund, R.W. and Goebel, E.D., 1968. Subsurface wastedisposal potential in Salina Basin in Kansas. In: J.E. Galley (Editor), Subsurface Disposal in Geologic Basins: A Study o f Reservoir Strata - A m . Assoc. Pet. GeoL, Mem. 10, pp.154-164.

Elliston, H.H. and Davis, W.D., 1944. A method of handling salt-water disposal including treatment of water. Presented at API Meet., Tulsa, Okla., May, 1944, API Paper,

Ferris, J.G., Knowles, D.B., Brown, R.H. and Stallman, R.W., 1962. Theory of aquifer tests, ground-water hydraulics. US. Geol. Sum. Water Supply Paper, No.l536-E, 174 PP.

N0.851- 18F.

REFERENCES 439

Garbarini, G.S. and Veal, H.K., 1968. Potential of Denver Basin for disposal of liquid wastes. In: J.E. Galley (Editor), Subsurface Disposal in Geologic Basins: A Study o f Reservoir Stmta -Am. Assoc. Pet. Geol , Mem. 10, pp.165-185.

Hardaway, J.E., 1968. Possibilities for subsurface waste disposal in a structural syncline in Pennsylvania. In: J.E. Galley (Editor), Subsurface Disposal in Geologic Basins: A S tudy of Reservoir Stmta - A m . Assoc. Pet. GeoL, Mem. 10, pp.93-125.

Hollister, J.C. and Weimer, J.C., 1968. Geophysical and geological studies of the relationships between the Denver earthquakes and the Rocky Mountain arsenal well. Colo. School Min. Q., 63(1):1-251.

Jones, O.S., 1945. Disposition o f oilfield brines. University of Kansas Press, Lawrence, Kansas, 45 pp.

Krumbein, W.C. and Sloss, L.L., 1963. Stratigraphy and Sedimentation. W.H. Freeman, San Francisco, Calif., 2nd ed., 660 pp.

Laurence, L.L. and Leuszler, W.E., 1958. ABC's of treating and handling injection water. Pet. Eng., 30:B52-B54, B59.

Matthews, C.S. and Russell, D.G., 1967. Pressure Build-up and Flow Tests in Wells. Society of Petroleum Engineers, AIME, 167 pp.

McCann, T.P., Privasky, N.C., Stead, F.L. and Wilson, J.E., 1968. Possibilities for disposal of industrial wastes in subsurface rocks on north flank of Appalachian Basin in New York. In: J.E. Galley (Editor), Subsurface Disposal in Geologic Basins: A Study o f Reservoir Strata - Am. Assoc. Pet. Geol , Mem. 10 , pp.43-92.

McLean, D.D., 1969. Subsurface disposal - precautionary measures. Ind. Waste Eng., August 1969: 20-22.

Morris, W.S., 1959. Cleaning asbestos-cement pipelines in salt-water disposal service. Pet. Eng., 31 : B46-B49.

Morris, W.S., 1960. Subsurface disposal of salt Water from oil wells. Water Pollut. Control Fed. J. , 32:l-20.

Ostroff, A.G., 1963. Compatibility of waters for secondary recovery. Prod. Monthly, 27 : 2-4-9.

Ostroff, A.G., 1964. Introduction to Oilfield Water Technology. PrenticeHall, Engle- wood Cliffs, N.J., 412 pp.

Peterson, J.A., Loleit, A.J., Spencer, C.W. and Ullrich, R.A., 1968. Sedimentary history and economic geology of San Juan Basin, New Mexico and Colorado. In: J.E. Galley (Editor), Subsurface Disposal in Geologic Basins: A S tudy of Reservoir Strata - A m . Assoc. Pet. Geol , Mem. 1 0 , pp.186-231.

Rice, I.M., 1968. Salt-water disposal in the Permian Basin. Prod. Monthly, 32(3):28-30. Ross, R.D., 1968. Industrial Waste Disposal (Reinhold Environmental Engineering Series).

Selm, R.P. and Hulse, B.T., 1959. Deep-well disposal of industrial wastes. Proc. 14th Ind.

Smith, W.W., 1970. Salt-water disposal: sense and dollars. Pet. Eng., 42:64-65. Snow, D.T., 1968. Fracture deformation and change of permeability and storage upon

change of fluid pressure. Colo. School Min. Q., 63:201-244. Warner, D.L., 1967. Deep wells for industrial waste injection in the United States -

summary of data. US. Dep. Inter., Fed. Water Pollut. Control Adm., Water Pollut. Control Res. Ser. PubL, No.WP 20-10, 45 pp.

Warner, D.L., 1968. Subsurface disposal of liquid industrial wastes. In: J.E. Galley (Editor), Subsurface Disposal in Geologic Basins: A Study o f Resenroir Stmta -Am. Assoc. Pet. GeoL, Mem. 10 , pp.11-20.

Wright, C.C. and Davies, D.W., 1966. The disposal of oilfield waste water. Prod. Monthly, 30:14-17; 22-24.

Wright, J.L., 1969. Disposal wells - a worthwhile risk. Presented at 98th Annual Meet., AIME, Washington, D.C., February 16-20 1969, Reprint, 1 5 pp.

Reinhold, New York, N.Y., 340 pp.

Waste C o n f , Purdue Univ. Eng., Ext. Ser., No.104, pp.566-586.

Chapter 15. SOLUBILITIES OF SOME SILICATE MINERALS IN SALINE WATERS

In a petroleum reservoir the subsurface saline waters are continually in contact with minerals that contain silica. Knowledge of the solubilities of some of these silicate minerals is needed in geochemical studies of sedimentary rocks. To increase this knowledge, a study was made of the solubility of five clay minerals in saline solutions. The solubilities of kaolinite, montmorillonite, nontronite, illite, and serpentine were determined as a function of time in saline solutions at 25OC and 1 atm.

Hydrothermal solution equipment capable of operating at 25"-600°C and at 1-2,100 kg/cm2 was designed and constructed to study the solubility of a serpentine (verde antique) in saline solutions at elevated temperatures and pressures. Most of the expei-iments were done between atmospheric pressure and the vapor pressure of water at 15OoC (Collins, 1969).

Composition and structure of minerals studied

Table 15.1 summarizes the approximate chemical compositions of the illite, kaolinite, montmorillonite, nontronite, and serpentine used in the experiments. All samples were natural ones and were obtained from commercial suppliers.

TABLE 15.1

Chemical composition of silicate minerals

Constituent Composition (wt.%)

illite kaolinite montmorillonite nontronite serpentine -

SiOz 56.91 44.82 49.91 39.92 44.16 A12 0 3 18.50 37.20 17.20 5.37 0.90 Fez03 4.99 0.41 2.17 29.46 0.27 FeO 0.26 0.07 0.26 0.28 2.10 MgO 2.07 0.25 3.45 0.93 40.07 CaO 1.59 0.58 2.31 2.46 0.02 Naz 0 0.43 0.40 0.14 K2 0 5.10 0.43 0.28 Hz O+ 5.98 12.92 7.70 7.00 7.15 Hz 0- 2.86 1.76 15.77 14.38 5.01 Ti02 0.81 1.26 0.24 0.08 0.01 MnO - - 0.04 - 0.02

- - - -

442 SOLUBILITIES OF SILICATE MINERALS

Illite consists of three-layer sheets made up of two layers of silica in tetrahedral coordination, one layer of aluminum in octahedral coordination, and an intersheet of adsorbed potassium. Kaolinite is a double sheet with one layer of aluminum and silica in octahedral coordination and one layer of silica with the silicon in tetrahedral coordination. The chemical structure of montmorillonite consists of two layers of silica in tetrahedral coordination and one layer of magnesium in octahedral coordination with oxygen and hydroxyl in the anion positions. Nontronite belongs to the montmorillonite group and is characterized by its abundance of iron in tetrahedral and octahedral positions; all members of this group swell in water because of introduction of interlayer water in the direction of the C-axis. Serpentine is monoclinic and composed of four molecules of the formula Mg, Si2 O5 (OH), ; the structure can be chain- or sheetlike.

In all silicates, the silicon-oxygen relation is the same; a silicon atom always occurs in the center of four oxygen atoms. This tetrahedron apparently is the fundamental invariable unit of silicate structure. Silicate types differ by the relationship of the tetrahedra in a structure to each other.

A serpentine includes at least two distinct minerals, antigorite and chrysotile. Most asbestos are chrysotile. Verde antique is antigorite.

The sheet structure of the serpentine is the disilicate type. Such a structure occurs with tetrahedra all in one plane, with each tetrahedron joined to other tetrahedra by three atoms lying in the common plane. Extension of this linkage gives a hexagonal network in the plane.

The serpentine minerals are composed of hydrated magnesium silicate layers. These layers may have ordered or disordered stacking arrangements. Oxygen atoms usually are the largest atoms in the structure. They are chiefly responsible, therefore, for the unit cell size.

Serpentine minerals can be transformed thermally. Transformation occurs at about 6OO0C and probably proceeds as:

2Mg3 Si05 (OH), + 3Mgz Si04 + SiOz + Hz 0

Serpentines are the magnesium analogs of kaolin. Their basal spacing is 7.2-7.3 8, compared with kaolinite at 7.15 A.

Analytical procedure for dissolved silica

1 ml of a 4% ammonium molybdate solution in 0 . N sulfuric acid solution was added to a portion of the aqueous phase; 15 ml of 4.5N sulfuric acid was added, and the mixture was transferred to a separatory funnel. The mixture was agitated for 1 minute in the funnel with ethyl acetate. Then the ester was extracted and transferred to a spectrophotometer cell. The absorbance of the ester was determined at 3350 A.

SILICATE SOLUBILITIES AT 25OC AND 1 ATM 443

TABLE 15.11

Composition of aqueous solutions used in ambient conditions study

Solu t io n Molality of added salt

Hz 0 HzO + CaClz Hz 0 + CaClz Hz 0 + MgClz Hz 0 + MgClz HzO + NaCl Hz 0 + NaCl Hz 0 + NaHC03 H20 + NaHC03

-

0.23 0.46 0.13 0.25 0.42 0.88 0.30 0.61

Silicate solubilities at 25OC and 1 atm

Samples of the minerals'(Tab1e 15.1) were ground to 200-mesh size, portions were placed in polyethylene bottles, and each mineral was allowed to react 6 months with the aqueous phases shown in Table 15.11. No precautions were taken t o exclude CO,; therefore, each phase was presumably saturated with CO, from the atmosphere. Portions of the aqueous phases were removed periodically from the bottles and analyzed for dissolved silica and pH. Fig. 15.1-10 illustrate smoothed solubility curves for dissolved silicon versus time. In general, it appears that as the concentration of dissolved salts in solution is increased, the solubility at ambient temperature and pressure.

. 0 1 2 1

.03 I - ,040

t

- 0 ,046

- ,044

-

0

-I 0

Z .042

.04 I loo 1,000 10

of the silicate minerals decreases

xx)

HOURS

Fig. 15.1. Silicon concentration as a function of tim: for illite-Hz O,-H2 O-CaClz, -Hz 0-NaHC03 ,-Hz 0-NaCI, and -H2O-MgCl2 at 25 C. a = Hz 0; b = CaC12,0.23M; c = NaHC03, 0.30M; d = NaCl, 0.42M; e = MgClz, 0.13M.

444 SOLUBILITIES O F SILICATE MINERALS

.03 I a ,048

E"

- - 0 .046

- ,044

0

2 0

.z ,042

.04 I I00 1,000

.03 I I- " a ,048

E"

- - 0 .046

- ,044

0

2 0

.z ,042

.04 I I00 1,000 I o.oO0

HOURS

Fig, 15.2. Silicon concentration as a function of tim% for illite-Hz O,-HzO-CaCI2, -Hz 0-NaHC03 ,-Hz 0-NaCI, and -I& 0-MgC12 a t 25 C. a = Hz 0; b = CaClz, 0.46M; c = NaHC03, 0.61M; d = NaCl, 0.88M; e = MgClZ, 0.25M.

HOURS

Fig. , 15.3. Silicon concentration as a function of time foro kaolinite-H2 O,-Hz 0- NaHC03 ,-Hz O-NaCI,-Hz 0-CaC12, and -Hz O-MgCl2 a t 25 C. a = Hz 0; b = CaClz, 0.23M; c = NaHC03, 0.30M; d = NaCl, 0.42M; e = MgClz, 0.13M.

c

.04 I I I I I I I l l 1 0 0 1.000 I C 00

HOURS

Fig. 15.4. Silicon concentration as a function of time foro kaolinite-H2 0,-Hz 0- NaHC03 ,-HZ O-NaCl,-Hz 0-CaC12, and -Hz 0-MgClz at 25 C. a = Hz 0; b = CaClz, 0.46M; c = NaHC03, 0.61M; d = NaCl, 0.88M; e = MgClz, 0.25M.

SILICATE SOLUBILITIES AT 25'C AND 1 ATM 445

5 . 0 3 4 1 i

! . o 3 2 2 -

I , , I( In

.03 I 100 I.000 10.000

HOURS

Fig. 15.5. Silicon concentration as a function of time for montmorillonite-H2 O,-H2O- CaC12 ,-H2 0-NaHC03 ,-Hz 0-NaCl, and -Hz 0-MgC12 a t 25'C. a = Hz 0; b = CaClZ, 0.23M; c = NaHC03, 0.30M; d = NaCl, 0.42M; e = MgC12, 0.13M.

.04 . 0 4 2 ~ I I00 1,000

HOURS 10,000

Fig. 15.6. Silicon concentration as a function of time for montmorillonite-H2 O,-Hz 0- CaClz ,-Hz 0-NaHC03 ,-HZ 0-NaCl, and -Hz 0-MgC12 at 25'C. a = H2 0; b = CaCl2, 0.46M; c = NaHC03, 0.61M; d = NaCl, 0.88M; e = MgCl2, 0.25M.

100 1,000 HOURS

10 100

Fig. 15.7. Silicon concentration a s a function of time for no~tronite-H2O,-H2 O-CaCl~,-H~0-NaHC03,-HzO-NaCl, and -H20-MgCl2 a t 25 C. a = HzO; b = CaCl2, 0.23M; c = NaHC03, 0.30M; d = NaCl, 0.42M; e = MgClz, 0.13M.


1,000 HOURS

i00

Fig. 15.8. Silicon concentration a s . a function of time for nontronite-HzO,-Hz O-CaC1~,-H~O-NaHCO~,-H~O-NaCI, and -HzO-MgC12 a t 25'C. a = HzO; b = CaClz , 0.46M; c = NaHC03, 0.61M; d = NaCI, 0.88M; e = MgClz, 0.25M.

.032

.031 - f ,048-

l.000 IC HOURS

Fig.' 15.9. Silicon concentration as a function of time for serpentine-Hz 0,-HzO- CaClz ,-Hz 0-NaHC03 ,-HZ 0-NaCI, and -Hz 0-MgC12 a t 25'C. a = Hz 0; b = CaClz, 0.23M; c = NaHC03, 0.30M; d = NaCl, 0.42M; e = MgC12, 0.13M.

,032

,031 - - .048 -

I I I I I I l l I 1 1 1 I l l 1 100 1.000 10

noum

Fig. 15.10. Silicon concentration as a function of time for serpentine-Hz 0,-Hz 0- CaClz,-H? 0-NaHC03,-HzO-NaCI, and -HzO-MgCIz a t 25'C. a = HzO; b = CaC12, 0.46M; c = NaHC03, 0.61M; d = NaCI, 0.88M; e = MgClz, 0.25M.

EXPERIMENTAL EQUIPMENT 447

Experimental equipment

Because the silicates, which cause scale deposits in desalination equipment, react and equilibrate slowly with aqueous solutions, pressurized thermal equipment was used to approach equilibrium more rapidly. No appropriate equipment was commercially available; therefore, the U.S. Bureau of Mines designed and built the equipment shown in Fig. 15.11-14, based on the type used by Dickson et al. (1963).

The pressure vessel was machined from sonic-tested stainless steel, and the sample container was machined from pressure-formed Teflon 7. A Teflon filter disk 1.429 cm in 0.d. by 0.318 cm thick (item 7 in Fig. 15.14) was used to filter the aqueous phase when a sample was collected for analysis.

Fig. 15.11. Hydrothermal equipment; A P pressure gage, 30,000 psi; B = temperature recorder; C = pressure recorder; D = temperature controller; E = rheostat; F = high- pressure valves; G = reactor oven; H = reactor rocking mechanism; Z = hydraulic pump; J = hoist; K = Teflon sample container; L = closure piece; and M = sampling valve.

44 8

SOL

UB

ILIT

IES O

F SIL

ICA

TE

MIN

ER

AL

S

EXPERIMENTAL METHOD 44 9

The equipment was capable of operating at 30"-600°C and at ambient to 2,100 kg/cm2. It was designed to agitate the sample continuously by rocking the muffle reactor forward and backward to 70" from the horizontal. To prolong a run, aqueous phase was added to the sample container with the recharging assembly shown in Fig. 15.12.

Experimental method

The solubility of a serpentine (verde antique) was determined at temperatures up to 200°C and at pressures up to 1,055 kg/cm2 in H20-NaC1 and H20-CaC12 phases. Serpentine ground to 200 mesh was placed in the Teflon container along with several small chunks of the same material. Then the aqueous phase was added, and the container was placed in the reactor. Aqueous phases were prepared with freshly distilled water and 99.99% purity salts. Equilibrium was approached by heating the sample to 200°C and adjusting the pressure to 1,055 kg/cm2. The sample was equilibrated at these conditions for 48 hours before a portion of the aqueous phase was withdrawn for analysis. The temperature then was dropped 25" or 50°C sequen- tially while the pressure was held constant, and portions of the aqueous phase were withdrawn every 24 hours and analyzed for pH and dissolved silica . Fundamental equations

Fundamental equations that denote thermodynamic relations for the effect of variation of pressure, temperature, and composition of solution upon the solubility relations of chemical compounds emerge from the condition for equilibrium in multicomponent systems derived by Gibbs (1928). At saturation (a condition of equilibrium between solid serpentine and solution), the molar free energy, e, of the Mg3Si205(OH), in the solid must equal the partial mold free energy, G, of the Mg3Si2 O5 (OH), in solution. A J ~ infinitestimal change maintaining equilibrium dG, therefore, must equal dG as shown by:

where u = the molar volume of serpentine; s = the molar entropy of serpentine; v, = the partial modal volume of serpentine in solution at saturation; S, = the partial molal entropy of serpentine in solution at saturation; m = the total molal concentration of H4Si04 in solution; T = the absolute temperature, and P = the pressure, in- bars.

The molar free energy, G, is a function of temperature, pressure, and concentration. At saturation, the concentration, m, is also a function of temperature and pressure.

As related to the quantities v, v!, and (aG/am)p,T, the effect of pressure

! d 4'

Fig. 15.13. Muffle furnace with pressure vessel, tubes, and thermocouples in place; 1 = thermocouple; 2 = sampling tube,lined with Teflon spaghetti tubing; 3 = pressure control tube; 4 = insulation; 5 = heating elements; 6 =closure piece; 7 = steel piece for hoist lift; and 8 = front view.

P ? ? B

I'

Fig. 15.14. Pressure vessel with Teflon sample container in place; 1 = pressure vessel; 2 = thermocouple well; 3 = Teflon seal; 4 = sample tube lined with Teflon spaghetti tubing; 5 = high-pressure tubing; 6 = closure piece; 7 = Teflon filter; 8 = Teflon sample container; and 9 = sample bottle closure pieces.

FUNDAMENTAL EQUATIONS 45 1

on the solubility of serpentine at constant temperature is given by:

where the change in molality with pressure at saturation and constant temperature is (am/aT)T. The effect of temperature on-the solubility of serpentine at constant pressure and the quantities s, S,, and (aG/am)p,T is shown by:

where (am/aT)p equals the change in molality with temperatures at saturation and constant pressure. At saturation and constant composition, the relationship between the effect of pressure variation on the equilibrium temperature and the quantities u, v,, s, and & is given by:

where (aT/aP), = the change in temperature with pressure necessary to maintain constant composition of the solution at saturation.

In equations 2, 3, and 4, u, v,, &, and (aG/am),,~ are unknown quantities. Although values for s are reported in scientific literature, only two of these equations are independent; therefore, a third relationship must be derived to calculate values of these quantities.

The differential molal entropy of solution at saturation (s - K) or ASis the change in entropy that occurs when 1 mole of serpentine is dissolved in a large volume of solution saturated with H4Si04. Multiplying AS, by the absolute-temperature gives the differential heat of solution at saturation fi,. If S, is more than s, the entropy of H4Si04 enlarged when serpentine is dissolved.

The value of (aT/aP]m in equation 4 may bedetermined wjth an equation empirically -_ - derived from constant molality if AS,, AH,, or AV, is known. To obtain V,, S,, or (aG/am)p,T, however, a value is needed h terms of activity coefficients as shown by:

where u = the number of ions formed by the dissociation of one H4SiOq molecule, R = the gas constant, T = the absolute temperature in degrees Kelvin, rn = the molal concentration of H4Si04, and y+ = the mean molal activity coefficient of H4 Si04 in solution.


Equations is obtained by combining equations 2 and 5 and can be used t o calculate V , or V, because the value of v is known:

Values for (aln rn/aP)T can be obtained by differentiating empirical equations for the solubility of serpentine as a function of temperature at a series of pressures (see Tables 15.111-X). Evaluation of equation 6 , however, requires a method of determining the mean molal activity coefficient for changes in molality at constant temperature and constant pressure and at the saturation molal concentration.

Although activity coefficients can be evaluated in several ways, most methods are based on dilute-solution treatments derived from Debye-Huckel theory. This theory, even when applying the limiting law (Lewis and Randall, 1961) shown in equation 7, is applicable only to solutes in infinitely dilute solutions:

In yf = A 1 z+z- 16 (7)

where A = a theoretical parameter and is a function of T and P ; 1z+z-I =the absolute of the product of the charges on the solute ions (for H2 Si04 ); and s = the ionic strength of the solution (s equals one-half the summation of the products formed by multiplying the molal concentration mi of each individual ion multiplied by the charge of that ion zi2 and s = '/zZjrnizi2 ).

Equation 8 is a more complete form of the Debye-Huckel expression because it accounts for the average effective diameters of the solution ions and is used to calculate activity coefficients at concentrations to 0.01 molal:

where B = a theoretical parameter and is a function of T and P , and a = the average effective diameter of the solute ions.

Differentiation of equation 8 yields:

Most of these parameters, except y+, are reported in the literature (Klotz, 1950); the parameter yk for H4Si04 in solutions more concentrated than 0.01 molal is not reported. These values can be obtained graphically (Klotz, 1950) by plotting the logarithm of the molal concentration of H4Si04 in solution versus the square root of the ionic strength of the solution, drawing a smooth curve through the experimental points, and extrapolating to zero

EXPERIMENTAL DATA 453

ionic strength to obtain the logarithm of the square root of the equilibrium constant K,. The y? can be calculated from:

yk = Ka'h/m (11)

Because of limited data, the activity coefficients were not calculated.

Experimental data and empirical equations

Table 15.111 presents the smoothed data for the amounts of silicon that went into solution when reacting serpentine with aqueous 0.025M calcium chloride solutions at various temperatures and pressures.

The coefficients for a, b, c, and d , and the standard deviations u given in Table 15.IV were derived from a least squares fit of the silicon solubilities of serpentine in aqueous 0.025M calcium chloride solutions for a first-degree equation S = a+ bt, a second-degree equation S = a + b t + ct ' , and a third-degree equation S = a + bt + ct2 + d t 3 .

Table 15.V gives the smoothed data for the amounts of silicon that went into solution when reacting serpentine with 0.05M calcium chloride at

TABLE 15.111

Smoothed molal silicon solubilities from serpentine in 0.025 molal calcium chloride solutions at various temperatures and pressures

Temperature Pressure

176 kg/cm2 ("C)

30 50 76 100 125 150 175 200

0.1045 x

0.1150 x 0.1075 x 0.9650 x lo4 0.7200 x lo4 0.4200 x lo4 0.1150 x lo4

0.1120 10-~

352 kg/cm2

0.1735 x 0.1810 x 0.1795 x 0.1705 x 0.1535 x 0.1270 x

0.5500 x lo4 0.90oo lo4

703 kg/cma

0.2045 x 0.2110 0.2120 0.2050 x 0.1895 x 0.1655 x 0.1350 x 0.10oo

1,055 kg/cm2

0.2585 x 0.2660 x 0.2670 x lo-' 0.2605 x 10" 0.2455 x

0.1905 x 0.1590 x lo-'

0.2210

various temperatures and pressures. Table 15.VI contains the coefficients for first, second, and third degree equations derived from a least squares fit of the data in Table 15.V. Table 15.VII presents the smoothed data for the amounts of silicon that went into solution when reacting serpentine with aqueous 0.05M sodium chloride solutions at various temperatures and pressures. Table 15.VIII contains the coefficient for first, second, and third degree equations derived from a least squares fit of the data in Table 15.VII.


TABLE 15.IV

Coefficients for empirical equations and resulting standard deviations (a) derived from the data in Table 15.111

Pressure

176 kg/cm2 352 kg/cm2 703 kg/cm2 1,055 kg/cm2

S = a + b t a 0.14567 x 0.22177 x 0.24774 x 0.30126 x b -0.61810 x 10” -0.59899 x U 0.16388 x lo4 0.17652 x 0.16566 x lo4 0.16282 x lo4 S = a + b t + c t a 0.86221 x lo4 0.15754 x 0.18723 x 0.24202 x b 0.81657 x lod6 0.77264 x 0.78028 x 0.77015 x 10” c -0.60087 x lo-’ -0.64922 x lo-’ -0.61160 x lo-* -5.59881 x lo-’ U 0.21557 x lo-’ 0.18634 x lo-’ 0.99021 x 0.17255 x lo-’ S = a + b t + ct2 + d t 3 a 0.77886 x lo4 0.14803 x 0.18125 x loW3 0.23157 x b 0.11362 x lo-’ 0.11370 x lo-’ 0.10095 x lo-’ 0.11707 x c -0.92296 x lo-’ -0.10164 x lo-’ -0.84257 x lo-’ -0.10025 x lo-’ d U 0.18318 x lo-’ 0.13391 x lo--’ 0.56229 x 0.97345 x 10”

-0.55728 x 10” -0.71175 x

2

0.93284 x lo-’ ’ 0.10636 x lo-’’ 0.66894 x lo-’ ’ 0.11693 x lo-’’

TABLE 15.V

Smoothed ‘molal silicon solubilities from serpentine in 0.05 molal calcium chloride solutions at various temperatures and pressures

Temperature (“C)

30 50 75

100 125 150 175 200

Pressure

176 kg/cm2

o.1010 10-~ 0.1030 x 0.9850 x loW4 0.9300 x 0.8650 x lo4 0.7250 x 0.5650 x lo4 0.3650 x

352 kg/cm2

0 . 2 0 4 5 ~ lov3 0 . 2 1 0 5 ~ lov3 0.2025 x 0.1955 x 0.1850 x 0.1720 x 0.1540 x 0.1325 x

703 kg/cm2

0.3165 x 0.3355 x 0.3175 x 0.3170 x 0.2975 x 0.2840 x 0.2735 x 0.2525 x

EXPERIMENTAL DATA 455

TABLE 15.VI

Coefficients for empirical equations and resulting standard deviations (a) derived from the data in Table 15.V

-.

Pressure

176 kg/cm2 3 52 kg /cm 703 kg/cm2

S = a + bt a 0.12328 x lo-’ 0.23102 x loV3 0.34775 x b -0.37430 x -0.43229 x 10” -0.42874 x (3 0.76194 x 10- 0.80191 x lo-’ 0.93876 x lo-’ S = a + bt + ct2 a 0.95751 x lo4 b 0.26192 x lov6 C -0.27826 x lo-’ - U 0.12056 x lo-’

0.20276 x 0.21998 x

-0.28487 x lo-’ 0.20391 x lo-’

0.32185 x lo-’ 0.16988 x 10”

-0.26181 x lo-’ 0.61658 x lo-’

S = a + bt + ct2 + dt3 a 0.98227 x lo4 0.19892 x 0.29920 x b 0.16698 x 10- 0.36685.~ 10” 0.10385 x lo-’ C -0.18257 x lo-’ -0.43253 x lo-’ -0.11373 x lo-’ d 0.27713 x lo-’ ’ 0.42652 x lo-” 0.25355 x lo-’’ U 0.11573 x lo-’ 0.19706 x lo-’ 0.53361 x lo-’

TABLE 15.VII

Smoothed molal silicon solubilities from serpentine in 0.05 molal sodium chloride solutions at various temperatures and pressures

Temperature (“C)

30 50 75

100 125 150 175 200

Pressure

176 kg/cm2

0.1700 x lo4 0.1950 x lo4 0.2100 10- 0.2200 lo4 0.2200 lo4 0.2100 0.1950 x 10- 0.1700 x lo4

352 kg/cm2 703 kglcm’ 1,055 kglcm’

0.3700 x 10- 0.3950 x lo4 0.4100 x lo4 0.4300 x 0.4200 x lo4 0;4100 x lo4 0.4000 x lo4 0.3700 x lo4

0.5300 x lo4 0.5500 x lo4 0.5600 x lo4 0.5700 x lo4 0.5600 x lo4 0.5500 x lo4 0.5250 x lo4 0.5050 x 10-

0.7400 x 10- 0.7700 x lo4 0.7750 x lo4 0.7900 x lo4 0.7650 x lo4 0.7600 x lo4 0.7400 x lo4 0.7150 x lo4


TABLE 15.VIII

Coefficients for empirical equations and resulting standard deviations ((7) derived from the data in Table 15.VII

Pressure

176 kg/cm2 352 kg/cm2 703 kg/cm2 1,055 kglcm’

S = a + b t a 0.19939 x lo4 0.40047 x lo4 0.56299 x lo4 0.77924 x lo4 b -0.56601 x -0.13533 x 10- -0.17005 x -0.19774 x loU7 U 0.18996 x lo-’ 0.2Q454 x lo-’ 0.18211 x lo-’ 0.19618 x lo-’ S = a + bt + ct2

b 0.15828 x 0.16960 x lov6 0.13354 x 0.13485 x low6 C -0.65845 x lov9 -0.67625 x low9 U 0.28312 x 0.40924 x low6 0.38334 x 0.71101 x

S = a + b t + c t2 + dt3

b 0.18236 x 10” 0.20036 x 0.18585 x 10” 0.24740 x C -0.93739 x -0.10512 x -0.11856 x -0.18106 x d U 0.26986 x 10” 0.39434 x 10- 0.33519 x 0.58769 x 10-

a 0.13066 x lo4 0.32714 x lo4 0.49784 x lo4 0.71234 x lo4

-0.69472 x 10*-0.74119 x

a 0.12438 x lo4 0.31912 x lo4 0.48420 x lo4 0.68299 x lo4

0.70283 x lo-’’ 0.89777 x lo-’ 0.15266 x lo-’ ’ 0.32852 x lo-’ ’

TABLE 15.IX

Smoothed molal silicon solubilities from serpentine in 0.1 molal sodium chloride solutions at various temperatures and pressures

Temperature (“C)

30 50 75

100 125 150 175 200

Pressure

176 kg/cm2

0.2350 x lo4 0.2800 x lo4 0.3100 x lo4 0.3300 x lo4 0.3200 x 0.2900 x lo4 0.2700 x lo4 0.1750 x lo4

3 5 2 kg/cm2 703 kg/cm’ 1,055 kglcm’

0.3200 x lo4 0.3650 x 0.4000 x lo4 0.4150 x 0.4350 x lo4 0.4050 x 0.3600 x lo4 0.2500 x lo4

0.5700 x 0.6100 x lo4 0.6500 x lo4 0.6600 x lo4 0.6450 x lo4 0.6150 x lo4 0.5700 x lo4 0.4950 x lo4

0.1355 x 0.1435 x lo4 0.1475 x lo4 0.1495 x lo4 0.1480 x lo4 0.1450 x low4 0.1415 x lo4 0.1325 x lo4

SUMMARY AND CONCLUSIONS 457

TABLE 15.X

Coefficients for empirical equations and resulting standard deviations (a) derived from the data in Table 15.IX

Pressure

176 kg/cm2 352 kg/cm2 703 kg/cm2 1,055 kg/cm2

S = a + b t a 0.30724 x lo4 0.39656 x lo4 0.64963 x lo4 0.14527 x b -0.27390 x lo4 -0.24585 x -0.42217 x -0.21139 x a 0.45114 x lo-' 0.54718 x lo-' 0.46091 x lo-' 0.56072 x lo-' S = a + bt + ct2 a 0.14511 x 10- 0.20125 x lo4 0.48267 x lo4 0.12509 x b 0.34728 x 0.42680 x low6 0.34365 x 0.44518 x c -0.16387 x lo-' -0.19742 x lo-' -0.16876 x lo-' -0.20395 x lo-' a 0.84998 x 0.12037 x lo-' 0.65103 x lod 0.10164 x lo-' S = a + b t + ct2 + d t 3

b 0.27393 x low6 0.14290 x 0.37802 x lov6 0.57294 x c -0.20340 x lo-' -0.33271 x lo-' d a 0.80897 x 0.65538 x lod 0.63945 x 0.90915 x 10"

a 0.16424 x 1 0 4 0.27529 x 0.47371 x lo4 0.12176 x

-0.89940 x lov9 -0.88707 x -0.21411 x lo-' '-0.82867 x lo-' ' 0.10033 x lo-'' 0.37291 x lo-' '

Table 15.IX contains smoothed data for the amounts of silicon that went into solution when reacting serpentine with aqueous 0.W sodium chloride solutions at various temperatures and pressures. Table 15.X contains the coefficients for first, second, and third degree equations derived from a least squares fit of the data in Table 15.IX. Plots of the silicon solubilities versus temperature are shown in Fig. 15.15.

Summary and conclusions

Solubility determinations were made of five clay minerals in aqueous saline solutions. In general, the dissociation of silicon as silica from the clay minerals decreased with increasing concentrations of dissolved salts at ambient temperatures and pressures. Solubility determinations of a serpentine mineral in aqueous saline solutions at elevated temperatures and pressures were determined in specially designed hydrothermal equipment. The standard deviations of the experimental data were acceptable within the limits of the equilibria time, and the smoothed data yielded acceptable empirical equations. The equipment proved to be of excellent design and construction.

The solubilities of silicon from a serpentine in aqueous salt solutions at various temperatures and pressures can be calculated with the coefficients


,031 ,040

,046-

- - - 1 :-

-

- - - / - =

- 0 - 2 .034.- 0.025 Molal calcium chloride - 0.05 Molol calcium chloride -

i

x - x y ,031 .048 - .O 46

.O 44 KEY

1,055 Kg/Cm2 0 703 Kg/Cm2

x 176 Kg/Cm2 .042- 352 KQ/Cm2

.04 I 20 40 60 00100 200 20 40 60 00100 200

TEMPERATURE, "C

Fig. 15.15. Molal silicon solubilities from serpentine in aqueous chloride solutions at various temperatures and pressures.

for a first-degree equation S = a + bt, a second-degree equation S = a + bt + c t 2 , and a third-degree equation S = a + bt + ct2 + d t3 given in Tables 15.IV, VI, VIII, and X. The first-degree equation can be used to make a rapid calculation with fairly good accuracy; the third-degree equation can be used to calculate a more accurate value consistent with the experimental data. Although equation 11 can be used to obtain approximate activity coefficients, considerably more data are needed for calculating accurate activity coefficient values.

The solubility values obtained in a study of five clay minerals in aqueous saline solutions indicated that in general the silicon solubilities decreased

REFERENCES 459

with increasing concentrations of dissolved salts at ambient conditions. To make more specific conclusions, a more detailed study would be necessary.

References

Collins, A.G., 1969. Solubilities of some silicate minerals in saline waters. U.S. off Saline Water Res. Dew. Progr. Rep. , No.472, 27 pp.

Dickson, F.W., Blount, C.W. and Tunell, G., 1963. Use of hydrottermal y lu t ion equipment to determine the solubility of anhydrite in water from 100 C to 275 C and from 1 bar t o 1,000 bars pressure. A m . J. S c i , 261:61-78.

Gibbs, J.W., 1928. The Collected Works of J. Willard Gibbs, 1. Thermodynamics. Long- mans Green, New York, N.Y., 353 pp.

Klotz, I.M., 1950. Chemical Thermodynamics. Prentice Hall, Englewood Cliffs, N.J., 369 PP.

Lewis, G.N. and Randall, M., 1961. Thermodynamics. McGraw-Hill, New York, N.Y., 2nd ed., 723 pp.

Chapter 16. ENVIRONMENTAL IMPACT OF OIL- AND GAS-WELL DRIL- LING, PRODUCTION, AND ASSOCIATED WASTE DIS- POSAL PRACTICES*

No detailed studies have been made about how drilling fluids, drilling muds, well cuttings, and well-treatment chemicals may contribute to pollution. Studies of well blowouts and possible development of communication between a fresh-water aquifer and an oil-bearing sand have been made (Vedder et al., 1969) as have studies of possible pollution related to poor production practices (Schmidt and Wilhelm, 1938). The fact that the brines produced with oil and gas can contribute t o pollution is well known (Crouch, 1964; Grandone and Schmidt, 1943; Taylor et al., 1940; Wilhelm and Schmidt, 1935), but no universally satisfactory method of their disposal is available. Disposal of brine by solar evaporation in evaporating ponds has been investigated (Gunaji and Keyes, 1968), but final disposal of the residue salts needs further development. Some brines contain valuable minerals which are economically recoverable, and treatment or disposal of such brines should be coordinated with mineral-recovery processes whenever possible (Collins, 1966).

Several publications are available about oilfield brine disposal by subsurface injection into porous and permeable strata (Morris, 1956; Payne, 1966; Rice, 1968); the staff of the East Texas Salt-Water Disposal Company (1953) has prepared a comprehensive report that describes gathering systems, pumps, treatment methods, and injection wells. Subsurface injection of oilfield wastes provides a good method for disposal of potential water pollutants, but the results are not always satisfactory (Donaldson, 1964; Watkins et al., 1960). This disposal method has been blamed as the possible cause of earthquakes, and if a natural disaster, such as an earthquake, occurs, new faults or fractures in subsurface strata may provide communications between the strata containing the waste and fresh-water aquifer (Bardwell, 1966; Evans, 1966; Warner, 1966).

Drilling

Drilling fluids and muds

The most modern drilling method is the rotary system which requires circulation of drilling fluid for removal of drilled cuttings from the bottom

* Reprinted with permission from Journal Water Pollution Control Federation, 43~2383-2393 (1972).

462 ENVIRONMENTAL IMPACT OF PETROLEUM PRODUCTION

of the hole to keep the drill bit and the bottom of the hole clean. The drilling fluids are pumped from ground surface through a drill pipe and bit to the bottom of the hole and returned to the surface through the annulus between the hole and the drill pipe. The flow of formation gas, oil, and brine into the drill hole is blocked by a fluid-mud column which produces a hydrostatic pressure that counterbalances or exceeds the formation pressures.

In certain geological environments, abnormally high-fluid pressures are encountered, i.e., the hydrostatic pressure is greater than 0.107 kg cm-* m-' of depth. When oil or gas wells are drilled into such an environment, there always is the possibility of a blowout unless elaborate precautions are taken and correct drilling muds are used. A situation can develop in un- cemented or poorly cemented environments if degradation or sloughing around the casing in a high-pressure zone occurs, allowing the pressured hydrocarbons to flow along the outside of the casing to a zone of lower pressure; Fig. 16.1 shows how this can happen. Drilling fluids may include gases, liquids, foams, and solids suspended in liquids. Liquid drilling fluids include crude oil, fresh water, and salt water. Most of the solids suspended in

Conductor casing

Surface casing

Possible pollution

Siough of f area Oil string casing

Fig. 16.1. Manner in which heaving shales or incompetent zones slough off and permit communication of a lower zone with an upper zone.

DRILLING 463

TABLE 16.1

Some constituents used in drilling fluids and muds

Quebracho extract Lignosulfonates, calcium and chrome derivatives Acrylonitrites (such as hydrolyzed polyacrylonitrite) Sodium salts of meta and pyrphosphoric acid Natural gums Tannins Molecularly dehydrated phosphates Subbituminous products Protocatechuic acid Barite Lignins (such as humic acids) Bentonite Sugar cane fibers Lime Granular material, such as ground nutshells Corn starch Salt water Soluble caustic/lignin product Carboxy methyl cellulose Crude oil Sulfonated crude oil Oil emulsions Sodium chromate Anionic and nonionic surfactants Organophylic clay Soaps of long-chain fatty acids Phospholipids (e.g., lecithin) Asbestos

liquids are called drilling muds and include the following: suspensiuns of clays and other solids in water (water-base muds); suspension of solids in oil (oil-base muds); oil-in-water emulsions (oil-emulsion muds); and water-in-oil clay emulsion (inverted emulsion muds). Table 16.1 lists some of the compounds in drilling muds (Caraway, 1953; Simpson et al., 1961).

Sulfonated drilling muds are prepared by: (1) sulfonating asphaltic crude oil with sulfuric acid, followed by neutralization with sodium silicate and ion exchanging with hydrated lime; or (2) absorbing concentrating sulfuric acid on a porous carrier, e.g., diatomaceous earth, and then sulfonating asphaltic crude oil with acid carrier, followed by partial neutralization with sodium hydroxide and ion exchanging with hydrated lime.

The usual asphaltic crude oils that are used yield a 5- to 7-wt.% carbon residue and have an API gravity in the range of 26'-31'. Some blends may contain an 18' API asphaltic crude oil with a 12-wt.% carbon residue blend- ed with a paraffinic 42' API crude oil with a 0.5-wt.% carbon residue. These muds are usually mixed with oil a t the drilling site and used in the drilling


operation. As the cuttings plus the used drilling mud are recovered from the well, the drilling mud is usually separated from the cuttings and reused. Some, of course, will be lost because it adheres to the cutting; therefore, some will present a possible water or land pollution hazard (Messenger, 1963).

The use of quebracho, starch, and carboxy methyl cellulose in formulating drilling muds has decreased in the last decade, whereas the use of chrome lignosulfonates has increased. The use of lime-treated mud systems has also decreased, whereas the use of low-solid muds, invert emulsions, and chrome lignosulfonate systems has increased.

Considerable money is invested in drilling muds, especially in the heavier muds; consequently, they are recovered for reuse. Such muds are primarily used for emergencies, such as lost circulation and high-pressure kicks from both gas and salt water. Many of the used muds are treated with high concentrations of lignosulfonates to produce a stable mud with specific properties.

Possible sources of pollution from drilling fluids and muds are the fluids and muds that may be spilled during drilling, those that may escape into a subsurface fresh-water aquifer, those that cling to the drill cuttings, and those that are not reused. The data in Table 16.1 indicate that several constituents in drilling fluid and mud are capable of polluting water and land.

Chemical treatment of wells

Wells are treated with acids to increase the permeability of the reservoir rocks. This increases fluid flow and increases the recovery of oil and gas; it also improves fluid injection in secondary oil recovery and disposal operations. Hydrochloric, nitric, sulfuric, hydrofluoric, formic, and acetic acids are used. Such treatments produce soluble compounds including calcium chloride, sodium sulfate, sodium fluoride, etc., and in addition, may leave partially spent acids in solution.

The volume of acid used to acidize a well may range from 1.9 to 12 m3, depending upon the amount of acid-soluble strata, the thickness of the horizon being treated, and the calculated productivity of the well (Hurst, 1970). Table 16.11 lists the approximate amounts of hydrochloric, formic,

TABLE 16.11

Volume of acids used for oil- and gas-well treatment

Acid Volume (m3 /year)

Hydrochloric Formic Acetic

3.3 lo5 7.6 x l o2 3.8 x lo2

DRILLING 46 5

and acetic acid used in the United S treatment.

Other pollution problems can develop when the salt-enriched solution plus any unspent acid are withdrawn from the well, because subsequent disposal of these solutions is complicated by their tendency to form precipitates and their low pH. It also is difficult to inhibit (Harris et al., 1966) the acid- treatment solution to prevent corrosion, and when corrosion does occur, the acid solutions and other fluids will escape at the point of pipe failure and pollute the adjacent zone, which may be a fresh-water aquifer.

Corrosion inhibitors

According to Hurst (1970), a universal “super” inhibitor has evaded the researcher for 40 years. Such an inhibitor would be useful to prevent steel casing and tubing from corroding as a result of acid treatment of a well. The best available high-temperature inhibitor is a combination of sodium arsenite with an alkyl phenolethylene oxide surfactant, and arsenic-type inhibitors have been used for both low- and high-temperature applications since the 1930’s. Table 16.111 lists some of the inhibitors used in the United States (Cowan, 1970).

TABLE 16.111

Types and amounts of inhibitors used in oil- and gas-well treatment ~~

Inhibitor

Sodium msenite Imidazoline Abiethylamine Coal tar derivatives Acetylenic alcohol-alkyl pyridine

4.54 lo5 5.68 lo5 3.18 lo5 1.14 lo5 1.36 lo5

~~

TABLE 16.IV

Types and amounts of other additives used in oil- and gas-well treatment

Additive

Lactic acid (44%) Citric acid Alkylaryl sulfonic acid Zirconium oxychloride (20%) Quaternary ammonium derivatives Polymers Gum gum Fluid loss agents Emulsion preventers

2.61 x lo5 9.08 x lo3 2.27 x lo5 1.14 lo5 9.08 lo4 4.54 lo4

8.17 lo5 2.04 lo5

2.61 x lo6


Other additives

To reduce friction, reduce loss, sustain permeability, prevent emulsions from forming, and prevent precipitation, additives are added to the oil- or gas-well systems. Table 16.IV lists some of the compounds used for these purposes and the approximate amounts used in 1 year.

Possible pollution from petroleum

An opening or cylindrical hole from the ground surface to a subsurface oil- to gas-bearing formation is a well. Such an opening usually is lined with a metal pipe cemented in place, and production equipment is fastened to the cased hole to regulate and control oil or gas withdrawal rates. Before drilling

Possible break

Conductor casing

Pass i b I e po I Iu t ton

Sur face cas in

Fig. 16.2. Probable manner whereby a well blowout can develop communication between an upper sand and a lower sand.

PRODUCTION 467

a well, some knowledge of the geologic formations to be penetrated is useful, as is knowledge of the approximate depth of the target petroleum-bearing zone. This information is needed so that the appropriate diameter, length, and type of tubular goods can be selected in planning the well.

Most States have laws requiring the setting of surface casing to protect the fresh-water subsurface sands from invasion by brines and hydrocarbons from deeper horizons. Therefore, a minimum of two strings of casing - the surface casing and the oil-string casing - will almost always be required. Addi- tional strings of casing may be required if heaving shales are found while drilling, if abnormal pressures are encountered, or if a zone of lost circulation is found. Each additional string of casing requires more capital and increases the cost of the well.

If appropriate precautions are not taken in planning, drilling, and com- pleting an oil or gas well, disastrous consequences can occur. For example, during drilling operations or when pulling the drill pipe, a well may blow out if adequate mud pressure is not maintained. Such a situation may develop if the mud line is accidentally broken or if the well casing is not properly cemented to competent zones. Fig.16.2 illustrates what might occur if fluid from a high-pressure well escapes into an incompetent zone and develops communication of a lower hydrocarbon-bearing horizon with an upper sand.

Production

Possible pollution from petroleum

Crude oil in excessive amounts is detrimental to vegetation; oily wastes on surface waters can cause a fire hazard, can be deleterious to fish life, and gradually will combine with particulate matter, sink, and thus pollute the bottom of the stream or lake. Further, crude oil has destructive effects on fowl that may swim in the polluted water and may damage the surrounding flora and the surrounding beaches. Mercury concentrations in excess of 20 ppm are present in some crude oils. In essence then, it can be assumed that excessive amounts of produced crude oil that finds its way to surface lands or waters will cause deleterious pollution.

The composition of the crude oil that pollutes the water or land will determine the extent and type of pollution. For example, some heavy crude oils possess a specific gravity of about 1, contain about 5-wt.% sulfur, and have an overall minimum boiling point of about 27OoC. Conversely, some light crude oils contain virtually no elements other than carbon and hydrogen, have 0.8 or less specific gravity, and distill below 27OoC. The major nonhydrocarbons in crude oils are basic and nonbasic nitrogen and sulfur compounds and acidic and nonacidic oxygen compounds. Usually the nonhydrocarbons are more highly concentrated in the heavier portions of the crude oils. In an overall classification, most crude oils can be classified as naphthenic paraffinic, or intermediate; the naphthenic type usually is the heaviest, the paraffinic the lightest.

46 8 ENVIRONMENTAL IMPACT OF PETROLEUM PRODUCTION

Once the crude oils escape upon land or water, they are subjected to evaporation, oxidation, solution, dispersion, and utilization by microorganisms. The lighter crude oils will evaporate more readily than will the heavy ones. The lower hydrocarbons, e.g., methane and benzene, though relatively insoluble in water, will be more soluble than the higher molecular weight hydrocarbons; the crude oils containing sulfur compounds probably will oxidize less rapidly than will those containing metallo compounds. Crude oils, when spread on salt water, such as the sea, will quite rapidly form highly stable water-in-oil emulsions, as was exhibited in the Torrey Canyon disaster.

This type of emulsfon forms thick blobs of oil which are fairly resistant to dispersal, oxidation, and bacterial reactions. The reason that this type of emulsion forms with salt water has not been clearly established. A means of readily reverting such emulsions to an oil-in-water type would be desirable for quick dispersal (Dean, 1968).

Emulsions of petroleum and brine or mixtures of crude oils and sand that are difficult to break can be found on surface disposal ponds. Should these ponds overflow, the surrounding land or surface streams will be polluted. Crude oil also may escape from leaky connections, improperly plugged wells, improperly cased and cemented wells, holes in lines or storage tanks, or as a result of an accident. Burning of the petroleum or emulsions, or both, that enter brine ponds can contribute to air pollution, and all of the petroleum will not be completely consumed by the fire.

Oil production may produce pollution in onshore or offshore areas from blowouts of the wells, dumping of oil-based drilling muds and oil-soaked cuttings, or losses of oil or brine in production, storage, and transportation. Over 320,000 km of pipelines operating at pressures to 70 kg/cm2 are used throughout the country and in offshore areas. Any rupture or accidental puncture of any of these lines results in pollution.

Possible pollution from natural gas

Blowouts of natural gas wells will contribute to pollution, especially if the natural gas contains appreciable quantities of hydrogen sulfide. Many gas wells contain enough hydrogen sulfide to pollute any fresh water they may contact. Such contact may develop if a well is faulty and communication between the gas zone and an upper fresh-water zone occurs. Brines associated with hydrogen sulfide-bearing gas zones also will contain appreciable quantities of the sulfide.

Possible pollution from oilfield brines

Waters associated with petroleum in subsurface formations usually contain many dissolved ions. Those most commonly present in greater than trace amounts are sodium (Na+), calcium (Ca+2 ), magnesium .(Mg+* ), potassium

PRODUCTION 46 9

(K+), barium (Ba+’ ), strontium (Sr+’), ferrous iron (Fe+’ ), ferric iron (Fe+3 ), chloride (Cl-), sulfate (SO4-’ ), sulfide (S-’ ), bromide (Br-’ ), bicarbonate (HC03-), and dissolved gases, such as carbon dioxide (CO’), hydrogen sulfide (H, S), and methane (CH,). The stability of petroleum- associated brine is related to the constituents dissolved in it, the chemical composition of the surrounding rocks and minerals, the temperature, the pressure, and the composition of any gases in contact with the brine (Fulford, 1968).

Scale inhibitors are added to waters and brines to prevent the precipitation reactions. Some of the chemicals used in these inhibitors are listed in Table 16.V.

TABLE 16.V

Chemicals used in scale inhibitors

Ethylenediamine tetraacetic acid salts Nitrilotriacetic acid salts Sodium hexametaphosphate Sodium tripolyphosphate Sodium carboxymethyl cellulose Aminotrimethylene phosphate

Knowledge of the oxidation state of dissolved iron in brines is important in compatibility studies. Brines in contact with the air will dissolve oxygen, and their Eh generally will be from 0.35 to 0.50 mV. Brines in contact with petroleum in the formation normally will have an Eh lower than 0.35 mV, as will waters in contact with reducible hydrocarbons (Hem, 1961). Any change in the oxidation state of brine containing dissolved iron may result in the deposition of dissolved iron compounds.

The sediments or precipitate formed from brines can cause environmental pollution directly or indirectly. For example, if the produced brines are stored in a pond, the sediments may cause soil pollution; if the brines are injected into a disposal well, the sediments may plug the face of the disposal formation, resulting in the necessity to increase injection pressures which may rupture the input system.

The amount of salt water or brine produced from oil wells varies considerably with different wells and is dependent upon the producing formation and the location, construction, and age of the well. Some oil wells produce little or no brine when first produced, but as they are produced, they gradually produce more and more brine. As some wells become older, the produced fluids may be more than 95% brine; or for each cubic meter of oil coming to the surface, 100 m3 or more of brine also is produced. The produced brines differ in concentration but usually consist primarily of


sodium chloride in concentrations ranging from 5,000 to more than 200,000 ppm; the average probably is about 40,000 ppm. For comparison, note that sea water contains about 20,000 ppm of chlorides. 1 m3 of brine containing 100,000 ppm of chloride will raise the chloride content of 400 m3 of fresh water above the maximum recommended for drinking water. Petroleum- associated brines may escape and contact fresh water or soil in different ways. For example, to protect the upper fresh waters from the deeper mineralized waters that might rise in the drilled well, the upper portion of the well is sealed by a string of cemented surface casing. If a well has insufficient surface casing, an avenue may be provided for the escape of brines if they are under sufficient hydrostatic head to cause them to rise in the hole to the surface or to the level of fresh water sands.

Handling the tremendous volume of brine produced simultaneously with petroleum is hazardous. Basically, the problem is to handle and dispose of the brine in such a manner that it does not contact soil or fresh water and cause detrimental pollution.

Currently, some produced brines are being discharged into approved surface ponds, whereas most brines are returned underground for disposal or to repressure secondary oil or gas recovery wells. The discharge of brines to any surface drainage is strictly prohibited in most States. Potential water and soil pollution problems are associated with both disposal methods. For example, if the surface pond is faulty, the brine will contact the soil and various chemical reactions will occur between the soil and the brine. Sometimes the brine will pass through the soil, reappear at the surface, and produce scar areas; sometimes it will pollute the soil and leaching will pollute surface streams or shallow subsurface aquifers.

Residual salt concentrations beneath or near abandoned unsealed disposal ponds

Unsealed surface ponds used for the disposal of oilfield brines have polluted fresh surface waters, potable groundwaters, and fertile land. Be- cause of chemical and physical phenomena and dispersion, the movement of soluble pollutants from these pqnds is complex. For example, the soluble pollutants move slowly in relation to the soil-water flow rate, and dispersion effects a displacement which causes the contaminated zone to grow.

The Kansas State Department of Health studied the soils beneath and near and old unsealed brine disposal pond that had been abandoned for 10 years. During its use, the pond received more than 29,000 metric tons of salts, and most of those soluble salts probably escaped by soil leaching and down- drainage and penetrated below the underlying limestone formation. Eleven test holes were drilled into the soil and shale beneath and adjacent to the pond, both above and below the natural drainage slope. Chemical analysis of the test hole core samples indicated that more than 430 tons (about 1.4% of the original) of soluble residual salt still remained to be leached out of the

DISPOSAL 471

soil and shale in the pond area. This amount of soluble or leachable salt remaining in the area indicates that the return of the subsurface water and soil to their prepollution level is a very slow process and may take several decades. Network pollution zones appear to form where formation fracture conjugates occur. Leaching appears to be entirely dependent upon the flushing mechanism provided by meteoric water.

The cation concentrations in the clay minerals were evaluated by X-ray diffraction techniques to trace cation transportation rates. Chloride analysis was selected as the most useful single means of detecting the presence of oilfield brine pollution, but the associated cation concentration should also be determined to formulate a more complete picture. Cation adsorption studies are apparently useful in differentiating brine-polluted soil and shale, clay mineral studies provide the information on the environmental characteristics of the pollution media, and cation exchange information aids in explaining the apparent differential transportation rates of ions in brine seepage solutions (Bryson et al., 1966; Siever, 1968).

Disposal

Subsurface disposal

A problem associated with subsurface brine disposal is casing leaks in the disposal well, which could allow the brine to enter fresh-water aquifers. Fig. 16.3 shows how an improperly designed disposal well and a leaky oil well can pollute a fresh-water aquifer. Erroneous geologic knowledge of the subsurface formation into which the brine is being pumped presents another problem. Brine usually is pumped into a subsurface formation that contains similar brine; however, exact knowledge of the faulting and fracturing of such a subsurface formation is difficult to discern. Because the brine is pumped into the formation, bottomhole pressure must not exceed 0.23 kg cm-’ m-l of overburden, or the hydraulic pressure may cause fracturing and in time, the wastes may migrate to a fresh-water zone.

Petroleum-associated brines from two different formations may form precipitates if they are mixed. For example, with a well used for disposal of brines produced from several producing oil wells, it is imperative that precautions be taken in mixing and treating the brines before injection. If the brines are incompatible and inappropriate precautions are taken, there is a possibility that deposits will form and filter out on the face of the injection formation, thus reducing the permeability. The quantity of deposits formed from incompatible brines depends on ions present. The more common deposits resulting from reactions of incompatible brines are gypsum (CaS04 * 2 H’O), anhydrite (CaS04), aragonite (CaCO,), calcite (CaC03), celestite (SrS04 ), barite (BaS04 ), troilite (FeS), and siderite (FeCO, ).

Subsurface brine disposal can be categorized as confinement or containment; confinement is the placement of brines in a horizon where any move-

47 2 ENVIRONMENTAL IMPACT OF PETROLEUM PRODUCTION

Fig. 16.3. Routes by which salt water can enter fresh water wells from faulty oil or disposal wells.

ment can be controlled or monitored, while containment is the placement that precludes the movement of the brines out of a formation or zone. Note that containment cannot be used for an unlimited supply of brine, but that confinement necessitates the monitoring of the migration of the brines. The necessary knowledge to define the hydrodynamics of brines injected into subsurface environments is expensive to obtain, and much of the necessary fundamental knowledge of subsurface formations is not available. Forma- tions into which brines are often pumped for disposal are called salaquifers, and these zones consist of permeable sedimentary rock. Some information needed before such a zone can be used for disposal operations is: How big is the zone? If the brine migrates in the zone, might it reappear in another zone or perhaps migrate to the surface? What mechanisms control movement in a given salaquifer or perhaps out of it? What steps are necessary to assure containment or confinement of the brine within the salaquifer? It is difficult, if not impossible, to develop adequate knowledge concerning how or where escape channels may occur from a salaquifer. Test drilling is the only known method that can provide such knowledge, and the drilling is expensive, as is the subsequent evaluation (Drescher, 1965).

DISPOSAL 473

Joint ownership of disposal systems by several companies helps minimize installation and maintenance costs. Brines can be gathered through common lines and accumulated at a central location, so that one disposal well serves many producing wells. Investment costs primarily depend upon the brine characteristics from the producing formations, the receptivity of the disposal formation, and the condition of the surface soil for gathering-line installation. Where the brine production is relatively small, a complete system can be installed for less than $500 per producing well, but if large volumes of brine are produced, the disposal well may be able to service only a few producing wells, and the cost may be $8,000 or more per well. In 1968 the operating costs in representative fields in the Permian Basin amounted to 0.42 mill/m3 for 6.04 million m3 of brines (Research Committee, Interstate Oil Compact Commission, 1968; Rice, 1968).

In 1967 in Texas, there were 41,000 active oil wells, and about 6,900 active gas wells from which more than 0.8 million m3/day of brine was produced. That amount of brine contains approximately 66 x lo6 kg of salts, and that amount of daily produced salt can pollute 98 million m3 of fresh water to the point that it would not be acceptable as drinking water.

Waterflooding of oil sands was begun in Bradford field, Pennsylvania, in 1907, and was developed into a systematic operation after 1934. Con- siderable care must be exercised in using this method to recover oil, e.g., there is a danger that the reinjected brine will migrate to fresh-water streams.

Subsurface disposal of oilfield brines, as well as industrial wastes, is being increasingly used to replace surface disposal (Enright, 1963; Research Com- mittee, Interstate Oil Compact Commission, 1960). The ideal conditions for formations used for such disposal are large areal extent, high permeability and porosity, overlying and underlying aquicludes, low internal pressure, salaquifer, compatible fluids, no unplugged wells open t o an outcrop, and uniformity. The reservoir used for disposal must be tremendous in size, and even though the amount of fluid that can be injected is large it is ultimately limited.

Many things are not known about what happens within a formation used for disposing of wastes. For example, many wastes are low in pH and apparently no studies have been made of how the pH changes with time within the formation. Conceivable the acid can react with the rock and perhaps break out. It is known that most accidental fractures of the formation or the overlying aquiclude will be horizontal if the well is no deeper than 300 m. However, if the disposal well is deeper than 450 m, the fracture orientation is likely to be vertical, and vertical fractures can, if large enough, cause communication with an upper zone.

Salt water under pressure will attempt to escape from any type of confinement. The salt water may escape through fractures becausa of a mechanical failure within the individual well system, through an old drill hole that penetrates the injection zone, or through a natural fault system caused by a recent earthquake.


Recovery of valuable elements before disposal

Elements found in some brines in economic concentrations are magnesium, calcium, potassium, lithium, boron, bromine, and iodine. Many of them are recovered by chemical companies from sea water, salt lakes, and subsurface saline waters (Brennan, 1966; Collins, 1970).

Factors which must be considered in evaluating a saline water as an economic resource are the cost of bringing it to the factory, the cost of the recovery process, and the cost of transporting the recovered products to market. Assuming that a brine is produced only for the purpose of recovering its dissolved chemicals, a prime factor is the cost of pumping the brine. It will cost less to produce the brine from a shallow well than from a deep well. Therefore, disregarding other factors, a brine must not only contain a certain amount of recoverable chemicals, but it must be available in large quantity before it can be considered economically valuable, and the farther it must be pumped, the more chemicals it must contain.

References

Bardwell, G.E., 1966. Some statistical features of the relationships between Rocky Mountain arsenal waste disposal and frequency of earthquakes. Mountain Geol. , 3: 37-42.

Brennan, P.J., 1966. Nevada brine supports a big new lithium plant. Chem. Eng., 73: 86-88.

Bryson, W.R., Schmidt, G.W. and O’Connors, R.E., 1966. Residual salt of brine affected soil and shale, Patiwin areas Buller Co., Kansas. Kansas State Dep. Health Bull., 3( 1): 28 pp.

Caraway, W.H., 1953. Quebraco in oil well drilling fluids. Petrol. Eng., 25:B81-83, B86, B88, B89, B92.

Collins, A.G., 1966. Here’s how producers can turn brine disposal into profit. Oil Gas J . , 64: 112-1 13.

Collins, A.G., 1970. Finding profits in oil well waste waters. Chem. Eng., 77: 165-168. Cowan, J.C., 1970. Some secondary properties of chemicals used for mineral scale inhibi-

tion. Div. Pet. Chem., A m . Chem. SOC. Meet., Houston, Texas, February 22-27, 1970, Preprints, pp. F47-F57.

Crouch, R.L., 1964. Investigations of alleged groundwater contamination, Tri-Rue and Ride oilfields, Scurry County, Texas. Texas Water Comm. Rep. , No. L.D.-0464-MR,

Dean, R.A., 1968. The chemistry of crude oils in relation to their spillage on the sea. In: J.D. Carthy (Editor), Proceedings Symposium Field Studies Council, Biol. Eff. Oil Pollut. Luttoral Communities, London, pp. 1-6.

Donaldson, E.C., 1964. Subsurface disposal of industrial wastes in the United States. U.S. Bur. Min. Inform. Circ., No. 8212, 34 pp.

Drescher, W.J., 1965. Hydrology of deep-well disposal of radioactive liquid wastes. In: A. Young and J.E. Gallup (Editors), Fluids in Subsurface Environments - Am. Assoc. PetroL GeoL, Mem. 4 , pp.399-406.

East Texas Salt-Water Disposal Company, 1953. Salt- Water Disposal East Texas Field. Petroleum Extension Service, Austin, Texas, 116 pp..

Enright, R.J., 1963. Oil field pollution. Oil Gas. J., 61:76-87.

16 PP.

REFERENCES 475

Evans, D.M., 1966. The Denver area earthquakes and the Rocky Mountain arsenal disposal well. Mountain GeoL, 3:23-26.

Fulford, R.S., 1968. Effects of brine concentration and pressure drop on gypsum scaling in oil wells. J. Pet. TechnoL, 20:559-564.

Grandone, P. and Schmidt, L., 1943. Survey of subsurface brine-disposal systems in western Kansas oilfields. U S . Bur. Min. Rep. Invest., No.3719, 20 pp.

Gunaji, N.N. and Keyes, Jr., C.G., 1968. Disposal of brines by solar evaporation. U.S. O f f . Saline Water Res. Dev. Progr. Rep., No.351, 213 pp.

Harris, O.E., Henrickson, A.R. and Coulter, A.W., 1966. High-concentration hydrochloric acid aids stimulation results in carbonate formations. J. Pet. TechnoL 18:1291-1296.

Hem, J.D., 1961. Stability field diagrams as aids in iron chemistry studies. J, Am. Water Works Assoc., 53:211-232.

Hurst, R.E., 1970. Market for completion and stimulation chemicals. Div. Pet. Chem., Am. Chem. Soc., Meet., Houston, Texas, February 22-27, 1970, p.l5(12)F9 (abstract).

Messenger, J.U., 1963. Composition, properties and field performance of a sulfcnated oil-base mud. J. Pet. TechnoL, 15:259-263.

Morris, W.S., 1956. Salt waters disposal from the engineering viewpoint. Presented to the Res. Comm., Interstate Oil Compact Comm., Dallas, Texas, May 31, 1956.

Payne, R.D., 1966. Salt water pollution problems in Texas. J. Pet. Technol., 18: 1401-1407.

Research Committee, Interstate Oil Compact Commission, 1960. Production and Disposal of Oilfield Brine in the United States and Canada. The Interstate Oil Compact Com- mission, Oklahoma City, Okla., 95 pp.

Research Committee, Interstate Oil Compact Commission, 1968. Subsurface Disposal of Industrial Wastes. The Interstate Oil Compact Commission, Oklahoma City, Okla., 109 PP.

Rice, I.M., 1968. Salt water disposal in the Permian Basin. Prod. Monthly, 32:28-30. Schmidt, L. and Wilhelm, C.J., 1938. Disposal of petroleum wastes on oil producing

properties. U.S. Bur. Min. Rep. Invest., No.3394, 36 pp. Siever, R., 1968. Establishment of equilibrium between clays and sea water. Earth Planet.

Sci. Lett., 5:106-110. Simpson, J., Cowan, J.C. and Beasley, Jr., A.E., 1961. Some recent advances in oil-mud

technology. Presented at 36th Annual Meet., AIME, Dallas, Texas, October 8-1 1 , 1961, SOC. Pet. Eng. Paper, No. 150, 16 pp.

Taylor, S.S., Holliman, W.C. and Wilhelm, C.J., 1940. Study of brine disposal systems in Illinois oilfields. U.S. Bur. Min. Rep. Invest., No.3534, 20 pp.

Vedder, J.G., Wagner, H.C. and Schollhomer, J.E., 1969. Geologic framework of the Santa Barbara channel retion. U.S. GeoL Sum. Prof. Paper, No.679, pp.1-11.

Warner, D.L., 1966. Subsurface injection of liquid wastes. In: N.E. Grosvenor, J.D. Haun and D.T. Snow (Editors), Natural Gas, Coal, Groundwater: Exploring New Methods and Techniques in Resources Research. University of Colorado Press, Boulder, Colo., pp. 10 7-1 2 5.

Watkins, J.W., Armstrong, F.E. and Heemstra, R.J., 1960. Feasibility of radioactive waste disposal in shallow sedimentary formations. NucL Sci Eng., 7:133-143.

Wilhelm, C.J. and Schmidt, L., 1935. Preliminary report on the disposal of oilfield brines in the Ritz-Canton field, McPherson Co., Kansas. U.S. Bur. Min. Rep. Invest., No.3297, 20 pp.

REFERENCE INDEX*

Agaev, A.A., 185 Ahrens, L.H., 133, 136 Akin, G.W., 371 Alexeyev, F.A., 308 Alkemade, C.T., 59 Al’tovskii, M.E., 211 Ambrose, A.W., 272 American Petroleum Institute, 19, 25, 27,

Amstutz, R.W., 432, 433 Amyx, J.W., 429 Andrews, L.J., 179 Angino, E.E., 65, 132, 226, 390, 399 Anonymous, 179,194,302,308,396,

Aries, R.S., 405 Armstrong, F.E., 461 Attaway, D.H., 108, 109, 110 Atwater, G.I., 209 Ault, W.U., 208 Aumeras, M., 161

47,105, 254, 272,347

41 5

Bentor, Y.K., 225 Bernard, J.L., 157, 216, 217 Berner, R.A., 207 Berry, F.A.F., 182 Berry, J.W., 186, 244 Biles, J., 383 Billings, G.K., 65, 244, 317 Birch, F., 212 Bischoff, J.L., 223 Bixler, H.J., 241 Black, A.P., 186 Bleakley, W.B., 437 Blount, C.W., 369, 371, 379, 447 Blyth, C.R., 243 Bogomolov, G.V., 43 Bohon, R.L., 179 Bojarski, L., 254, 260, 282 Bond, D.C., 244, 314 Bonoli, L., 182 Booth, R.L., 25 Borchert, H., 228 Bordovskii, O.K., 165,184 Boyle, R.W., 322 Braitsch, O., 163,227 Brannock, W.W., 107 Brasted, R.C., 183 Braus, H., 183 Bray, E.E., 296, 297, 311 Bredehoeft, J.D., 243 Brennan, P.J., 390, 474 Brenneman, M.C., 303 Brey, M.E., 65, 207 Briggs, Jr., L.I., 425 Brod, I.O., 211 Broecker, W.S., 202 Brongersma-Sanders, M., 204 Bronston, A., 308 Brooks, R.R., 82 Brown, R.H., 434 Bruderer, W., 210

Baar, C.A., 163 Baas Becking, L.G.M., 170, 208 Bacher, A.A., 399,411 Bailey, N.J.L., 303 Baker, D.R., 311, 312 Baker, E.G., 211, 296,298,299, 311 Ballinger, D.G., 25,43 Bardwell, G.E., 405, 461 Barnes, H.L., 224 Bars, E.A., 429 Bass, Jr., D.M., 429 Baugher,III, J.W., 343, 344 Bazilevich, Z.A., 162 Beasley, Jr., A.E., 463 Beck, K.C., 207, 294 Beckman, H.F., 105 Beerstecher, Jr., E., 301 Bennett, J.H., 227

*Only page references to text pages are made in this index. References to pages containing bibliographic details have been omitted. These details are given at the end of each chapter.

478 REFERENCE INDEX

Bryson, W.R., 405, 471 Buckley,S.E., 12, 169, 181, 313 Buckman, H.D., 138 Burges, A., 186 Burmistov, D.F., 162 Burnam, C.W., 185 Burriel-Marti, F., 54 Burst, J.F., 140, 209, 240, 294, 343 Bush, P.R., 224 Butler, G.P., 205 Butt, J.B., 393, 395, 399

Califet, Y., 182 Caraway, W.H., 207, 297, 372, 463 Carpelan, L.H., 203 Carpenter, A.B., 226 Cartmill, J.C., 210, 298, 311 Case, L.C., 195, 433 Castagno, J.L., '43 Chapman, G., 182 Chave, K.E., 207, 240 Chebotarev, I.I., 226, 262, 265, 267, 289 Chenoweth, P.A., 330, 331 Cherney, S., 399 Chilingar, G.V., 207, 245, 321 Christ, C.L., 50, 167, 198 Christensen, J.J., 399, 411 Christman, R.F., 186 Clark, S.P., 194 Clarke, F.W., 197 Claussen, W.F., 179 Clayton, R.H., 243 Cloke, P.L., 168, 208 Coggeshall, N.D., 12, 181, 314 Collins, A.G., 15, 27, 29, 37, 43, 54, 60,

61, 63, 83, 94, 96, 107, 108, 109, 110, 111, 135, 137, 140, 143, 145, 156, 157 ,169 ,171 , 204, 219, 226, 227, 229, 232, 233, 238, 297, 346, 369, 372, 390 ,394 ,402 ,441 ,461 ,474

Collom, R.E., 272 Columbus, N., 382 Conolly, J.F., 180 Cooper, J.E., 184, 297, 311, 315 Corbett, C.S., 293 Coulter, A.W., 465 Cowan, J.C., 369, 370, 372, 463, 465 Cox, D.L., 392 Craig, H., 91 Crocker, L., 399 Crouch, R.L., 405 ,461 Czamanske, G.K., 224

Dall'Aglio, M., 152 Dapples, E.C., 208 Davidson, M.J., 308 Davies, D.W., 437 Davis, J.B., 185, 301, 302, 313 Davis, J.W., 145, 147, 369, 372 Davis, S.N., 430, 434 Davis, W.D., 422, 423 Dean, J.A., 54, 80 Dean, R.A., 468 Deffeyes, K.S., 203, 204 Degens, E.T., 181, 182, 207, 210 DeLaguna, W., 428 Deroo, G., 309 DeSitter, L.Y., 242 Dewiest, R.J.M., 430, 435 Dickey, P.A., 1 , 205, 210, 226, 274, 288,

298, 311, 343, 346 Dickinson, G., 343, 344 Dickson, F.W., 369, 371, 447 Diehl, H., 96 Dingman, R.J., 132, 226 Disteche, A., 371 Disteche, S., 371 Diterikhs, O.D., 308, 314 Dodge, B.F., 402 Donaldson, E.C., 419, 461 Drescher, W.J., 472 Dressman, R.C., 25 Drong, H.J., 209 Dudova, M.Ya., 308, 314 Duffy, J.R., 180 Dunham, K.C., 224 Dunlap, H.F., 32, 35 Dunseth, M.G., 396 Dunton, M.L., 310 Dutoit, M.M.S., 186 Duursma, E.K., 178

East Texas Salt-Water Disposal Company, 421 ,423 ,461

Ebrey, T.G., 94, 96 Eckhardt, F.J., 238 Edmund, R.W., 177 ,425 Egleson, G.D., 226, 234 Eichelberger, J.W., 25 Eley, D.D., 177 Elliott, Jr., W.C., 256 Ellis, A.J., 227, 370 Elliston, H.H., 422, 423 Emery, E.M., 184 Emery, K.O., 201, 207, 293 Engelbrecht, R.S., 183 Enright, R.J., 473

REFERENCE INDEX 479

Epstein, S., 91 Erdman, J.G., 309,310 Eshaya, A.M., 402 Ettre, L.S., 185 Evans, D.M., 405,461 Evans, E.D., 296 Evans, G., 205 Evans, M.E., 177 Ewing, G.C., 203

Fabricand, B.P., 65, 207 Fajardo, I., 346, 347 Fash, R.H., 308 Ferguson, W.S., 311 Ferris, J.G., 434 Fertl, W.H., 346, 363,364 Fettke, C.R., 2 Feugere, G., 310, 322 Filonov, V.A., 317, 318 Finch, W.D., 343 Fisher, F.L., 107 Fleischer, M., 133, 136, 141, 143, 145,

147,149,150,151,152,153, 156, 158,159,161,162,164

Forgotson, J.M., 364 Forsman, J.P., 310 Foster, J.B., 362 Fowler, Jr., W.A., 245, 343, 362 Frank, H.S., 177 Frear, G.L., 370 Friedman, G.M., 202,207,234 Friedman, I., 91, 243, 244 Fuchtbauer, H., 209 Fulford, R.S., 369, 371, 380, 469 Fulton, Jr., R.B., 154, 216,217 Furman, N.H., 44

Gaida, K.H., 294 Galin, V.L., 321 Garbarini, G.S., 425, 427 Garrels, R.M., 50,167,198 Garrett, R.G., 322 Garrison, A.D., 2 Gates, G.L., 207,297,372 Gautier, A., 108 Gehman, Jr., H.M., 310 Geodekyan, A.A., 308 George,’D.R., 399 George, W.O., 107 Gerard, R.E., 310, 322 Gevirtz, J.L., 202 Gibbs, J.W., 449 Ginsburg, R.N., 202 Glater, J., 371

Glew, D.N., 371 Goebel, E.D., 425 Goldberg, E.D., 149 Goldschmidt, V.M., 133,136, 138, 140,

141,145,147,150,151,155,158 Goldshteyn, R.I., 382 Goncharov, Yu., 152 Gordon, W.C., 3 Gorgy, S., 108 Grabau, A.W., 205 Grabowski, R.J., 157, 216, 217 Graf, D.L., 243 Grandone, 461 Grauer, A., 211 Graves, Jr., R.W., 201 Greene, R.C., 373 Grim, R.E., 230, 232 Griswold, W.T., 1 Gullikson, D.M., 297 Gunaji, W.N., 461 Gutsalo, L.K., 313, 318, 319

Haddenhorst, H.G., 209 Halliburton Company, 74,118 Ham, W.E., 201 Hames, D.A., 371 Hanshaw, B.B., 224, 320 Hanson, W.E., 181 : Hardaway, J.E., 425 Harkins, K.S., 343, 344 Harris, O.E., 465 Hastings, W.W., 107 Hawthorne, R.R., 32, 35 Hays, J., 245 Hedberg, H.D., 178, 309 Heemstra, R.J., 461 Heintz, J.A., 399, 411 Helgeson, H.C., 224 Hem, J.D., 133,135,147,155,159,161,

168,170,469 Hemley, J.J., 152 Henningsen, E.R., 382 Henrickson, A.R., 465 Herrmann, R., 59, 227,228 Hill, G.A., 224, 320 Hiltabrand, R.R., 239 Hiss, W.L., 320 Hitchon, B., 244, 245, 296, 297, 299 Ho, A., 186 Hocutt, C.R., 12, 169,181, 357 Hodges, Jr., R.M., 241 Hodgman, C.D., 34 Hodgson, G.W., 180,210,296,299, 311 Hoerr, C.W., 183

480 REFERENCE INDEX

Holliman, W.C., 461 Hollister, J.C., 434 Holser, W.T., 163, 205 Hood, D.W., 183,184 Horvitz, L., 308 Hottmann, C.E., 343, 344, 347, 363 Howell, J.V., 1 Hoylman, H.W., 321 Hubbert, M.K., 382 Hulse, B.T., 432,433 Hunt, J.M., 178, 205, 210, 296, 298, 310 Hunter, J.A., 399, 413 Hurst, R.E., 464, 465

Ibert, E.R., 107 Illing, L.V., 202 Imbimbo, E.S., 65, 207

Jamieson, G.W., 205, 310 Jankowsky, W.J., 209 Jebens, R.H., 399,413 Jeffery, L.M., 183, 184 Jeltes, R., 181 Jobelius, H., 211 John, L.M., 183 Johnson, A.C., 322 Johnson, R.K., 343, 344 Johnston, J., 370 Jones, B.F., 223, 225 Jones, O.S., 419 Jones, P.H., 245, 298,343,346,347,363 Jones, P. J., 32

Kabot, F.J., 185 Kaley, M.E., 201 Kaplan, I.R., 82, 170, 208 Karasik, M.A., 152 Karaskiewicz, J., 322 Karim, M., 321 Kartsev, A.A., 297,308,314 Kawai, K., 165,179 Kazmina, T.I., 153 Keefter, R.M., 179 Kelley, W.P., 230 Kellog, M.W., and Company, 172,173 Keyes, Jr., C.G., 461 Khitarov, N.I., 140, 232, 240 KidwelI, A.L., 178, 298 Kimura, S., 241 Kincaid, E.E., 392 King, R.M., 150 Kinsman, D.D.J., 205 Klein, G., 399 Klemme, H.D., 309

Klotz, I.M., 352 Knopf, A., 155 Knowles, D.B., 434 Knudsen, M., 172 Kwrner, W.E., 184 Kohout, F.A., 382 Kolodii, V.V., 316 Koons, C.B., 311 Kopp, J.F., 25 Korobov, D.S., 317 Kortsenshtein, V.N., 313, 314 Kovieheva, I.S., 210 Koyama, T., 165 Kozin, A.N., 233 Kozlov, M.F., 43 Kramer, J.R., 225, 226, 240 Krause, H.R., 183 Krauskopf, K.B., 107 Kravchik, T.E., 314 Krejci-Graf, K., 232, 317 Krivosheya, V.A., 313 Kroepelin, H., 322 Kroner, R.C., 25 Krouse, H.R., 303 Krumbein, W.C., 204, 205,429 Kudelskii, A.V., 43 Kuznetsov, S.I., 301, 302 Kumetsova, Z.I., 211 Kvenvolden, K.A., 205, 315

Lagerwerff, J.V., 371 Lamontagne, R.A., 182 Landes, K.K., 309 Lane, A.C., 3 Lane, E.C., 272 Larson, T.E., 150 Larson, T.J., 241 Latimer, W.M., 29, 167 Laurent, P., 183 Laurence, L.L., 420, 422 Leobourg, M., 11 Leuszler, W.E., 420,422 Levorsen, A.I., 197, 295, 382 Lewis, G.N., 373,452 Lichtenberg, J.J., 25 Linnenbom, V.J., 181 Litchfield, C.D., 183 Lochte, H.L., 185 Loeb, S., 241 Loleit, A.J., 425 London, E.E., 313, 317 Long, F.A., 180 Longbottom, J.E., 25 Lotze, F., 204

REFERENCE INDEX 481

Louis, M., 182 Low, P.F., 242, 346 Lowenstam, H.A., 202 Lucchesi, P.J., 379 Lucia, F.J., 203, 204 Lutz, F.B., 108 Lyon, T.L., 138

Mandl, I., 211 Manheim, F.T., 223 Manjikian, S., 241 Manuel, O.K., 227 Marcy, V.M., 43, 101, 122 Margoshes, M., 83 Marsden, S.S., 165, 179 Marsh, G.H., 47 Martell, A.E., 145 Mason, B., 138, 143, 144, 149, 150, 151,

Matthews, C.S., 428 Mayeda, T.K., 91, 243 Maxey, G.B., 243 McAlister, J.A., 11 McAuliffe, C.D., 180, 181, 210, 311, 314,

McBain, J.W., 183 McBermott, E., 308 McCann, T.P., 425 McCutchan, J.W., 371 McDevit, W.F., 180 McElvain, R.G., 318 McIlhenney, W.F., 399, 413 McIver, R.D., 295 McKelvey, J.G., 242 McLean, D.D., 429 McLeod, H.O., 307 McNellis, J.M., 132 Meents, W.F., 243 Meinert, R.N., 310 Meinschein, W.G., 298 Mellon, M.G., 35 Merritt, Jr., L.L., 92 Messenger, J.U., 464 Metcalfe, L.D., 184 Metler, A.V., 371 Meyer, H.W.H., 185 Meyerhoff, A.A., 212 Michaels, A.S., 241 Middleton, F.M., 183 Midgett, M.R., 25 Miholic, S., 150 Miller, E.E., 209 Miller, J.C., 226 Miller, W.C., 390, 399

153,158,159, 161,163,165

31 5

Mills, R. van A., 2, 272 Milne, I.H., 242 Mitgarts, B.B., 153 Moeller, T., 133, 135, 136, 141 Mogilevskii, G.A., 297 Moore, C.A., 202 Moore, D., 170, 208 Morgan, C.O., 130 Morgan, J.J., 199 Morris, R.C., 205 Morris, W.S., 421, 424, 461 Mousseau, R.J., 12, 32 4 Muehlberg, P.E., 399, 411 Muir, R.O., 228 Mun, A.I., 162 Munn, M.J., 1, 2 Murata, K.J., 107 Myagkov, V.F., 162

Nagy, B., 180 Nalco Chemical Company, 186 Namoit, A.Y., 177 Natural Gasoline Association of America,

Naumor, G.B., 168 Nektarova, M.B., 185, 316 Nemethy, G., 177 Neuberg, C., 211 Neruchev, S.G., 210 Neuman, E.W., 372 Neumann, H.J., 211 Noad, D.F., 11, 321 Nordby, H.E., 186 Norris, M.S., 12, 314 Nutter, B.P., 11

O’Conner, J.T., 183, 474 O’Conner, R.E., 405 Oden, S., 185 Odum, H.T., 145 Ostroff, A.G., 169,256,274, 371, 428,

Oudin, J.L., 309 Ovchinnikou, N.V., 165

Packman, R.F., 186 Page, H.J., 186 Paine, W.R., 343, 347 Palmer, C., 254, 256, 257 Parker, J.W., 224, 321 Pate, B.D., 108 Patnode, H.W., 310 Patterson, M.S., 373 Pavolva, G.A., 165

186

437

482 REFERENCE INDEX

Payne, R.D., 461 Peake, E., 180,296, 311 Pearson,C.A., 108,109,110, 111 Peck, R.B., 206, 294, 344 Pennebaker, E.S., 344, 363 Peterson, J.A., 320, 425 Peterson, J.B., 425 Pettijohn, F.J., 197 Philipp, W., 209 Philippi, G.T., 295, 296, 300, 309, 310 Phillips, R.C., 368, 369, 372, 380 Phleger, F.B., 203 Piper, A.M., 132 Piper, T.J., 183 Pirson, S.J., 169, 208, 308 Pirsson, L.V., 155,168 Platte, J.A., 101 Plumley, W.J., 201 Pollard, T.A., 207 Popov, A.I., 382 Posner, A.M., 183 Potter, E.C., 27 Pourbaix, M.J.N., 30, 167 Powers, M.C., 294,343 Prescott, J.M., 183 Presley, B.J., 82 Price, L.C., 178, 296 Privasky, N.C., 425 Pugin, V.A., 140, 232, 240 Pusey, 111, W.D., 311 Pytkowicz, R.M., 371 Pyushchenko, V.G., 321

Quaide, W., 205 Querio, C.W., 226,234

Rae, A.C., 182 Rainwater, F.H., 31 Rakestraw, N.W., 108 Ralston, A.W., 183 Ramirez-Munoz, J., 54, 67 Ramsey, T.R., 320 Randall, M.H., 373,452 Rankama, K., 197 Ransone, W.R., 308 Reed, W.E., 210 Reeder, L.R., 426,430, 434, 436 Reichertz, P.O., 207 Reistle, Jr., C.E., 131, 272 Research Committee, Interstate Oil

Rettig, S.L., 223 Reuter, J.H., 181,182, 210 Reynolds, L.C., 432, 433

Compact Commission, 473

Rice, I.M., 437,461,473 Rich, J.L., 2 Rieke, 111, H.H., 245 Riley, G.A., 206 Riley, J.M., 399 Ringwood, A.E., 194 Risley, G.A., 201 Rittenberg, S.C., 207 Rittenhouse, G., 157, 216, 217, 229 Roach, J.W., 320 Robinson, J.W., 65 Robinson, L.R., 183 Rogers, G.S., 256 Rogers, W.B., 1 Rosaire, E.E., 308 Rosenqvist, I.T., 207 Rosin, J., 23 Ross, C.S., 197 Ross, R.D., 426,427,433 Rubio, F.E., 303 Ruddick, E.L., 399 Russell, D.G., 428 Russell, W.L., 242

Sahama, T.G., 197 Salutsky, M.L., 396, 399 Sandell, E.B., 98, 99 Sanders, J.E., 207, 234 Saraf, D.N., 180 Savchenko, V.P., 316 Scheraga, A.A., 177 Schilthuis, R.J., 1, 3 Schmidt, G.W., 294, 314, 343, 361, 362,

Schmidt, L., 461,471 Schoeller, H., 232, 254, 267, 271 Schollhomer, J.E., 461 Schrayer, G.T., 12, 314 Schrink, D.R., 107 Schwab, R., 317 Schwanenbek, F.X., 272 Scribner, B.F., 83 Selby, S.M., 34 Selm, R.P., 432, 433 Serebriako, O.I., 317 Sestini, F., 186 Shaborova, N.T., 185, 316 Shaffer, L.H., 369,371, 380 Shankland, R.S., 34 Shaw, D.R., 166, 244 Shaw, T.I., 166 Shearman, D.J., 205 Shilov, I.K., 316 Shimp, N.F., 243

405

REFERENCE INDEX 483

Shiram, C.R., 343, 347 Shiskina, O.V., 165 Shreve, R.N., 395 Shvets, V.M., 211, 316 Siegel, A., 182 Siever, R., 207, 471 Sikka, D.B., 318 Sillen, L.G., 145, 166 Silverman, S.R., 311 Simons, H.F., 308 Simpson, J., 463 Skinner, B.J., 193 Sloss, L.L., 429 Slowey, J.F., 184 Smales, A.A., 108 Smith, G.F., 96 Smith, H.M., 303 Smith, N.O., 180 Smith, P.V., 211 Smith, W.W., 419, 438 Snow, D.T., 438 Sokolov, V.A., 308 Solomon, H.J., 393, 395, 399 Souriragan, S., 241 Spencer, C.W., 425 Spencer, D.W., 311 Spiegler, K.S., 242 Ssutu, L., 371 Stallman, R.W., 434 Stead, F.L., 425 Steelink, C., 186 Stiff, H.A., 131, 132, 371 Stormont, D.H., 308 Stratton, G., 108 Stumm, W., 199 Subotta, M.I., 297 Sudo, Y., 316 Sugawara, K., 165, 166 Sulin, V.A., 254, 257, 258, 347 Swigart, T.E., 272 Swinnerton, J.W., 181

Tabasaranskii, Z.A., 297 Taggart, M.S., 12, 169, 181, 313 Taguchi, K., 296 Takahashi, T., 202 Tallmadge, J.A., 393, 395, 399 Taylor, D.W., 206 Taylor, S.S., 461 Templeton, C.C., 369, 372 Terada, K., 165, 166 Terzaghi, K., 206, 294, 344 Tickell, F.G., 128 Thatcher, L.L., 31

Timko, D.J., 346, 363, 364 Tissot, B., 309 Tollin, G., 186 Tooms, J.S., 227 Torrey, P.D., 1, 2 Trask, P.D., 310 Trelease, S.F., 160 Tronko, I.V., 317 Truesdell, A.H., 223, 225 Trump, R.P., 242 Tunnell, G., 447 Tunyak, A.P., 185, 316

Ulrich, R.A., 425 Upson, J.E., 382 U.S. Bureau of Mines, 254, 272, 393, 404,

Usiglio, J., 203 41 5

Valyashko, M.G., 162,227 Vandenburgh, A.S., 223 Van Everdingen, R.O., 223 Van Nostrand Press, 211 Vasil’ev, V.G., 313 Vasileuskaya, A.Ye., 152 Vdovyking, P., 319 Veal, H.K., 425, 427 Vedder, J.G., 461 Veldink, R., 181 Vermeulen, T., 399 Vetter, O.J.G., 368, 369, 372, 380, 461 Vilonov, V.A., 319 Vinogradov, A.P., 316 Vinogradov, V.L., 228, 316 Viher, G.S., 200, 322 Von Engelhardt, W., 240, 294

Wagner, H.C., 461 Wallace, W.E., 8, 343, 344 Walton, G., 183 Wangersky, P.J., 184 Waring, G.A., 135 Warner, D.L., 425,426,461 Washington, H.S., 197 Water, C.J., 111 Waters, Jr., O.B., 399 Watkins, J.W., 47, 108, 109, 110, 461 Watson, J.A., 65 Weast, R.C., 34 Weaver, C.E., 294 Weimer, J.C., 434 Weintritt, D.J., 369, 370, 372 Welcher, F.J., 40 Weller, J.M., 206

484 REFERENCE INDEX

Welte, D.H., 297, 298, 309 Weyl, P.K., 203, 204 White, D.E., 107,135,162,194, 195,

206,232,240 White, W.A., 3, 243 Whitehead, H.C., 108 Whiting, R.L., 429 Whitney, E.D., 379 Wilhelm, C.J., 461 Willard, H.H., 92 Williams, J.A., 302, 303 Williams, P.M., 184 Wilson, A.L., 186 Wilson, D.F., 182 Wilson, J.E., 425 Winter, J.A., 25 Winters, J.C., 302, 303

Witherspoon, P.A., 180,182 Woodcock, A.H., 91 Wright, C.C., 437 Wright, J.L., 434 Wyllie, M.R.J., 32, 242

Yakoylev, Yu.I., 316 Yarbrough, H.R., 313 Yasenev, B.P., 308 Young, A., 244, 346 Yurovskii, Yu.M., 308

Zarrella, W.M., 12,181, 314 Zinger, A.S., 180, 314 Zobell, C.E., 30, 167, 302 Zorkin, L.M., 313

SUBJECT INDEX

Abiogenic, 205, 293 Abnormal pressure, 344, 359 -, detection, 343 Accumulation of petroleum, 2, 298 Accuracy, in analyzing methods, 21 -, of measurements, 23 Acetic acid solutions, 120 -, in oil-well acidizing, 120 Acidified samples, 23 Acidity, 37, 156 Acid treatment, 464 Additives, 463-466 Aerobic bacteria, 169, 208, 213, 302,

304,314 Alabama, 333 Algae, 165 Aliquot size, 41 Alkali metals, concentration during

-, properties, 134 Alkaline earth metals, concentration

-, properties, 141 Alkalinity, 37, 155, 254 Alkanes, 298,309 Allochthonous origin, 293 Alteration of hydrocarbons, 299 Aluminum, abundance, 155 -, atomic absorption method, 65 -, constituent of oilfield waters, 155 -, emission spectroscopy method, 90 -, properties, 148 Amazonite, 140 American Petroleum Institute, 19, 25,

27, 254, 347 American Society for Testing and

Materials, 19 Amino acids, 182 -, chromatographic techniques, 182 Ammonium nitrogen, 157 -, concentration and economical profit,

-, determination by titrimetric methods,

evaporation, 134

during evaporation, 134

413

43

Ammonium pyrollidine dithiocarbamate,

Anadarko Basin, 128,129, 226, 297 Anaerobic bacteria, 169 Analytical method, choosing of, 20 Anhydrite, 159, 471 -, solubility, 372 Antigorite, 442 Apatite, 158 Aquifer, 225, 244 -, contamination, 434 Aragonite, 471 Arbuckle formation, 51, 330 -, chloride concentration, 332 -, potentiometric surface map, 331 Arkansas, 333,335 Aromatic hydrocarbons, 314 Arsenic, colorimetric methods, 108 -, constituent of oilfield waters, 158 -, diethyldithiocarbamate method, 108 -, Gutzeit method, 108 -, occurrence, 108 Artificial fracturing, 430 Athabasca tar sands, 303 Atomic absorption methods, 65-82 Authigenic deposition, 201, 206 Autochthonous origin, 293

82

Bacterial alteration of petroleum, 301 Bacterial reduction, 50, 235 Barite, 471 Barium, 141,147 -, atomic absorption method, 65, 77 -, colorimetric methods, 114,115 -, emission spectroscopy method, 83 -, flame spectrophotometric method, 63 -, gravimetric method, 115 -, properties, 141, 171 -, qualitative test, 114 -, recovery, 415 Barium sulfate, 367, 370, 372 -, concentration and ionic strength, 374 -, scale, 370 -,solubility, 372, 375-377, 379, 382

SUBJECT INDEX 486

Bathyal-abyssal deposits, 201 Bell Canyon formation, 322, 327-329 -, calcium concentration, 329 -, chloride concentration, 328 -, dissolved solids content, 327 -, potentiometric surface map, 323, 324 Bell Creek field, Wyoming, 303 Benzene, 315 -, solubility, 179 Benzene method for prospecting, 181,

314 Beryl, 140 Beryllium, atomic absorption method, 65 -, constituent of oilfield waters, 141, 142 -, emission spectroscopy method, 89 -, properties, 141 Bicarbonate, concentration and depth, 357 - - , Bioconcentration, 228 Biogenic origin, 205, 293 Biological degradation of hydrocarbons,

Biological weathering, 197 Biosphere, 193 Bischofite, 162 Bittern-type brines, 359 Boiling point, 172 Bolivar Coastal field, 303 Borate boron, titrimetric method of boron,

Borehole temperature, 364 Boron, 21, 37 -, abundance, 153 -, concentration and economic profit,

and economic profit, 413

301

37

404,413 - - , by evaporating, 154 - - , and geologic age, 408 -, constituent of oilfield waters, 153 -, emission spectroscopy method, 83 -, properties, 171 -, recovery, 415 Bradford Sand, 1, 2 Brine value, 414,416 Brine worth, 414, 416 Brines (see also Oilfield brines and Oilfield

waters), 13, 27, 117, 159, 160, 181, 213, 269,319,348,380,395,427,471

-, analyses, 272 -, classification, 225, 254, 257, 260, 267 -, commercial, 415,416 -, composition, 384 -, concentrations of elements, 395 -, containing high bromine, 391

Brines (continued)

- - , -, disposal, 411-417, 471 -, evaluation, 427 -, operations, 389, 395 -, ponds, 389,470 -, refinery, 390, 395, 396, 402, 403 -, stabilization, 380, 381 -, state regulations, 434 Bromide, 45, 162, 227, 360, 408, 410, 411 -, concentration, 361

- - , - - , - - , -, properties, 171 -, recovery, 41 5 -, recovery from Catesville, 391, 392 -, seaweed and coral, 228 -, sodium chloride relation, 162 -, titrimetric methods, 45 Bromine, 162, 391,398 -, abundance, 164 -, locations with high concentration, 410 -, occurrence, 163 -, recovery, 391 Buffers, 28 -, definition, 198 Bulk density, 363 Burner height device, 67

Cadmium, 152 -, abundance, 152 -, atomic absorption method, 65 -, colorimetric method, 103 -, properties, 153 -, sphalerite as carrier, 153 Calcite, 194, 198, 201, 208, 370, 371,

-, solubility, 370 Calcium, 40, 73, 140, 143, 283-289, 370,

-, abundance, 144 -, atomic absorption method, 65, 72, 75 -, complexometric method, 40 -, concentration, 289, 361 - - ,

- - ,

- - , -, constituent of oilfield waters, 141, 143

- - , high magnesium, 394 high sodium chloride, 392

- - , in brines, 162, 163 and economic profit, 404, 413 by evaporating, 163, 164 and geologic age, 408

461,471

395

in Bell Canyon formation waters, 329

and economical profit, 404, 413

and geologic age, 408

- - , and depth, 358

- - , by evaporating, 143,144

SUBJECT INDEX 487

Calcium (continued) -, locations with high concentrations, 409 -, properties, 141, 171 -, recovery, 415 -, solubility, 370 Calcium carbonate, precipitate, 144, 171 -, solubility, 202 Calcium sulfate, solubility, 144, 381 Calculated resistivity, 35 Calculating probable compounds, 125 Caledonian Group, 151 Calibration curve in flame spectrophoto-

Caliche evaporite deposits in Chile, 161 Cambrian, 213 -, concentrations of elements, 219 Capillary cell method, 182 Capitan Limestone, 320 Carbonate, 146, 152 -, depositional environments, 201 -, recovery, 415 Carbonated waters, dissolved elements, 198 Carbon dioxide, 50, 142,155, 170, 208,

-, determination, 50 Carboniferous age, 185 Carnallite, 162, 228 Case histories, geochemical, 308 Catesville field, 391 Celestite, 471 Cell preparation, resistivity measurements,

Central Basin platform, 320 Cesium, 141, 393 -, abundance, 141 -, constituent of oilfield waters, 134, 141 -, flame spectrophotometric method, 59,

-, properties, 134 Chebotarevk classification, 262, 267 Chelating agents, 40, 82, 96 Chemical analysis, 12 5 Chemical treatment of wells, 464 Cherokee Group, 311 Chile caliche evaporite deposits, 161 Chloride, 44 -, concentration, 238, 239 - - , - - ,

metric methods, 53

299

34

61

in Arbuckle formation waters, 332 in Bell Canyon formation waters,

and economic profit, 413 and geologic age, 408

328 - - , and depth, 357 - - , - - ,

Chloride, concentration (continued) - - ,

-, properties, 171 -, recovery, 415 -, titrimetric method (Mohr), 44 Chlorine, 161, 398 -, abundance, 161 Chlorinity, 24 Chocolate Bayou field, 245, 362 Chromatographic techniques, 181-185 Chromium, atomic absorption method, 65 Chrysotile, 442 Cinnabar, 151,152 Classification of oilfield waters, 253, 276 Classification systems, applications, 274-

Clastics, 200 -, depositional environments, 200 Clay minerals, 140, 209, 230, 240, 345,

430,433,441,442 -, authigenic, 201 Cleaning pipelines, 421 Coal ashes, 133 Colorado, 323 Colorimetric methods, interferences in, 93 Combination factor, 127 Compaction, 206,294 Compaction model, 344 Compatibility of oilfield waters, 367 Completion of disposal wells, 432 Composition of minerals, 441 Composition of oilfield waters, 213 Compressibility of rock and water, 428 Concentrating by ion exchange, 95 Concentrating brines, 240 Concentration change during evaporation,

134, 204,227, 229,231-234, 238 Concentration ratios in brines, 236, 237 Concentration versus proximity to an oil

Confining beds, critical pressure of, 429 Connate water, 3, 169, 194, 270, 271 Contamination of shallow aquifers, 434 Continental slope drill hole, 223 Copper, 150 -, abundance, 150 -, atomic absorption method, 65, 80 -, colorimetric method, 95, 96, 150 -, properties, 148 Cordellera Isabella, Nicaragua, 323 Core samples analysis, 310 Corrosion inhibitors, 465, 469

and relationships to other elements, 229-239

289

accumulation, 31 5

488 SUBJECT INDEX

Cretaceous age, 135, 154, 163, 215, 227,

-, lithium concentration, 135 -, magnesium concentration, 143 -, potassium concentration, 139 -, sodium concentration, 137 -, strontium concentration, 146 Cretaceous age rocks, brines from, 237 Cretaceous system, concentration of

elements, 213 Critical pressure, 429 Cymric fields, California, 152

229

Decarboxilization, 185 Deep well injection, 420 -, acceptable geologic areas, 425 Delaware Basin, 329 Delaware sand, 322, 323 Deltaic deposits, 201 Density, 172 Denver Basin, 343 Deposition, organic matter, 205 -, silica, 206 Depositional basin, 200 Depositional environments, 200, 201,203 Depth, 226 -, versus concentration, 357, 358 Description for water sample, 16 Deuterium, mass spectrophotometric

method, 91 Devonian age, 234 Devonian deposits, 317 Devonian system, 185, 213, 217, 261 Dexter formation, 335 Diagenesis, 133, 207, 208, 232, 245, 267,

Diagenetic water, 194 Dilution technique, 41 Disodium 1,2-~yclohexanediaminetetra-

acetic acid, 40 Disposal, 471 Disposal brines, 41 1 Disposal costs of brines, 422 Disposal systems, cost of, 437 Disposal well, 412, 424, 425, 432 -, cross section, 431 Disposal zone, 426,427 -, evaluation, 427 Dissolved gases, 12 Dissolved solids, 117, 216, 284-286, 323,

- in Bell Canyon formation waters, 3,327 Dnepr-Donets Basin, 313,318

346

325,362,410,419

Dolomite, 142, 194, 203, 234, 239 Dolomitization, 195, 203, 204, 208, 234,

Dolostone deposits, 234 Dow Chemical Company, 391,399 Dowex A-l,96 Drilling, 463 -, disposal wells, 432 Drilling fluids, 461, 463 Drilling muds, 8, 170, 343, 461, 463, 468 Drill-stem test, 8, 12, 181

Earthquakes, 434 East Texas Basin, 224,232,272, 283-

East Texas field, 420, 424 East Texas Salt-Water Disposal Company,

Economic value of brine, 403 Eh, 14, 19, 29, 166, 170, 199 Eh, unfiltered and filtered petroleum

Eh/pH plot, 159, 168, 170, 199 Electric log, 153, 341 -, cross section of southwest Louisiana,

Elements, minor, 220 Emission spectroscopy, 83 -, calibration curve, 88 -, emulsion calibration curve, 87 -, gamma curve, 87 Eocene age, 104,114, 130, 152, 167,185,

Eolian deposits, 160 Epm (equivalents per million), 24, 274 Equivalents per million (epm), 24, 126,

Erosion, 198 Escape routes, 429 Evaluation, economic, 402 Evaporites, 137, 223, 238, 239 -, basin, 203 -, depositional environments, 203 Exchange reactions, 211

238

288, 321

423

producing wells, 320

349-352

212

269,275

Fatty acids, 183, 315 -, chromatographic techniques, 184 - in sea water, 184 Feldspar, 138,140, 242,433 Ferromagnesian, 142 Fertilizers, 397 Fertilizer production, flowsheet for, 397 Field sampling methods, 273

SUBJECT INDEX 489

Filtered petroleum-producing wells, pH

Flame spectrophotometric methods, 53 Florida, 333-335 Flow diagram of solubility equipment,

Flow line, 13 Flowsheet for descaled sea water and

fertilizers, 397 Flowsheet for fresh water and valuable

elements, 401 Fluid mechanics, 320 Fluid travel, 433 Fluoride, colorimetric method, 109 Fluorine, abundance and properties, 161 Fluorite, 161 Fluorspar, 124, 161 Ford field, Texas, 323 Formation damage, 368 Formation interval tester, 10 Formation pressure, 12 Fossil water, 3 Freezing point, 172 Fresh-water conversion, 401 Fresh-water production, flowsheet for,

Fresh-water well, 471, 472 Fulvic acid, 185

Gas analysis, 12 Gas chromatographic methods, 147, 181,

Gases in petroleum, reservoir waters, 271 Gas/oil ratio, 11 Gasoline Association of America, 186 Gaslwater relationships, 256 Generation and migration, 295 Genetic indicators, 336 Genetic types of waters, 260 Geochemical case histories, 308 Geochemical methods, exploration, 307 Geochemistry versus geologic environment,

Geologic maps, 426 Geopressure, 343 Geopressured reservoirs, 343 Geopressured zones, 343, 362 Georgia, 335 Geostatic ratio, 344 Gibbsite, 155 Glass electrode, 27 Graphic plots, 128 Graphite, 295

and eH values, 320

448

401

182,184,185

266

Gravimetric methods, 24, 114 Green River formation waters, alkalinity,

Groznyv oil district, 247, 302 Gulf Coast area, 128, 129, 181, 343, 346,

Gulf Coast Basin, 243 Gulf Coast shales, 179, 240, 360 Gypsum, 194, 203,204, 235,317,471

156

360

Hackberry field, Louisiana, 304 Halite, 162, 163, 194, 203, 227-229 Heaving shales, 462 Holocene age, 165 Honaker Trail formation, 321 Host rock, 133 Hot brines, 227 Humic acids, 182,184,185,186 -, chromatographic technique, 185 Hydrocarbons, 12, 178, 194, 211, 298,

-, accumulation, 178, 298 -, alkanes, 309 -, alteration, 299, 301 -, aromatic, 298, 309 -, bacterial attack, 302 -, biological degradation, 301 -, compaction, 294 -, containing nitrogen, 182 -, diffusion, 180 -, generation-migration, 295, 296, 362 -, hydrochemical indicators, 258 -, maturation, 295 -, migration, 299, 314, 316 -, in natural gas, 180 -, origin, 57 -, in petroleum, 181 -, in recent sediments, 244 -, in sedimentary rocks, 245 -, solubility, 178, 179, 296 -, water washing, 300 Hydrochemical anomalies, 308, 316 Hydrochemical indicators, hydrocarbons,

Hydrodynamic gradients, 295,325 Hydrodynamic potential, 382 Hydrodynamic zones, 266 Hydrogen chloride, free, 120 Hydrogen sulfide, 51,156,159, 309, 468 -, method for determination, 51 Hydrogeochemical exploration, 31 1 Hydrogeochemical research and exploration

310

258

313

490 SUBJECT INDEX

Hydrolysate, 139, 141, 171 -, rocks, 195,197 -, sediments, 141 Hydrolysis reactions, 15 Hydrosphere, 193 Hydrothermal equipment, 447

Igneous rocks, average composition,

Illinois Basin, 243 Illite, 138-140, 209, 230, 239, 240, 269,

441,443,444 Index base exchange (IBE), 267,270,

271,283 Inhibitors, 465 -, chemical, 465 -, corrosion, 465, 469 Injection of subsurface brines, 420 Injection well, 424 Instrumental methods, 20 Interior regions of the earth, 193 Internal standard solution in emission

Interstitial water, 3, 194, 206, 207, 209 Iodate, 166 Iodide, 45, 110, 226 -, colorimetric method, 110 -, concentration and economic profit,

196

spectroscopy, 84

404,413 - - , by evaporating, 166 - - , -, properties, 171 -, recovery, 390, 415 -, seaweed and coral, 228 -, titrimetric method, 45 Iodine, 164, 390, 398 -, concentration by algae, 165 -, recovery from brines, 390 Iodoargyrite, 164 Iodoembolite, 164 Ion association, 225 Ion exchange, 230 -, concentrating by, 95 Ionic potential, 133, 142,171 Ionic radii, 171 Ionization interferences, 66 Iron, 149 -, abundance, 149 -, atomic absorption method, 65, 79 -, colorimetric method, 94, 95 -, emission spectroscopy method, 83 -, properties, 148 Isotopic fractionation, 243

and geologic age, 408

Jurassic age, 135, 154, 163, 227, 229 -, lithium concentration, 135 -, magnesium concentration, 143 -, potassium concentration, 139 -, sodium concentration, 137 -, strontium concentration, 146 Jurassic system, 213, 214 Juvenile water, 3, 195

Kainite, 162 Kansas brines, 226 Kaolinite, 155, 184, 209, 230, 269, 441,

Kazhim stratigraphic well, 185 Kerogen, 205, 309, 311

Lacustrine deposits, 200 Lanthanum, 83,84 Lea County, New Mexico, 320 Lead, 152 -, abundance, 152 -, atomic absorption method, 65, 81, 82 -, colorimetric method, 95, 99 -, dithizone method, 99 -, ion exchange, 99 -, isotope ratio, 318 -, properties, 119, 148, 152 Lepidolite, 140 Limestone, 51, 197, 201, 235, 320 -, dolomitization of, 204 Liquid exchange, chromatography, 182 Lithium, 133, 392 -, abundance, 133 -, atomic absorption method, 68 -, concentration and economic profit,

by evaporating, 135, 136 and geologic age, 408 in Mississippian and Pennsylvanian

in Tertiary, Cretaceous and Jurassic

443,444

404,413 - - , - - , - - ,

age formation waters, 136

age formation waters, 135 - - ,

-, constituent of oilfield waters, 133 -, flame spectrophotometric method, 54 -, properties, 133, 134, 171 -, recovery, 415 -, toxicity, 133 Lithology, 225 Lithophile, 147 Lithosphere, 193 Locations of valuable brines, 406 Louisiana, 135, 142, 144, 146, 163, 231,

333,335,349-352, 359-361

SUBJECT INDEX 491

Magnesium, 40,142, 283-289, 394 -, abundance, 142 -, atomic absorption method, 65, 71, 74 -, complexometric method, 40 -, concentration, 289, 238 , , and geologic age, 408

- - ,

_ _ and economic profit, 404, 413 - -

, in Mississippian and Pennsylvanian age formation waters, 143

age formation waters, 142 - _ , , in Tertiary, Cretaceous and Jurassic

-, constituent of oilfield waters, 141, 149 -, locations with high concentration, 410 -, properties, 141, 171 -, recovery, 394, 415 -, specific gravity versus concentration,

Magnesium ammonium phosphate, 396 Manganese, 40, 149 -, abundance, 149 -, atomic absorption method, 65, 78 -, emission spectroscopy method, 83 --, flame spectrophotometric method, 61 -, properties, 148 Maracaibo Basin, Venezuela, 303 Mass spectrophotometric methods, 91 Maturation, 295 Maximum worth, 414 Membrane-concentrated brines, 240 Membrane effect, 240 Metals, 65 Meteoric water, 194, 227, 253, 267, 270,

Methane, 178, 181, 295, 300, 316 -, measurement of, 12,180,181 -, solubility, 180 Mercuric iodide in brackish water, 152 Mercury, 151 -, abundance, 151 -, atomic absorption method, 65 -, properties, 151 Mexia-Talco Fault, 321 Mica, 140, 232, 433 Michigan, 361 Michigan Basin, 205, 226, 243, 359, 360 Microcline, 140 Microphotometer criteria, in emission

Micropipet, 41 Microsyringe-evaporating flask, 186 Miersite, 164 Migration, 2, 293, 295 Milligram per liter (mg/l), 25, 269, 275

72

271,289

spectroscopy, 85

Mineral-acid acidity, 37 Minerals, formation, 234 -, recovered from saline waters, 392 Minor elements, 220 Miocene age, 165 Mississippi, 333, 335 Mississippian age, 135, 145, 154, 164, 166,

-, lithium concentration, 136 -, magnesium concentration, 143 -, potassium concentration, 139 -, sodium concentration, 138 -, strontium concentration, 146 Mississippian system, 216 Mixed salts, 395 Mixing of subsurface waters, 382 Molecular hydrogen, 180 Montmorillonite, 140, 155, 184, 209, 238,

Mud filtrate, 11

213

240, 294,360,441,445

Nalco Chemical Company, 186 Naphthenic acids, chromatographic

National Bureau of Standards, 23 Natural gas, 178, 307, 309, 310 -, deposits, 178 Neogene age, 245 Nernst equation, 167 New Mexico, 224 Nickel, 98 -, atomic absorption method, 65 -, colorimetric method, 95, 98 -, ion exchange, 95 Nitrate nitrogen, colorimetric method, 107 Nitrogen containing hydrocarbons, 182 Nitrogen-free organic compounds, 178 Nodules of manganese oxide, 149 Nontronite, 441, 442, 445,446 Normal pressure, 359 North Carolina, 335

technique, 185

Ohm meter, 32 Oilfield brines (see also Brines and Oilfield

waters), 25, 193, 219, 273, 389, 422 -, analysis, 25, 272 -, disposal, 389, 420 -, economics, 422 -, field sampling methods, 273 -, origin, 193 -, pollution, 468 Oilfield waters (see also Brines and Oilfield

brines), 215, 226, 367, 372, 374, 389

492 SUBJECT INDEX

Oilfield waters (continued) -, altered, 242, 243 -, analysis, 272 -, classification, 253 -, compared to sea water, 227 -, concentration of elements, 217, 238 -, incompatibility, 367 -, physical properties, 133 Oil in water, 186 -, determination, 186 Oklahoma, 136, 139, 143, 145, 146, 157,

164,166,335 Optical density, 94 Ordovician age, 213, 218, 345 Organic acids, 186, 216, 311, 312, 316 -, chromatographic technique, 186 Organic compounds, 156,178,184-186,

188,205,317,433 -, deposits, 293 -, in oilfield brines, 188 -, in petroleum-associated waters, 186 -, in saline waters, 177 -, in subsurface water, 185 Organic matter, deposition, 205 -, in sea water, 178 Origin of brines, 219 Origin of oilfield waters, 193 Osmotic pressure, 173 Oxygen, 47, 91,158 -, method for "0 -, solubility, 157 -, titrimetric method, 47 -, Winkler method, 47

Paleozoic age, 160 Palmer's classification, 254, 256 Paradox Basin, Utah, 224, 321 Paraffins, 310 Parts per million (ppm), 24, 25 pE, 166 Pedosphere, 193 Pennsylvanian age, 135, 145, 154, 164,

166,238 -, lithium concentration, 136 -, magnesium concentration, 143 -, potassium concentration, 139 -, sodium concentration, 138 -, strontium concentration, 146 Pennsylvanian system, 213, 215 Permeability, 207, 303, 325, 345, 430 -, artificial fracturing, 430 -, calculations, 11 Permian age, 213, 214, 320, 322

Permian Basin, 473 Petroleum, 195, 210, 211, 244, 295, 299,

-, accumulation, 178, 225, 298, 309, 310,

-, alteration, 293, 299, 304 -, compaction, 294 -, degradation, 301 -, exploration, 307, 320 -, generation, 210, 212, 219, 295, 297,

-, migration, 211, 295, 297 Petroleum Abstracts, 307 pH, 10,14,15,27,37,168-170,198,

-, temperature and, 28, 29 -, unfiltered and filtered petroleum-

producing wells, 320 pH meter, performance characteristics, 29 Phenol, chromatographic technique, 181 Phosphate, 105 -, colorimetric method, 105, 106 Phosphorus, 158 Photosynthesis, 165, 206 -, by algae, 165 Pinkerton Trail Limestone, 320 Plasma arc, 83,84 Plate development in emission spectroscopy,

Playa deposits, 223 Pleistocene age, 150 Plugging of formations, 432 Polarization, 171 Pollution, 466-468 -, of uppersand by well blowout, 466 Porosity, 207, 303, 345 Porosity reduction, 345 Potassium, 138, 393 -, abundance, 138 -, atomic absorption method, 70 -, concentration and economical profit,

- - , by evaporating, 139

310,315

313

310

207

85

404,413

- - , - - ,

-, -, in Tertiary, Cretaceous and Jurassic

-, constituent of oilfield waters, 134, 138 -, depletion, 140, 240 -, flame spectrophotometric method, 58 -, properties, 134, 171 -, recovery, 415

and geologic age, 408 , in Pennsylvanian and Mississippian



SUBJECT INDEX 493

Potentiometric surface map, 331 Powder River Basin, 303, 343 Precipitates, 432 Precision, 20 Precursors, 210, 212, 216, 293, 297, 311 Preliminary evaluation, marketing research,

Pressure equalizer, 12 Pressure-distance-time relationship, 430 Pressure head, 11 Pressure relationships, 433 Pripvatsky Depression, 317 Produced water, 4 Production, 467

405

Quality control, 19, 20 Quartz, 194,201, 209,433 Quartzite, 155 Quebracho, 464

Radioactive anomalies, 318 Radioactive compounds, 317 Radium, 318 -, anomalies, 318 -, concentration, 317 Radium/uranium ratio, 317-320 Reacting values, 126 Reaction coefficients, 126 Reagent chemicals, 23 Reagent solutions, 23 Recovery, 4, 390, 392,415,474 Redox potential (Eh, pE), 29, 157, 166 Reef carbonates, 202 Regressive marine deposits, 200 Reistle diagram, 131 Replacing power of ions, 230 Reporting analytical results, 25 Reservoir transmissibility, 428 Residual salt concentration, 470 Resistivity, 32, 33, 35, 317 Reverse exchange, 233 Reverse osmosis, 240, 241 Rio Bravo fields, California, 152 Rocky Mountain area, 156, 343 Rodessa formation, 284, 286-288 Rounding-off numbers, 26 Rubidium, 59, 140, 393 -, abundance, 140 -, constituent of oilfield waters, 139, 140 -, flame spectrophotometric method, 59,

-, properties, 134 -, standard-addition technique, 61

61

Saber field, 323, 326, 330 Sabkha sediments, 224 Salinity, 24, 226, 254, 257 -, concentration, 333-335 Salt water disposal, 4 12 Salting out effect, 179 Sample container, 16 Sample treatment, 22 Sampling, 8 -, methods, 273 Sand dike, 345 Sandstone, 152,158, 201, 345 San Juan Basin, 224, 343 San Juan Mountains, 321 Saturated hydrocarbons, 314 Scale, 368, 370 Scale inhibitors, 469 Schoeller’s system,.267, 268 Searles Lake, 135 Sea water, 137, 143, 149, 152, 158, 194,

215,227,245,392, 394,402 -, average composition, 195 -, composition, at dolomitization or

-, -, at gypsum precipitation, 234 -, fatty acids in, 184 Sedimentary basins, 212,406 Sedimentary rocks, 11, 51,135,140,147,

-, average composition, 196 Sediment compaction, 206 Sediment diagenesis, 207 Seleniferous vegetation in the U.S., 160 Selenium, abundance, 160 -, colorimetric method, 111 Sensitivity for metals in atomic absorption

Separation of gas, oil and brine, 400 Serpentine, 446,449,453,458 -, silicon solubility from, 453-458 Shales, 141,152, 158,179, 206, 240, 245,

360,430 Shallow aquifers, contamination of, 434 Siderite, 471 Significant figures, 25 Silica, 107 -, abundance, 156 -, analytical procedure when dissolved,

-, colorimetric method, 107 -, deposition, 206 -, spectrophotometric method, 107 Silicate, 149, 240,443

bacterial reduction, 235

195,210,245

methods, 65

442

494 SUBJECT INDEX

Silicate (continued) -, chemical composition, 441 -, solubility, 441 Silicon, concentration, 443-446 -, solubility, 458 - - , Silurian age, 213, 218 Silver, atomic absorption method, 65 Simpson Sand, 345 Sloughing, 462 Smackover formation, 12, 135, 230, 232,

-, brines, 233, 235, 236, P38, 240, 392 -, -, concentration ratios, 236 Smackover Limestone water, drill-stem

Sodium, 136, 283, 284, 286, 287, 289,

-, abundance, 137 -, atomic absorption method, 65, 68 -, concentration, 289, 361 - - , - - , - - ,

- - ,

-, constituent of oilfield waters, 134, 136 -, determination by calculation, 116 -, flame spectrophotometric method, 57 -, locations with high concentrations, 409 -, properties, 134,171 -, recovery, 415 Sodium chloride, 33, 392 -, bromide relation, 163 -, resistivity, 33 Solids, dissolved (see also Dissolved solids),

specific gravity and concentration, 36 -, -, in brines and sea water, 413 Solubility, 144, 178, 296, 370, 372, 375-

Solubility equipment, flow diagram, 448 Source rocks, 309 South Carolina, 335 South Caspian Basin, 316 South Pyote field, Texas, 323 Specific gravity, 35, 410 -, versus concentration for magnesium

solution, 72 -, chloride solution, 45 Specific heat, 172 Spent acid, 118 Sphalerite, 153

, from serpentine, 453-458

234,238,239, 391

test, 12

360

and economic profit, 404,413 and geologic age, 408

, in Pennsylvanian and Mississippian

, in Tertiary, Cretaceous and Jurassic age formation waters, 138


377,382,441

Stable-isotopes analysis, 15 Standard-addition technique, 50, 55, 57,

Standard solutions, 23 State regulations, 434 Stiff diagram, 131 Stinkfluss, 161 Stratigraphic interval, 11 Stratigraphic problem, 325 Stratigraphic traps, 312, 323, 325, 326 Strontium, 62, 76, 83, 145, 385 -, abundance, 145 -, atomic absorption method, 76 -, concentration, 239 - - , - - , -, -, in Pennsylvanian and Mississippian

-, -, in Tertiary, Cretaceous and Jurassic

-, constituent of oilfield waters, 141, 145 -, emission spectroscopy method, 83 -, flame spectrophotometric method, 62 -, properties, 141, 171 -, recovery, 415 Strontium sulfate, 385 -, concentration, 145 -, concentration and ionic strength, 378 -, saturation in waterflood makeup brines,

383 -, solubility, 145, 370, 372, 375-377,

379, 381,383,385 Structural trap, 312 Structure of minerals, 441 Subsurface brines, 143, 159, 225, 315

-, analyses, 321 -, classification, 216, 234 -, contents, 159,313-315 -, hydrochemical anomalies, 316 -, maps, 320 -, mixing, 382 -, properties, 214 -, sampler, 9, 224 Subsurface disposal, 419, 421, 426, 471 Subsurface waters, 7,9, 135, 253, 289,

Sugars, chromatographic technique, 181 Sulfate, 114, 385 -, concentration and economic profit,

-, determination, 53 -, gravimetric method, 114

60,61

and economic profit, 404 and geologic age, 408



420

382

413

SUBJECT INDEX 495

Sulfate (continued) -, properties, 171 -, recovery, 415 -, reduction, 208, 317 -, solubilities in synthetic brines, 379 Sulfide, 51 -, determination, 52, 53 Sulfur, 52, 159 -, abundance, 159 -, concentration and economic profit,

401 - - , and geologic age, 408 -, determination, 52 Sulin’s classification, 257, 259 Suiyosei-ten’nengasu, 178 Surat Basin, 245 Surface tension, 173 Suspended solids, 31 Sylvania formation, 226 Sylvite, 139, 163, 228 Synthetic brines, 27, 383

Tar mats, 299 Tax incentives, 436 Temperature, 15, 29, 212 Temperature gradient, 212 Ternary diagrams, 288 Tertiary age, 154, 163, 212, 213, 227,229 -, lithium concentration, 135 -, magnesium concentration, 142 -, potassium concentration, 139 -, sodium concentration, 137 -, strontium concentration, 146 Tertiary age rocks, brines from, 237 Texas, 333-335 Thermal conductivity, 172 Thermodynamic equations, 449 Thiosulfate, determination, 53 Tickell diagrams, 128 Titrimetric analysis, 24, 37 Toluene, 181, 314 Transgressive marine deposits, 200 Transmissibility, 428 Traps, 299, 312, 326 -, stratigraphic, 299, 312, 323 -, structural, 312 -, types, 247 Treatment facilities, 420, 421 Troilite, 471 Turbidity, 31 Tuscaloosa formation, 335

Uinta Basin, 157, 210, 212 Uncompahgre Uplift, 321 Underground waste disposal, 434 Unfiltered petroleum producing wells,

pH and eH values, 320 Units for water analysis, 24 Unsaturated hydrocarbons, 314 Unstable properties, 15 Upper Cretaceous, 321- Uranium, 318 Utah, 157

Valuable brines, 406, 407 Valuable elements, 474 -, production, flowsheet for, 401 Value of brine, constituents, 415 Value of dissolved chemicals versus depth,

Value estimate, 414 Vapor pressure, 172 Viscosity, 173 Valence, 171 Volcanic waters, 58 Volga region, 180 Vorobyevite, 140

403

Waste disposal, 471 Waste disposal well, 472 Water, compatibility, 12, 290 -, compressibility, 428 -, properties, primary, 214, 261 -, washing, 300 Water analysis, 24, 130, 321 -, interpretation, 130, 131 Water and hydrocarbons, 311 Water exchange coefficient, 265 Waterflood makeup brines, 383 Waterflooding, 4, 369, 420, 473 Waters, composition, 280 -, connate, 3, 194 -, diagenetic, 194 -, formation, 195 -, fossil, 3 -, interstitial, 3, 194 -,juvenile, 3, 195 -, meteoric, 194 -, subsurface (see also Subsurface waters),

Weathering, 197, 198, 200, 262 -, cycles and types of products, 263 Well blowout, pollution by, 466 Wellbore, 368 Wellhead, 14, 15

297

496 SUBJECT INDEX

Wellhead sampling, 13 Well treatment, 13 -, pH for determining of, 170 Wilcox formation, 331-334 Williston Basin, 129 Woodbine (Dexter) formation, 335 Worth estimate, 414

Zinc, 80, 101, 151 -, abundance, 151 -, atomic absorption method, 65, 80 -, colorimetric method, 101 -, ion exchange, 151 -, properties, 148

X-ray diffraction, 201, 471