the impact of oil chemistry on heavy-oil solution gas drive and

THE IMPACT OF OIL CHEMISTRY ON

HEAVY-OIL SOLUTION GAS DRIVE AND

FRACTURE RECONSOLIDATION OF

DIATOMITE DURING THERMAL

OPERATIONS

A THESIS

SUBMITTED TO THE DEPARTMENT OF

ENERGY RESOURCES ENGINEERING

STANFORD UNIVERSITY

IN PARTIAL FULFILLMENT OF THE REQUIREMENTS

FOR THE DEGREE OF

MASTER OF SCIENCE

Jing Peng

August 2009

c© Copyright by Jing Peng 2009

All Rights Reserved

ii

I certify that I have read this report and that, in my opinion, it is fully

adequate in scope and quality as a report for the degree of Master of

Science.

Anthony Kovscek Principal Adviser

I certify that I have read this report and that, in my opinion, it is fully

adequate in scope and quality as a report for the degree of Master of

Science.

Louis Castanier

Approved for the University Committee on Graduate Studies.

iii

Abstract

Two different unconventional resources and two different recovery processes are stud-

ied in this work. The first is heavy oil recovered by solution gas drive. The second is

steam injection into low permeability diatomite reservoir for conventional and heavy-

oil recovery.

The role of oil chemistry on heavy-oil solution gas drive is studied. Measurements

of the concentration of organic acid and base groups as well as asphaltene content of

crude oil are combined with data from laboratory-scale heavy-oil solution gas drive

experiments. We find that significant asphaltene content as well as substantial acid

and base numbers are indicators of whether oil is foamy. The acid number is the

amount of potassium hydroxide in mg needed to neutralize the acid groups in 1 g

of crude oil, whereas the base number is the amount of potassium hydroxide in mg

that is required to neutralize the titrant used in an acid titration of 1g of crude oil.

The partitioning of acid and base groups between the asphaltene fraction and de-

asphalted oil is also studied. Organic acid and base groups are clearly present in the

asphaltene fraction. We investigate the lifetime of single foam films of crude-oil and

asphaltene solutions. Transparent micromodels etched with a sandstone pore network

and containing gas dispersed within the oil are also used to investigate the correlation

of acid number, base number, and asphaltene content with gas-bubble coalescence.

The results show that a high concentration of asphaltene that exhibits acid and base

functional groups tends to increase foamability and film life time of gas-crude-oil

dispersions. The deasphalted fraction is not foamy despite possessing significant acid

and base number. We conclude that acid and base in asphaltene are the source of

interfacial properties. Asphaltene content and acid/base number of asphaltene are

v

important factors accounting for the stabilization of dispersed gas bubbles in foamy

oil.

Additionally, factors related to the silica dissolution process and the mechanism of

fracture reconsolidation are studied. Short-time fluid injection was conducted to study

the influence of pH, temperature, salinity, and metal ions on silica dissolution. The

experimental results suggest that temperature and pH are the two most important

factors, in agreement with the literature. Salinity can also affect the dissolution

process, while the influence of metal ions can be neglected. The influence of steam

was also studied, indicating that the presence of steam hinders silica dissolution of

diatomite. Based on the results of the silica dissolution study, an optimal condition for

dissolution was obtained and used in hot-fluid injection experiments with relatively

long periods of time. With longer experiment time, more aspects of silica dissolution

were studied. At elevated temperature, strong silica dissolution happens even under

very acidic conditions. Wormholes form during the injection of hot alkaline fluid if the

basic pH is maintained within rock. As a result, permeability is enhanced and porosity

of the inlet area also increases. Several fractured cores were prepared to study the

mechanism of fracture reconsolidation. Fractures were oriented lateral to and normal

to flow. Fractured cores were subject to different brine formulations at different

temperatures and confining pressures. Fracture healing and rock reconsolidation were

observed when hot fluid was injected at elevated temperature. The results of other

tests suggest that both silica dissolution and confining stress are necessary for fracture

reconsolidation. The proposed mechanism for this process has three steps. The first

step is aqueous silicate production by silica dissolution. In the next step, silicate

gelation happens within the pore space and fracture. Confining stress is important

in the last step. It enhances the transformation of silica gel to solid silica. Given

enough experiment time, fracture reconsolidation happens.

vi

Acknowledgement

I would like to express my gratitude to all those who gave me the possibility to

complete this thesis.

My two years at Stanford have been so rewarding. I am very glad that I can

work on the areas I am really interested in. My greatest acknowledgement goes to

my advisor, Dr. Anthony Kovscek. Professor Kovscek has been a consistent source

of knowledge, encouragement and advice throughout this thesis work. Without him,

I would not have finished such inspiring research work.

My sincere thanks also go to Dr. Tom Tang, who have given me a lot of help

on the experiment work. I also would like to express my gratitude to Dr. Louis

Castanier, who provided laboratory support for my study. I also would like to thank

Dr. Cynthia Ross for SEM analysis.

Thanks are due to Bolivia Vega, who has shared with me lots of valuable experi-

ence. My thanks also go to many other colleagues in SUPRI-A. Their help has made

my life at Stanford much easier and happier.

I would like to take this opportunity to thank my family. My parents have en-

couraged and supported my education since the very beginning. Their unconditional

support and love have guided me through each and every step along the way. I would

like to express my greatest gratitude to my husband, for being supportive, patient

and helpful all the time.

vii

Nomenclature

AN acid number

API The American Petroleum Institute gravity

beq the volume of titrant (ml) consumed by spiking solution only at the equivalent

point

BN base number

CHPA Cyclohexanepropionic acid

k+ Rate constant of silica dissolution

N the mole concentration (mole/L) of titrant

Veq the volume of titrant (ml) consumed by crude oil sample and spiking solution

at the equivalent point

Woil the weight (g) of crude oil sample

ix

Contents

Abstract v

Acknowledgement vii

Nomenclature ix

List of Tables xiii

List of Figures xvi

1 Introduction 1

2 Oil chemistry and heavy-oil solution gas drive 5

2.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5

2.2 Experimental . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

2.2.1 Materials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7

2.2.2 Apparatus . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8

2.2.3 Acid number measurement . . . . . . . . . . . . . . . . . . . . 9

2.2.4 Base number measurement . . . . . . . . . . . . . . . . . . . . 9

2.2.5 Asphaltene content measurement . . . . . . . . . . . . . . . . 10

2.2.6 Single film life time . . . . . . . . . . . . . . . . . . . . . . . . 10

2.2.7 Micromodel experiment . . . . . . . . . . . . . . . . . . . . . 11

2.3 Results and discussion . . . . . . . . . . . . . . . . . . . . . . . . . . 11

2.3.1 Chemical characterization . . . . . . . . . . . . . . . . . . . . 12

2.3.2 Film stability . . . . . . . . . . . . . . . . . . . . . . . . . . . 13

xi

2.3.3 Viscosity . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

2.4 Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22

2.5 Conclusions and future work . . . . . . . . . . . . . . . . . . . . . . . 22

3 Silica dissolution & fracture reconsolidation 25

3.1 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

3.2 Silica dissolution and precipitation in diatomite . . . . . . . . . . . . 27

3.2.1 Silica dissolution . . . . . . . . . . . . . . . . . . . . . . . . . 27

3.2.2 Silica precipitation . . . . . . . . . . . . . . . . . . . . . . . . 28

3.2.3 Gelation of silicate and colloidal silica . . . . . . . . . . . . . . 28

3.3 Experimental study . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

3.3.1 Materials . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

3.3.2 Experimental apparatus . . . . . . . . . . . . . . . . . . . . . 31

3.3.3 Determination of silica concentration . . . . . . . . . . . . . . 35

3.3.4 Procedures . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 37

3.4 Silica dissolution of diatomite . . . . . . . . . . . . . . . . . . . . . . 38

3.4.1 Influence of pH . . . . . . . . . . . . . . . . . . . . . . . . . . 38

3.4.2 Influence of salinity . . . . . . . . . . . . . . . . . . . . . . . . 41

3.4.3 Influence of temperature . . . . . . . . . . . . . . . . . . . . . 44

3.4.4 Influence of metal ions . . . . . . . . . . . . . . . . . . . . . . 46

3.5 Fracture reconsolidation . . . . . . . . . . . . . . . . . . . . . . . . . 46

3.6 Discussion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 66

3.7 Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 70

3.8 Conclusions and future work . . . . . . . . . . . . . . . . . . . . . . . 71

xii

List of Tables

2.1 AN/BN and asphaltene content . . . . . . . . . . . . . . . . . . . . . 12

2.2 AN and BN of de-asphalted oil and asphaltenes . . . . . . . . . . . . 14

2.3 The life time of dispersed gas bubbles in micromodel experiments. . . 17

3.1 The comparison between gelations of silicate and colloidal silica. . . . 29

3.2 Aqueous solutions used in pH tests of silica dissolution. . . . . . . . . 39

3.3 Aqueous solutions used in salinity tests of silica dissolution. . . . . . . 42

3.4 Aqueous solutions used in temperature tests of silica dissolution. . . . 44

3.5 Aqueous solutions used in metal ion tests of silica dissolution. . . . . 48

xiii

List of Figures

1.1 World wide distribution of oil . . . . . . . . . . . . . . . . . . . . . . 2

2.1 Life time of single films formed from asphaltene solutions. . . . . . . 15

2.2 Micromodel images of bubble coalescence w/o vacuum . . . . . . . . 16

2.3 Micromodel images of bubble colescene w/ vacuum . . . . . . . . . . 17

2.4 Hypothetical structure of asphaltene . . . . . . . . . . . . . . . . . . 19

2.5 Asphaltene content versus acid number of study samples. . . . . . . . 20

2.6 Asphaltene content versus base number of study samples. . . . . . . . 20

2.7 Life time of single films versus viscosity . . . . . . . . . . . . . . . . . 21

3.1 Diatomite outcrop sample. . . . . . . . . . . . . . . . . . . . . . . . . 30

3.2 SEM image of diatomite sample. . . . . . . . . . . . . . . . . . . . . . 31

3.3 Experimental set-up . . . . . . . . . . . . . . . . . . . . . . . . . . . 32

3.4 Picture of experimental set-up . . . . . . . . . . . . . . . . . . . . . . 33

3.5 Coreholder assembly. . . . . . . . . . . . . . . . . . . . . . . . . . . . 34

3.6 Color standard solutions for silica concentration determination . . . . 36

3.7 Effluent pH for tests with variable injected pH. . . . . . . . . . . . . . 40

3.8 Effluent silica concentration for tests with variable injected pH. . . . 40

3.9 Change of permeability for pH tests . . . . . . . . . . . . . . . . . . . 41

3.10 Effluent pH for salinity tests. . . . . . . . . . . . . . . . . . . . . . . . 42

3.11 Effluent silica concentration for salinity tests. . . . . . . . . . . . . . . 43

3.12 Change of permeability for salinity tests . . . . . . . . . . . . . . . . 43

3.13 Effluent pH for temperature tests. . . . . . . . . . . . . . . . . . . . . 45

3.14 Effluent silica concentration for temperature tests. . . . . . . . . . . . 45

xv

3.15 Permeability change for temperatue tests . . . . . . . . . . . . . . . . 46

3.16 Effluent pH at 180◦C (w/ and w/o steam). . . . . . . . . . . . . . . . 47

3.17 Effluent silica concentration at 180◦C (w/ and w/o steam). . . . . . . 47

3.18 Effluent pH for metal ion tests. . . . . . . . . . . . . . . . . . . . . . 48

3.19 Effluent silica concentration for metal ion tests. . . . . . . . . . . . . 49

3.20 The fractured core used in test 1 . . . . . . . . . . . . . . . . . . . . 50

3.21 Change of effluent pH for test 1. . . . . . . . . . . . . . . . . . . . . . 51

3.22 Change of silica concentration for test 1. . . . . . . . . . . . . . . . . 51

3.23 Permeability change for test 1. . . . . . . . . . . . . . . . . . . . . . . 52

3.24 CT images for test 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . 53





3.29 The wormholes formed in test 2. . . . . . . . . . . . . . . . . . . . . . 58

3.30 Porosity distribution before and after test 2. . . . . . . . . . . . . . . 58





3.35 The diatomite core before and after test 3. . . . . . . . . . . . . . . . 62

3.36 Relationship between effective stress and permeability for test 3. . . . 63

3.37 Porosity distribution before and after test 3. . . . . . . . . . . . . . . 63

3.38 The diatomite core before and after test 4. . . . . . . . . . . . . . . . 65


3.40 Diatomite core in test 5 . . . . . . . . . . . . . . . . . . . . . . . . . 67


xvi

Chapter 1

Introduction

Unconventional resources are usually more difficult to recover than conventional re-

sources. Unconventional resources include hydrocarbon located in tight and low per-

meability rock formations, and oil with high viscosity and high density. The estimated

resource of bitumen, heavy oil and shale oil is around 7.5 trillion barrels, which is

much more than that of recoverable conventional oil (Stark et al. 2007). Although

unconventional resources account for a significant portion of world oil reserves, their

geological or fluid properties present great challenges for oil recovery, both technically

and economically. With the increasing demand for oil worldwide, unconventional oil

is an important source to supplement conventional oil supplies. The study of oil re-

covery from unconventional resources is of particular interest. The purpose of our

study is to better understand the oil recovery for two different unconventional re-

sources. One is about heavy-oil recovery under solution gas drive, the other is about

steam injection into diatomite reservoir.

Heavy oil and bitumen are characterized by their high viscosity (> 100cp) and

high density (< 20◦API). The bitumen and heavy crude oil is around 5.4 trillion

barrels, which is five times more than that of conventional oil (Figure 1). Thus,

heavy oil and bitumen are the greatest possible sources to meet the increasing need

for oil. However, the recovery efficiency of heavy oil and bitumen is much lower than

that of conventional oil, due to their high viscosity. But for some heavy-oil reservoirs

under solution gas drive, the recovery is much greater than predicted (Huang et al.

1

2 CHAPTER 1. INTRODUCTION

1998, De Mirabal et al. 1996; 1997, Maini 1996). It is observed during depletion that

the gas phase remains as dispersed bubbles. As a result, the relative permeability

of gas remains low (Tang and Firoozabadi 2003, Tang et al. 2006b). Because there

is a significant fraction of the gas remaining in the reservoir, the drive energy is

preserved. Accordingly, the rate of pressure decline is lower than that estimated by

conventional analysis (Tang et al. 2006b). Because of the presence of dispersed gas

bubbles, this kind of heavy oil is often called as “foamy oil”(Smith 1988, Maini et al.

1993). Obviously, the dispersed gas bubbles play an important role in heavy-oil

solution gas drive, but the reason why the bubbles remain dispersed for a relatively

long time is still not clear. The purpose of our study is to better understand this

problem.

Figure 1.1: World wide distribution of conventional oil and heavy oil and bitumen(http://www.petroleumequities.com).

Diatomite is a sedimentary rock mainly composed of amorphous silica (opal-A),

crystalline silica (quartz) and clay in different proportions. The key features of di-

atomite are low permeability (0.1 md-10 md) and high porosity (25%-65%) (Schwartz

1988). Diatomite is of great importance commercially. The estimated reserve of oil

for diatomaceous reservoirs in the San Joaquin Valley, California ranges from 10 to

15 billion barrels (Ilderton et al. 1996). However, the low permeability feature of di-

atomite makes it difficult to recover oil by usual techniques. Steam injection has been

tested and is proven to recover oil from diatomite reservoirs (Kovscek et al. 1996a;b;

3

1997, Kumar and Beatty 1995, Johnston and Shahin 1995, Murer et al. 1997), but

the recovery process is complicated due to dissolution and precipitation of diatomite

rock, among other factors. In addition, a relatively high pressure is required to inject

steam into the low permeability rock matrix of diatomite, which may lead to fractures

in the rock. In this study, we further explore the influence of diatomite dissolution

and precipitation during the process of steam injection.

Our studies of the two kinds of unconventional resources are described in detail in

following chapters. In Chapter 2, we report the experimental results from measure-

ments of acid/base number and asphaltene content, single-film tests and micro-model

experiments. Based on the results, we found that there is a relationship between

oil chemistry and the heavy-oil solution gas drive mechanism. In Chapter 3, we

have studied the effects of several factors of steam injection and silica dissolution of

diatomite rock. We also found that silica dissolution plays a role in fracture recon-

solidation of diatomite under thermal operations.

4 CHAPTER 1. INTRODUCTION

Chapter 2

The impact of oil chemistry on

heavy-oil solution gas drive

2.1 Introduction

Some heavy oil reservoirs under primary recovery by solution gas drive show unex-

pectedly high recovery efficiency (Huang et al. 1998, De Mirabal et al. 1996; 1997,

Maini 1996). One phenomenological observation related to favorable recovery is that

the gas phase remains dispersed throughout a significant portion of the depletion.

Consequently, gas relative permeability remains low (Tang and Firoozabadi 2003,

Tang et al. 2006b), a significant fraction of the gas remains in the reservoir, drive

energy is preserved, and accordingly the rate of pressure decline is less than predicted

by conventional analysis (Tang et al. 2006b). Because the gas remains dispersed, the

term “foamy oil” was coined as a descriptor (Smith 1988, Maini et al. 1993). The

term is not quite accurate however, because the morphology of gas is more “bubbly”

than foam like (Tang and Firoozabadi 2003, Sheng et al. 1999, Urgelli et al. 1999).

Here we use the terms foamy oil and heavy-oil solution gas drive interchangeably.

A number of factors appear to contribute to the success of heavy oil solution gas

drive. Gas bubbles nucleate in a heterogeneous fashion within pores (El Yousfi et al.

1997, George et al. 2004) and grow relatively slowly because diffusivity of gas through

liquid is inversely proportional to liquid viscosity (El Yousfi et al. 1997, George et al.

5

6 CHAPTER 2. OIL CHEMISTRY AND HEAVY-OIL SOLUTION GAS DRIVE

2004, Arora and Kovscek 2003). The growth of gas bubbles into a continuous phase is

hindered by the liquid viscosity (El Yousfi et al. 1997, George et al. 2004, Arora and Kovscek

2003). All other factors being equal, the time to drain thick liquid lenses that sepa-

rate gas bubbles is proportional to viscosity and hence the coalescence of gas bubbles

into a continuous gas phase is delayed by oil viscosity. Once the liquid lenses sepa-

rating gas bubbles are drained and the interfaces of the bubbles meet, the bubbles

coalesce if there are no surface-active agents are present in the liquid to stabilize

the interface. While liquid viscosity alone does make a contribution to the mainte-

nance of dispersed gas in porous media, comparison of the dynamics of gas evolution

among clean mineral oil systems and crude-oil systems of similar viscosity, teaches

that the gas dispersed within crude remains dispersed for a much greater period of

time (Tang et al. 2006a). By inference oil-phase chemistry plays a significant role in

stabilizing the gas-oil interface and in the so-called foamy-oil effect.

The rate of depletion also appears to play a role for some systems. Tang et al.

(2006a) demonstrated that greater depletion rate tends to generate more dispersed,

pore-sized gas bubbles that encounter significant resistance to flow and result in

greater oil recovery. In addition, the recovery efficiency of solution gas drive decreases

as temperature increases because increased temperature reduces the oil viscosity

thereby enhancing dispersed gas-phase mobility (Tang and Firoozabadi 2003). Sand

mobilization, sand production, and the resulting creation of high permeability gas

pathways within the reservoir also serve to promote oil production (Tremblay et al.

1996). The interested reader is directed to the articles of Sheng et al. (1999), Maini

(1999) and Firoozabadi (2001) for significantly more detailed reviews.

While there are many factors contributing to favorable heavy-oil solution gas drive

recovery, forces that assist gas bubbles in remaining dispersed appear to be relevant.

The analysis of George et al. (2004), described above, teaches that oil-phase viscosity

is important to coalescence but it cannot describe foamy-oil mechanics completely.

Chiefly, oil viscosity alone cannot account for the relatively long periods of time that

bubbles remain dispersed and foam like. Thus, crude-oil chemistry that contributes

to stabilize gas-oil interfaces is important to the process (Bauget et al. 2001).

Here, we report on our efforts to categorize crude-oil functional groups that aid

2.2. EXPERIMENTAL 7

foamy-oil phenomena. Previously, we noted that crude oils rich in organic acid func-

tional groups and asphaltenes correlated with high critical gas saturation, low gas

phase relative permeability and greater oil recovery (Tang et al. 2006c). Asphaltenes

are frequently suggested to be related to foamy oil behavior (Adil and Maini 2005)

and asphaltenes feature prominently in our work. Our work is primarily experimental

in nature. We have measured the so-called acid and base numbers of known foamy

and nonfoamy crude oils, isolated the asphaltenes of these crudes and measured their

acid and base numbers, and measured the stability of gas bubbles in crude oil and var-

ious organic solutions. A network structure stabilized by interactions among acid and

base functional groups is proposed as a mechanism to stabilize the gas-oil interface.

This part of work proceeds with a description of the oil samples and methods

used for characterization. We describe a micromodel apparatus containing a two-

dimensional representation of a sandstone pore network pattern that is used to ex-

amine the stability of gas bubbles dispersed within various organic solutions. Results

and a discussion of the relevance of crude-oil chemistry to heavy oil solution gas drive

follow. A summary of our approach and findings completes our study on this part.

2.2 Experimental

The experimental description is divided into materials, measurement tools, and the

micromodel bubble coalescence apparatus. Then the procedures for oil character-

ization are outlined, including acid number, base number, asphaltene content and

single-film lifetime.

2.2.1 Materials

Fourteen stock tank oil samples were used in our study, as detailed in Table 2.1. Two

of these crude oils were previously demonstrated to be foamy oils (Tang et al. 2006c).

Here, we adhere to their previous descriptions as HO-1 and HO-2. We also examine

various samples from the West Sak, Alaska North Slope reservoir. The other oils are

of current interest to our research group and are not necessarily foamy oils. They span


a range of oil gravity and asphaltene content. Solvents and reactants include toluene,

isopropanol, heptane, glacial acetic acid and potassium hydroxide (KOH) that were

purchased from EMD Chemical. Decane was purchased from Zeeland Chemicals.

Perchloric acid (HClO4), cyclohexanepropionic acid (CHPA), quinoline, stearic acid,

potassium hydrogen phthalate were obtained from Fisher Scientific. Acetic anhy-

dride was purchased from Acros Organics. Mineral oil samples were manufactured

by Brookfield Engineering Laboratories. The filter paper was from Millipore.

2.2.2 Apparatus

An Accumet AP63 portable ISE/pH/mV meter connected to an Accumet∗ pH/ATC

combination electrode was used to measure pH for all acid/base titrations. The vis-

cosities of some solutions were measured by a Canon - Fenske viscometer (EXAX

size 50). The experimental setup to test the stability of gas bubbles consists of

the etched-silicon micromodel, pressure vessels, microscope, vacuum pump, vacuum

gauge (Omega DPG1100B) and syringe pump (Teledyne D-Series) that controls fluid

flow and pressure. The micromodel is designed to represent the pore-level geomet-

ric structure of a sandstone pore network. It allows direct visualization of the flow

phenomena, and is useful to view pore-level events within porous media. Etched

silicon-wafer micromodels developed by Hornbrook et al. (1991) were used in our ex-

periments. These micromodels contain a 50 by 50 mm etched pore pattern. There are

flow distribution channels along inlet and outlet edges of the micromodel that result

in approximately linear flow from the inlet and outlet. The porosity of the micro-

model is around 0.2 and the permeability is approximately 0.1 mD. Further details of

these micromodels and experimental procedures are provided by George et al. (2004),

Rangel-German and Kovscek (2004). A Nikon Eclipse (ME 600) reflected-light mi-

croscope with a photo tube that allows for the connection of a video camera was

used to visualize fluid movement within the micromodel. A high-quality color video

camera (COHU Solid Slate Camera) was used to capture images from the microscope

and the images were recorded on a VHS video cassette recorder. Most observations

are made at 200X.

2.2. EXPERIMENTAL 9

2.2.3 Acid number measurement

The acid number (AN) of each oil sample was determined by the potentiometric

titration method (Fan and Buckley 2006). About 0.5 g of oil sample (or asphaltene)

was dissolved in a 50 ml mixture of deionized water, toluene and isopropanol (6 ml

deionized water, 494 ml isopropanol, 500 ml toluene). The solution was spiked with

1.5 ml of 0.0175 M stearic acid solution (in decane). The resulting solution was

titrated with 0.04 M standardized potassium hydroxide (KOH) in isopropanol. A

10 ml burette was used for all oil sample titrations. The volume of solution in the

burette and the pH of the sample solution were recorded every titration. A curve of

pH versus titrant volume was drawn. The volume of titrant to neutralize the solution

(Veq) was identified numerically as the inflection point on the titration curve. The

corresponding acid number was calculated as

AN =(Veq − beq)×N × 56.1

Woil

(2.1)

where beq is the inflection point volume of the blank titration (0.0175 M stearic acid

solution in decane).

2.2.4 Base number measurement

The base number (BN) of the oil samples was determined by potentiometric perchloric

acid titration (Dubey and Doe 1993). About 0.5 g of oil sample (or asphaltene) was

dissolved in a 50ml solvent mixture of glacial acetic acid and toluene (1: 1 volume

ratio). Then, 1 ml of 0.04 M quinoline solution (in decane) was used to spike the

solution. The titrant was 0.055 M standardized HClO4. The volume reading of the

burette and the pH value of sample solution were recorded every titration. A titration

curve of pH versus titrant volume was drawn and the volume of inflection point (Veq)

was obtained in a fashion identical to the AN measurement. The base number was

calculated as

BN =(Veq − beq)×N × 56.1

Woil

(2.2)


where beq is the inflection point volume of the blank titration (1 ml 0.04 M quinoline

in titration solvent). The base number is the amount of potassium hydroxide in

milligrams that is required to neutralize the acid titrant needed to neutralize one

gram of crude oil.

2.2.5 Asphaltene content measurement

Oil is divided into asphaltene and maltene fractions according to solubility in hep-

tane. Asphaltene is insoluble in the low molecular weight paraffins and consists of

condensed aromatic rings bounded by alkyl chains with various functional groups. It

is considered to be surface active in some selected organic solvents. The soluble por-

tion is called maltene that we refer to here as de-asphalted oil. Both asphaltene and

de-asphalted oil contain acidic and basic groups that may be related to the source

of interfacial activity of some crude oils. To find a relation among acid number,

base number, and asphaltene content with the stability of dispersed gas bubbles, we

studied the effects of asphaltene, organic acid and base on the cold production of

heavy oil. The asphaltene fraction was separated from the crude oil using a stan-

dard method (ASTM-D6560-00 2005). About 5 ml of oil sample was put in a 250 ml

flask, and then about 200 ml of heptane was added. The flask was sealed and shaken

thoroughly. The mixture was equilibrated for two days at ambient conditions. The

mixture was shaken numerous times during the aging period. A 0.22 µm filter was

used with a vacuum filtration apparatus. The filter funnel was rinsed several times

until the filtrate was transparent. After the final rinse, vacuum was continued to let

the asphaltenes dry until forming cracks in the filtrate. The asphaltene was dried in

a hood and weighed. The asphaltene content was calculated as

Asphaltene Content (wt%) =weight of dry asphaltene

weight of crude oil sample× 100 (2.3)

2.2.6 Single film life time

Similar to Bauget et al. (2001), a stainless steel ring (0.35 inches) was submerged in

various oils and solutions and then retracted to form a film. The oil or solution being

2.3. RESULTS AND DISCUSSION 11

tested was in a small enclosure saturated with solvent vapor to prevent dry out and

evaporation of the film. Films were held horizontally unless noted otherwise. The

film life time was recorded as the time from the formation to rupture of the film.

Because variability in the time to rupture was noted for the same solution, at least 30

measurements were made for each case and the film life time obtained as an average

as well as the standard deviation of the lifetime.

2.2.7 Micromodel experiment

All experiments were carried at 22 ◦C. Before beginning the experiment, the micro-

model was washed with toluene followed by methanol to remove traces of trapped

material. The micromodel was placed under the microscope. It was saturated with

nitrogen first by injecting the bone-dry gas from the nitrogen pressure vessel at a

constant pressure of 10 psi. After injecting nitrogen, the pressure vessel containing

oil was connected to the micromodel. The oil was injected into the micromodel by

a syringe pump at a constant pressure of 10 psi. The oil injection process was mon-

itored by the microscope. When the free gas in the micromodel became dispersed

as gas bubbles, the pump was stopped. Then photographic observations of bubbles

within the pores of the micromodel began. For less viscous oils and solutions that

demonstrated short film lifetimes in the single-film test, no pressure drop was applied

on the micromodel. In other cases, a vacuum (22 inches of Hg) was applied at the

outlet of micromodel. Images within the micromodel were recorded by VCR.

2.3 Results and discussion

First the crude-oil properties including acid number, base number, and asphaltene

content are presented. Then the origin of acid and base functionalities is discussed.

Next, the results of single film tests and micromodel experiments are discussed. Fi-

nally, the effect of viscosity on foamy-oil behavior is compared to that of oil compo-

sition.


2.3.1 Chemical characterization

Table 2.1 gives the acid number of the fourteen oil samples. The acidic functional

groups are mainly carboxylic acid groups that exist in both de-asphalted oil and the

asphaltene fraction (Callaghan et al. 1985). The two foamy oils, HO-1 and HO-2,

have acid numbers of 1.79 mg/g and 2.88 mg/g, respectively. These values are near

the median point within the range from 0.14 mg/g for Cymric light oil to 5.51 mg/g

for Cymric heavy oil. Tang et al. (2006c) suggested that the organic acid groups in oil

are related to foamy-oil behavior of heavy oil under solution gas drive. Our results,

however, indicate that the acid number alone is not necessarily related with the

foamy-oil behavior because many of the oils tested that are not foamy also display

a significant acid number. It is possible that not all organic acids in the oil are

interfacially active, so it is necessary to find the acid types that play a role in the

stabilization of dispersed gas bubbles.

NO. Oil Acid # Base # Asphaltene content ◦API Foamy?(mg/g) (mg/g) (wt%)

1 West Sak 1.04 2.87 2.46 24 No2 West Sak 2 0.62 2.44 2.51 20 No3 West Sak 3 1.00 2.82 4.01 18∗ No4 West Sak 4 0.87 2.91 2.60 17∗ No5 Aera crude oil 1.64 4.99 2.71 32 No6 PIKI 1.79 2.85 0.14 19 No7 THUMS 1.70 7.34 6.57 20 Not tested8 Cymric heavy 5.51 9.78 6.07 12 No9 Cymric light 0.14 2.31 1.06 34 No10 Oman 3.08 1.98 0.12 N/A No11 Lost Hills 2.36 6.02 2.69 21 No12 Kern River 2.43 8.64 5.90 14.5 Not tested13 HO-1 1.79 4.84 21.0 9.7 Yes14 HO-2 2.88 5.90 13.6 9 Yes

Table 2.1: Acid numbers, base numbers and asphaltene contents of crude oil samples(*contains a water in oil emulsion).

The base numbers of the fourteen oil samples were also measured, as shown in

Table 2.1. The organic bases identified in oil are heterocyclic aromatics with one


nitrogen atom and one or more fused aromatics rings (Lochte 1952, Schmitter et al.

1980). The measured base numbers range from a minimum of 1.98 mg/g for the

Oman heavy oil to a maximum of 9.78 mg/g for Cymric heavy oil. The base numbers

of HO-1 and HO-2 are 4.84 mg/g and 5.90 mg/g, which are near the median point of

the range. Similar to the observations of acid number, the base number alone does

not have direct link to foamy behavior.

The asphaltene content of the fourteen crude-oil samples was measured with re-

sults summarized in Table 2.1. The two foamy oils, HO-1 and HO-2, have the greatest

asphaltene contents of 13.6% and 21.0%, respectively. The asphalt and deasphalted

fractions were then employed for further analysis. As suggested above, organic acids

and organic bases are not necessarily related to foamy-oil behavior. To find the dis-

tribution of organic acids or bases in the oil, the acid/base numbers were measured

for the asphaltene and the de-asphalted fraction of West Sak, HO-1 and HO-2. The

results are shown in Table 2.2. Clearly, organic acids and bases are distributed in

both de-asphalted oil and asphaltene fraction. The acid numbers of asphaltene and

the de-asphalted oil are close to each other for the three samples. Evidently, oil acids

distribute almost evenly in both fractions. On the contrary, the majority of organic

bases are in asphaltene. Another interesting phenomenon is that while the asphal-

tene contents are markedly different, acid and base numbers of the three asphaltene

samples are approximately the same. It appears that the asphaltenes from all oils

may have similar amounts of acidic and basic groups. Possibly, the structure and

properties of asphaltenes within this study are very similar.

2.3.2 Film stability

The chemical analysis suggested that crude-oil foaming correlated with asphaltenes

exhibiting acid and base functionalities. We performed several single film life time


Oil sample West Sak HO-1 HO-2Asphaltene AN 2.25 2.01 2.25

(mg/g)De-asphalted AN 0.98 1.43 2.57

(mg/g)Asphaltene BN 12.48 11.34 13.38

(mg/g)De-asphalted BN 2.56 2.46 4.08

(mg/g)Asphaltene content 2.46 21.0 13.6

(wt %)

Table 2.2: Acid and base numbers of de-asphalted oil and asphaltenes.

tests to differentiate the interfacial activities of the asphaltene fractions and de-

asphalted oil. Synthetic fractions as well as crude-oil fractions were studied. Cy-

clohexanepropionic acid (CHPA) solution in decane was chosen to represent the de-

asphalted oil, because naphthenic acids are the major type of organic acid in de-

asphalted oil and CHPA is a napthenic acid with good activity (Wu et al. 2006). An

acid number range from 1 mg/g to 5 mg/g was tested. Quinoline solution in decane

was chosen as a model base group because it is representative for the organic bases

in the de-asphalted oil. A base number range from 2 mg/g to 10 mg/g was tested.

Solutions were also made using the crude-oil asphaltene fractions. The asphaltenes

from West Sak, OH-1, OH-2 were dissolved in toluene and the tests were performed

in the range of asphaltene content from 5% - 20%. The film lifetimes for all CHPA

solutions and quinoline solutions are approximately the same as that of pure decane,

suggesting that these model de-asphalted acids and bases are not interfacially active

and responsible for foamy-oil stability.

The film life times measured for asphaltene solution are much longer compared

to film lifetimes for pure solvent. The diagram of film life times versus asphaltene

concentration is Figure 2.1 Thin films emerged in these tests as a diffraction pattern

was evident to the naked eye. Figure 2.1 reports average (30 measurements) film

lifetime and the maximum film lifetime. We find that the greater the asphaltene

concentration, the greater the film stability. The slopes of the film lifetime versus


asphaltene concentration increase with asphaltene concentration.

5 10 15 2050

100

150

200

250

300

350

400

Asphaltene Concentration (%wt)

Film

Life

time

(s)

Mean lifetime of HO−1Mean lifetime of West SakMean life time of HO−2Maximum lifetime of HO−1Maximum lifetime of West SakMaximum life time of HO−2

Figure 2.1: Life time of single films formed from asphaltene solutions.

To add a degree of physical realism to the tests of films stability, a series of

micromodel experiments were performed to study the interfacial activities of CHPA

decane solution (2.9 mg/g acid number), quinoline decane solution (5.9 mg/g base

number) and OH-2 asphaltene solution (13.6%). The solvent is an equivolume mixture

of decane and toluene (1:1). The acid number, base number and asphaltene content

of OH-2 are 2.9 mg/g, 5.9 mg/g and 13.6%, respectively. Hence, the solutions are

comparable to the actual foamy oil. The length of the time from the formation to the

coalescence of the bubbles was measured and the whole process was monitored by a

microscope and recorded by a VCR. The experimental results are shown in Figure 2.2

(without vacuum applied) and Figure 2.3 (with vacuum applied). The life times of

dispersed gas bubbles are listed in Table 2.3. Compared with asphaltene solution,

the life times of bubbles in the de-asphalted oils are negligible. The micromodel

results also indicate that asphaltene stabilizes the dispersed bubbles in foamy oil in

agreement with the results of the single film life time tests.

The two foamy oils, HO-1 and HO-2, have the greatest asphaltene contents of

13.6% and 21.0%, respectively. Asphaltene molecules are known to be surface active

in some organic solvents. On the other hand, a mechanism for stabilization of the


Figure 2.2: Micromodel images of bubble coalescence for CHPA, quinoline and as-phaltene solutions, 200X. (No vacuum applied to system. Gas is lightly shaded, oil isblack, and grains are gray)


Sample w/o vacuum w/ vacuum (22 inches Hg)Bubble life time Bubble life time

CHPA solution (2.9 AN) 2 mins 11 secs N/AQuinoline solution (5.9 BN) 10 mins 16 secs 2 mins 2 secsAsphaltene solution (13.6%) > 4 hrs 16 mins 31 secs 1 hr 45 mins 35 secs

Table 2.3: The life time of dispersed gas bubbles in micromodel experiments.

Figure 2.3: Micromodel images of bubble coalescence for quinoline and asphaltenesolutions, 200x. (Vacuum (22 inches in Hg) applied to system. Gas is lightly shaded,oil is black, and grains are gray)


gas-oil interface by asphaltene does not seem to be evident in the literature. Given

that HO-1 and HO-2 display acid and base functionalities as well as significant as-

phaltene content, the origin of film stability could be interaction between the acidic

sites and basic sites of asphaltene. Hydrogen bonds and other weak chemical bonds

among acid and base groups may allow a rigid, network-type structure of asphaltene

to form that stabilizes the interface of two phases. Such interaction is similar to that

leading to the well known dimerization of acetic acid by hydrogen bonds or to the

formation of a charge transfer complex between nitrobenzene (C6H6NO2) and mesity-

lene (C6H5(CH3)3) (Poling et al. 2000). In the latter example, a weak chemical bond

is formed because nitrobenzene is an electron acceptor (Lewis acid) and mesitylene

is an electron donor (Lewis base).

Figure 2.4 displays a hypothetical structure of an asphaltene complex in which

hydrogen bonds connect the multi-aromatic-ring compound to form a network struc-

ture. Charge transfer complexes lead to a similar picture. This simplified schematic

illustrates the mechanism of how hydrogen bonds work to form the 3-dimensional

structure of asphaltene. Our work indicates that foamy oil must have high asphal-

tene concentrations with organic acid and base functional groups. As the asphaltenes

in HO-1 and HO-2 appear to be similar to those in West Sak, it is suggested that the

West Sak case is not foamy for lack of sufficient asphaltenes. We do not know how

high the asphaltene content should be to make a foamy oil. Certainly it should be

greater than the 2.46% for West Sak.

Macroscopic networked asphaltenic structures are similarly suggested to form at

the oil water interface where they are believed to play an important role in the

alteration of reservoir media to a mixed wettability state (Freer et al. 2003). The

formation of asphaltenic “films” at the water oil interface is well established and dates

from the early work of Bartell and Neiderhauser (1949) as well as refs. (Kimbler et al.

1966, Reisburg and Doscher 1956, Strassner 1968). Figure 2.4 merely suggests that

analogous ordering is potentially possible at the gas oil interface and may be inferred

from the elasticity of the gas-oil interface.

Although direct relations of acid, base number, and asphaltene concentration with

foamy-oil behavior can not be found, we have sufficient data to begin to develop


N

N

SR

N

OOH

N

S

H

OO

H

N

N

S

OO

H

O

O

OH

NRH

S

OH

O

O O

H

H

O

R

Figure 2.4: A hypothetical structure that illustrates hydrogen bonds resulting in anetworked asphaltene structure. Dashed lines represent the hydrogen bonds.

correlations. Our results and the hypothesis of the role of acid and base groups on gas-

oil interface stability suggest that all the three properties contribute to the interfacial

activity of foamy oil. In a coordinate system where the x-axis represents acid or base

number and the y-axis represents asphaltene content, each sample is expressed as a

point. Figure 2.5 and Figure 2.6 present the relations between asphaltene content

and acid or base number. For both figures, the two points representing OH-1 and

OH-2 are far from trend representing non-foamy cases. There could be a “foamy

region” in the coordinate system and the oils that fall in that region, such as OH-1

and OH-2 are foamy. The diagrams representing the relation between asphaltene

content and acid/base number provide a method to predict the behavior of oil by the

three readily measured properties. Given more foamy-oil samples, the extent of this

“foamy region” should become clearer and the method made more accurate.

2.3.3 Viscosity

Viscosity is thought to play an important part in the solution gas drive process.

Many works suggested that a greater oil viscosity slows down the coalescence of

gas bubbles and restricts the formation of free gas flow (Wall and Khurana 1977,


0 1 2 3 4 5 60

5

10

15

20

25

Acid number

Asp

halte

ne c

onte

nt (

wei

ght %

)

Figure 2.5: Asphaltene content versus acid number of study samples.

0 2 4 6 8 100

5

10

15

20

25

Base number

Asp

halte

ne c

onte

nt (

wei

ght %

)

Figure 2.6: Asphaltene content versus base number of study samples.


Kumar and Pooladi-Darvish 2001, Talabi and Pooladi-Darvish 2003). However,

(Tang et al. 2006a) found that oil composition, rather than viscosity, is a significant

contributor to the stability of dispersed gas bubbles. To illustrate the problem, we

studied the effect of viscosity on the stability of single film and compared the results

with those of asphaltene solutions and foamy-oil sample.

The single film life times of different mineral oil samples with standard viscosities

were measured. A diagram of film life time versus viscosity was drawn for mineral

oil samples and asphaltene solutions, as shown in Figure 2.7. At the same viscosity,

the single film life time of asphaltene solution is much longer than that of mineral

oil. In addition, when a stainless steel loop with a diameter of 2.2 cm was dipped

directly into HO-1 (viscosity is 258 cp), a stable film formed and lasted an average of

530 seconds (held vertically to speed coalescence). While at the same condition, the

film formed by a mineral oil with much greater viscosity (11,360 cp) can only last 16

seconds on average. All the facts suggested that asphaltene content and asphaltene

functional groups are a more significant factor for the foamy-oil stability in comparison

to oil-phase viscosity.

0 2 4 6 8 100

50

100

150

200

250

Viscosity (cp)

Film

Life

time

(s)

Film life time of HO−2 asphaltene solutionFilm life time of standard mineral oil

Figure 2.7: Life time of single flims of asphaltene solution and mineral oil versusviscosity.


2.4 Summary

The acid and base numbers of crude oil reflect organic acid and base functional groups.

The acid number and base number quantify the frequency of carboxylic acid groups

and basic nitrogen present per mass of oil, respectively. In the crude oils studied here,

the acid and base groups are found in both the asphaltene and deasphalted fraction.

The asphaltene fraction of three quite different viscous crude oils displays similar acid

and base numbers. This result was not expected.

Within our study samples, there were two crude oils that demonstrated foamy-

oil behavior at laboratory scale. The correlation of acid number, base number, and

asphaltene content on the foamability of oil, asphaltene solutions, and deasphalted

oil were studied in single-film and micromodel tests. Also, crude-oil properties were

contrasted with mineral oil of similar or greater viscosity and linked with interfacial

properties. Within these samples, cold production behavior correlates with asphaltene

content of heavy oil that displays significant acid and base number. Asphaltene

solutions from a crude-oil that did not foam were found to exhibit significant film

lifetimes and lifetime increased with asphaltene content. Asphaltene solutions from

foamy and nonfoamy crude oils displayed similar behavior. In general, the greater the

solution asphaltene content, the greater the interfacial stability. The acid and base

groups present on asphaltene appear to contribute to stability by allowing asphaltene

molecules to form an interlinked network structure.

The role of solution viscosity on bubble coalescence and film rupture appeared

to be relatively minor. Bubbles dispersed in viscous mineral oil and (thick) films of

mineral oil did coalesce more slowly in comparison to their less viscous, mineral oil

counterparts. Film lifetimes, however, were much greater for crude oils and asphaltene

solutions. Likewise, film lifetimes did not increase markedly as viscosity increased.

2.5 Conclusions and future work

For the study of oil chemistry and heavy-oil solution gas drive, there are several

conclusions based on the results of chemical property measurement, single film tests,

2.5. CONCLUSIONS AND FUTURE WORK 23

and micromodel experiments.

1. heavy-oil solution gas drive recovery correlates with asphaltene content that

displays significant acid and base number

2. The acid and base groups present on asphaltene, not in deasphalted oil, con-

tribute to stability of dispersed gas bubbles in foamy oil

3. The role of viscosity on bubble coalescence and film rupture appears to be

relatively minor compared with oil chemistry

In the future work, the impact of oil chemistry (acid number, base number and

asphaltene content) on heavy-oil solution gas drive should be studied within sandpacks

or rocks, because the study here is limited to 2-D micromodel and more general

conclusion is needed.

Chapter 3

Silica dissolution and fracture

reconsolidation of diatomite during

thermal operations

3.1 Introduction

Diatomite is a sedimentary rock mainly composed of opal-A (amorphous silica, 57-

77%), quartz (crystalline SiO2, 3-12%), and clay in different proportions depending

on its origin (Berry and Mason 1959). Diatomite is characterized by high porosity,

varying from 25% to 65%, but low permeability, ranging from 0.1-10 md (Schwartz

1988). Oil recovery from diatomite is commercially important because of the large

amount of oil in place, ranging from 12 to 18 billion barrels (Ilderton et al. 1996).

Because diatomite rock is not very permeable, usual techniques, such as pri-

mary production, do not work well for oil recovery. Recently, steam injection was

tested and proven to be an efficient method to improve recovery. It has been used

to recover successfully light and heavy oil from the South Belridge and Cymric di-

atomite (Kern County, CA) (Kovscek et al. 1996a;b; 1997, Kumar and Beatty 1995,

Johnston and Shahin 1995, Murer et al. 1997). First, the heat generated by steam

leads to viscosity reduction and thermal expansion, that enhances oil recovery. In

this stage, injected steam does not have to contact oil directly. Subsequently, the

25

26 CHAPTER 3. SILICA DISSOLUTION & FRACTURE RECONSOLIDATION

condensate from injected steam imbibes into the rock matrix and displaces oil. The

condensate is usually a hot fluid with low salinity and moderately high pH, that

may bring some changes to the wettability and relative permeability of diatomite

rock (Tang and Kovscek 2002, Schembre et al. 2005). It was also reported that hot

fluid injection into diatomite influences permeability and porosity of the rock ma-

trix (Bhat and Kovscek 1999, Diabira et al. 2001). Steam injection into diatomite

reservoirs is a complicated process. Relatively high injection pressures are necessary

for steam to enter the low-permeability rock matrix. This may lead to compaction

or fracturing of the rock matrix in some extreme cases. The chemical reactivity

and large surface area of diatomite also brings complexity to steam injection. Silica

(SiO2), the main component of diatomite, dissolves in the relatively fresh hot aqueous

condensate. This is silica dissolution. The dissolved silica is transported downstream

by moving condensate and it precipitates again when the condensate cools. This is

silica reprecipitation. Silica dissolution may enhance permeability of diatomite rock

while reprecipitation may decrease it. Thus, steam injection causes redistribution of

permeability and porosity within the diatomite reservoir, which is already relatively

impermeable. Such redistribution may have both positive and negative effects on

injectivity and oil recovery.

Ikeda et al. (2007) observed homogenization of diatomite rock after the core was

flooded by hot alkaline. Such homogenization was also observed for fractured samples,

resulting in healing of fractures. The cause of fracture reconsolidation is not clear.

There are several factors that may play a role. Silica dissolution/precipitation is a

possible reason. At elevated temperature, the injected fluid with high pH dissolves the

silica in diatomite core. If the precipitation of dissolved silica occurs in the fracture,

the fracture can be healed by the redeposited silica. Overburden stress on the core

can also cause fracture healing. Jones (1975) suggested that fracture permeability

is greatly reduced by increasing the magnitude of confining pressure applied on rock

core. Besides, temperature may also be a essential factor in the process of fracture

reconsolidation, as proposed by Ikeda et al. (2007). In our work here, we will verify

whether the above factors influence reconsolidation and fracture healing of diatomite

under hot-fluid injection. We will also study the mechanism of fracture reconsolidation

3.2. SILICA DISSOLUTION AND PRECIPITATION IN DIATOMITE 27

of diatomite to interpret how these factors act.

First, experiments were conducted to study silica dissolution of diatomite core

accompanying one-dimensional fluid flow at a variety of salinity, pH values, temper-

atures, and metal ion concentrations. We compare the evolution of permeability,

effluent pH, and silica concentration of effluent. By doing so, we obtain an optimal

condition for silica dissolution and will use that condition to study the role of silica

dissolution in fracture healing and homogenization of diatomite rock. Next, several

experiments were designed to study the influence of silica dissolution, confining pres-

sure, and temperature on diatomite under thermal operations.

3.2 Silica dissolution and precipitation in diatomite

3.2.1 Silica dissolution

Silica (SiO2), the main component of diatomite, is dissolved in aqueous solution.

Silica dissolution to form slicic acid is shown as the forward direction of the reversible

reaction in Eq. 3.1.

SiO2(s) + 2H2O À H4SiO4(aq) (3.1)

Silica dissolution is related to the pH of solution. Besides pH, silica dissolution is also

dependent on temperature, salinity, and metal ions present in solution (Reed 1980,

Rudenko and Sklyar 1990).

The importance of silica dissolution has been emphasized both in steam flood-

ing (Reed 1980) and in alkaline flooding (Bunge and Radke 1982, Lieu et al. 1982,

Sydansk 1982). Rapid dissolution of silica sometimes causes significant changes

in rock, such as wormholes. Few studies examine silica dissolution in diatomite.

Diabira et al. (2001) suggested that dissolution of diatomite matrix is a slow process

relative to compression and cannot compensate for permeability reduction until a

large volume of fluid is injected. Bhat and Kovscek (1999) proposed a network model

to gauge how evolving pore topology of diatomite affects porosity and permeabil-

ity. The results of the network model agreed well with the experimental results of

Koh et al. (1996).


3.2.2 Silica precipitation

After silica dissolution, the dissolved silica precipitates to form solid again under

certain conditions, such as cooler solution or higher concentration. Silica precipitation

is shown as the reverse direction of Eq. 3.1. Similarly, silica precipitation is also related

with the pH of solution. The deposition of silica on rock surface is believed to reduce

permeability. In the permeability-damage experiment conducted by injecting silica

laden hot water into diatomite, Koh et al. (1996) confirmed that silica deposition

leads to permeability reduction.

In the work of Bohlmann et al. (1980), the kinetics of silica deposition was studied.

Some of their observations are

1. Silica deposition is a function of the concentration of H4SiO4,

2. deposition on all surfaces results from spontaneous nucleation, and

3. similar to silica dissolution, silica deposition is dependent on silica concentra-

tion, pH, surface area, temperature and salinity.

Silica precipitation may play a role on fracture reconsolidation of diatomite.

3.2.3 Gelation of silicate and colloidal silica

Upon hot-fluid injection, silica enters into the aqueous solution as silicate or colloidal

silica, or both. Silicate is a ionic form of silica, coming from the dissolution of sil-

ica. Colloidal silica refers to stable suspensions of discrete, nonporous, and typically

spherical amorphous silica particles in a liquid phase. The main form of silica depends

on the condition of the solution, such as pH, temperature, and salinity. Under certain

conditions, both silicate and colloidal silica have a possibility to form silica gel, which

is a state that lies between liquid and solid. Silica gel may change the rock matrix of

diatomite, so it is helpful to understand the conditions and mechanisms for gelation

of silicate and colloidal silica.

The gelation of colloidal silica results from particle collision, bonding and ag-

gregation into long chain networks (Iler 1979, Jurinak and Summers 1991). Particle

3.2. SILICA DISSOLUTION AND PRECIPITATION IN DIATOMITE 29

collision is enhanced by increasing particle concentration and temperature, or reduc-

ing surface charge. Siloxane (Si−O− Si) bonds are formed during particle bonding,

that is catalyzed by the hydroxide ion. As a result of particle aggregation, a 3-D

uniform network of long strings of silica particles forms. Generally, colloidal gelation

requires a relatively high concentration of reagent. When the sodium pH is below

7, gelation time is decreased by increasing pH. The preferred pH range for minimum

gelation time is 5 < pH < 7. When pH is above 7, the gelation time is lengthened

due to stronger charge repulsion, while colloidal silica is stable at 9.5 < pH < 10.5.

The gelation time is also reduced by increasing temperature and colloidal silica con-

centration.

Silicate gelation is a superposition of many process: particle formation, growth and

aggregation (Iler 1979, Jurinak and Summers 1991). The rate of particle formation

and growth is strongly dependent on salinity and pH. The mechanism of particle

aggregation is similar to that of colloidal silica gelation. At the same level of pH,

the gelation time of silicate is generally shorter than that of colloidal silica. And

the gel strength of silicate is greater than that of colloidal silica. Compared with

colloidal silica gelation, silicate requires lower silica concentration to become a gel

and the gelation time is more sensitive to salinity. Unlike colloidal silica gelation,

silicate gelation still happens when 9 < pH < 10. Low levels of contaminants decrease

silicate gelation time in that pH range. The detailed comparison of the two gelation

mechanisms is shown in Table 3.1.

Colloidal silica SilicateStability ratio of > 50 < 4silica and alkaline

Stability pH 9.5-10.5 11.3-13Gelation time Long Short

Salinity sensitivity Not sensitive SensitiveRequired concentration Relatively high Relatively low

for gelation

Table 3.1: The comparison between gelations of silicate and colloidal silica.


3.3 Experimental study

3.3.1 Materials

Rock preparation

The diatomite core plugs used for the silica dissolution study are from a quarry

(Lompoc, CA). The porosity and permeability of the diatomite is around 60% and

3 md. The core plugs have no oil and are almost white, as in Figure 3.1. The SEM

(scanning electron microscope) image of the diatomite is shown in Figure 3.2, from

which a whole diatom is seen. To prepare a core for our study, the rock is first dried

in a vacuum oven. Then samples are cut to approximate dimensions with a bandsaw.

Two 1.5-inch disks are fixed to each end of the sample and then the sample is shaped

by sandpaper to the desired size.

Figure 3.1: Diatomite outcrop sample.

3.3. EXPERIMENTAL STUDY 31

Figure 3.2: SEM image of diatomite sample.

Fluids

The fluids used in our study include brine and high pH synthetic steam condensate.

The basic brine contains 3961 ppm Na+, 56 ppm Ca2+, 3 ppm Mg2+, and 6222 ppm

Cl−. The total salinity of the brine is 10242 ppm. By changing pH, salinity, and

metal ion concentration, we prepare other brine solutions needed for experiments.

The synthetic steam condensate is composed of 1248 ppm Na+, 837 ppm CO2−3 , and

415 ppm HCO−3 , which is a buffer solution with a pH value of 10.

3.3.2 Experimental apparatus

The studies of silica dissolution and fracture reconsolidation use the same experimen-

tal set-up, as shown in Figure 3.3 and Figure 3.4.


Figure 3.3: Experimental set-up for studies of silica dissolution and fracture recon-solidation.

Coreholder

In order to perform hot-fluid injection tests at elevated temperatures and high pres-

sure, a Hassler-type aluminum coreholder is designed. The endcaps are made from

stainless steel so that hot alkaline fluids never contact the aluminum tube. Spider-

webbed shaped grooves in the endcaps help to distribute flow evenly. The coreholder

is made for cores with a diameter of 1.5 inches. Core lengths vary from 1 inch to 3

inches. The diatomite core is first coated with a thin film of high temperature Dow

Corning silicone gel. The gel is non-wetting and does not penetrate the core, which

could prevent any fluid bypass during injection when a confining pressure is applied.

Then the core is wrapped with FTP (i.e., teflon) heat shrinking tubing that serves to

hold the silicone gel in place. Thus, the FTP tubing-silicone gel combination func-

tions as a high temperature sleeve. Then the core is placed inside of the aluminum

coreholder and a confining pressure of 300-1000 psi is applied by a water pump. To

heat the core, the coreholder is wrapped with heating tape and then covered by high


Figure 3.4: Picture of experimental set-up for studies of silica dissolution and fracturereconsolidation.


temperature insulation. A temperature controller is used to maintain constant tem-

perature of the coreholder. The coreholder is designed and tested for temperatures

up to 260◦C(500◦F). The assembly of the coreholder is shown in Figure 3.5.

Figure 3.5: Coreholder assembly.

CT scanner

A GE Light Speed X-ray Computerized Tomography (CT) scanner is used to monitor

porosity change during injection experiments. The scanner has 1200 fixed detectors

and a scan angle of 398◦. The spatial resolution is 0.5 mm by 0.5 mm by 10 mm.

The tube current is 125 mA and the energy level of the radiation is 130 keV. The

acquisition time for one image is about 6 seconds, and the processing time is about

40s. A map of porosity is computed from raw CT data according to Eq. 3.2.

φ =CTwr − CTar

CTw − CTa

(3.2)

where CT denotes the CT value for a voxel and the subscripts wr, ar, w and a refer

to water-saturated core, air-saturated core, water phase and air. The CT numbers of

water and air are taken as 0 and -1000, respectively.


Pressure transducer and demodulator

A Celesco differential pressure transducer is used to measure the pressure difference

across the inlet and outlet of the coreholder. A Celesco carrier demodulator is used

to convert the electrical signals from the transducer into pressure units.

3.3.3 Determination of silica concentration

The silica concentration of the effluent can be accurately determined by an inductively

coupled plasma (ICP) spectrometer. But this method is slow and not a good choice

when we need to monitor the silica concentration of effluent during the run-time of

an experiment. The silica concentration is estimated by colorimetry with ammonium

molybdate tetrahydrate ([(NH4)6Mo7O24 ¦ 4H2O]) (Schwartz 1942). Dissolved silica

reacts with ammonium molybdate to form an intensively yellow-colored heteropoly

acid, the color of which is similar to that of potassium chromate (K2CrO4) solution.

Because the color caused by silica is not stable and changes after sometime, the

potassium chromate solution is an ideal permanent color standard to indicate the

concentration of silica.

The chemical solutions required for this method are prepared as follows.

1. Ammonium molybdate reagent ([(NH4)6Mo7O24 ¦ 4H2O]) solution is prepared

by dissolving 15 g of ammonium molybdate in 200 ml deionized water and the

resulting solution is diluted to 300 ml with 1:1 hydrochloric acid.

2. Silica standard solution with a concentration of 1000 mg/L is from Fisher Sci-

entific.

3. Potassium chromate (K2CrO4) standard solution is prepared by dissolving 630

mg potassium chromate in 1 L deionized water.

4. Sodium tetraborate decahydrate solution (Na2B4O7 ¦ 10H2O) is prepared by

dissolving 10 g chemical in 1 L deionized water.

When all chemical solutions are available, a series of silica color solutions with

different silica concentration are needed for the preparation of color standards. 0, 1,


2, 4, 5, 7.5, 10 ml of 0.1 mg/L silica standard solutions are added into 40 ml glass

bottles and diluted to 25 ml, respectively. Then 0.5 ml 1:1 HCl solution and 1 ml

ammonium molybdate reagent solution are added into the diluted silica solutions.

The mixture solutions are shaken vigorously and then the silica color solutions are

ready.

The color standard solutions are made by adding 0, 0.5, 1, 2, 2.5, 3.75 and 5

ml potassium chromate standard solutions into 12.5 ml sodium tetraborate solution

and diluted to 25 ml, respectively. An additional 1.5 ml of water is added into

the diluted solutions and then the color standard solutions are ready. The colors

of the standard solutions are similar to the colors of silica standard solutions with

corresponding concentrations, as in Figure 3.6. The color standard solutions are used

in our experiment to estimate the silica concentration of effluent. For each test, 0.5

ml 1:1 HCl solution and 1 ml ammonium molybdate reagent solution are added into

25 ml effluent. After the sample is shaken and mixed well, the color of the effluent is

compared with color standard solutions to estimate silica concentration.

Figure 3.6: Comparison of the color of silica solutions and color standard solutions.


3.3.4 Procedures

Silica dissolution study

All tests for silica dissolution study follow a similar procedure, as shown below:

• The diatomite core is dried and put into the coreholder. A overburden confining

pressure of 400 psi is applied. The coreholder is placed horizontally within the

CT scanner gantry. Then, the CT images of cross sections at different locations

are taken for the dry core.

• The core is flushed by NaCl solution to remove any divalent metal ion in the

core. High salinity solution (1M) is injected first, then the low salinity brine

(0.1 M) is injected. (Only metal ion tests require this step.)

• The core is then flushed by deionized water until it is clean. After this, the

CT images of the water-saturated core are taken. To measure the permeabil-

ity before injection of brine, the pressure difference across the inlet and outlet

of the core is measured and the flow rate is also measured. For the study of

temperature effects, the coreholder is wrapped with heating tape and a de-

sired temperature is applied. The temperature of the core is controlled by a

temperature controller.

• The brine is injected into the core at a constant rate of 0.335 ml/min (0.42

m/day). The permeability of the core is measured every hour. The pH and

silica concentration of the effluent are also measured. The total injection time

is 4 hours.

Fracture reconsolidation study

After the optimal condition of silica dissolution of diatomite was worked out, we con-

tinued to study the mechanism of fracture reconsolidation under thermal operations.

The basic experimental procedure for this part is described as


• The fractured core is dried and put into coreholder, and then the coreholder is

placed horizontally within the CT scanner gantry. The CT images of the dry

core are taken.

• The core is flushed with deionized water and the CT images of water-saturated

core are taken.

• At room temperature, different confining pressures (150-600 psi) are applied to

the core and the corresponding permeability data recorded.

• The core is heated to 200◦C and then the preheated synthetic steam condensate

or brine is injected at a constant of rate of 0.335 ml/min (0.42 m/day). The

effective overburden pressure is kept unchanged at 400 psi. The experiment is

monitored by CT-scanner at all times. Permeability, pH, and silica concentra-

tion of the effluent are measured during the whole test. The total injection time

is 3-4 days.

For this part of the study, a total of 5 tests were performed. The injected fluid

for tests 2,3, and 5 was the synthetic steam condensate with pH = 10. Test 1 used

the brine described in Table 3.2 with a pH value of 10, while test 4 just used neutral

deionized water. Tests 1, 2, 3 exactly followed the above procedure. For test 4, the

injection was stopped after the core was fully saturated with water. The overburden

pressure was still 400 psi but no heat was applied to the core. Test 5 followed almost

the above procedure, except that the effective overburden pressure was only 100 psi.

3.4 Silica dissolution of diatomite

3.4.1 Influence of pH

At room temperature, the brine solutions with four different pH values were used as

injection fluids (Table 3.2). The permeability, effluent pH, and effluent silica concen-

tration were monitored every hour. The change of effluent pH with injected volume of

fluid is shown in Figure 3.7. The pH of effluent for all tests decreases with time, indi-

cating that the hydroxide ion in the injected solution has been consumed by the rock.

3.4. SILICA DISSOLUTION OF DIATOMITE 39

In other words, silica dissolution reaction occurred during the tests. The changes of

effluent pH for the four tests have similar tendency after the injection of the first hour,

regardless of the pH of the injected fluid. In addition, pH almost did not change when

its value was the range of 3.7-4. It is very possible that the equilibrium pH for silica

dissolution reaction was reached under these experimental conditions. The evolution

of silica concentration of effluent with injected volume is shown in Figure 3.8. At the

same injection volume, the greater the pH of the injection fluid, the greater the silica

concentration. Obviously, silica dissolution prefers alkaline condition, because more

hydroxide ion can make the reversible reaction in Eq. 3.1 proceed to the right.

The change of permeability relative to the original value is shown in Figure 3.9.

Increase of permeability is observed after the first hour of injection. The value of

permeability varies and there is no clear tendency for the change. As suggested

by Diabira et al. (2001), dissolution of diatomite matrix is a slow process and the

formation of moderately homogeneous rock cannot be changed substantially unless

a large volume of fluid is injected. The injection time was 4 hours, which explains

why the permeability did not change much during the injection. In addition, the

silica dissolution is not strong enough under the current experimental condition. The

increase of permeability after the first hour may be caused by the release of fines from

the rock matrix, which happens after the core is flushed by solution with low salinity.

Table 3.2: Aqueous solutions used in pH tests of silica dissolution.

Test A Test B Test C Test DTemperature (◦C) 20 20 20 20

pH 4 6 10 12Na+(ppm) 3961 3961 3961 3961Ca2+(ppm) 56 56 56 56Mg2+(ppm) 3 3 3 3Cl−(ppm) 6222 6222 6222 6222

Salinity(ppm) 10242 10242 10242 10242


20 40 60 80 100 1203.5

4

4.5

5

5.5

6

6.5

Injection volume (ml)

Effl

uenc

t pH

pH = 4pH = 6pH = 10pH = 12

Figure 3.7: Effluent pH for tests with variable injected pH.

20 40 60 80 100 1200

10

20

30

40

50

60


Si c

once

ntra

tion

(mg/

L)

pH = 4pH = 6pH = 10pH = 12

Figure 3.8: Effluent silica concentration for tests with variable injected pH.


20 40 60 80 100 1200

5

10

15

20

25

30


∆ k

(%)

pH = 4pH = 6pH = 10pH = 12

Figure 3.9: The change of permeability relative to original permeability for tests withvariable injected pH.

3.4.2 Influence of salinity

At the same temperature (room temperature) and pH, four brine solutions with dif-

ferent salinities were used to study the influence of salinity on silica dissolution of

diatomite. The properties of the four solutions are described in Table 3.3.

According to the change of effluent silica concentration during the three tests

(Figure 3.11), the brine solution with higher salinity caused stronger dissolution.

With the same pH, low salinity solution resulted in greater effluent pH. The reason

may be that the extent of the dissolution reaction is small in low salinity solution, so

the hydroxide ion is not consumed readily and then the pH value remains high. This

result also confirms that silica dissolution is stronger in solution with higher salinity.

As shown in Figure 3.12, permeability did not change much during the injection for

all three tests, which is similar to the results of the pH test. As stated above, silica

dissolution is a slow process and the rock matrix can not be changed much unless

a large volume of fluid is injected. We could notice that the permeability increases

more after the first hour injection for fluid with higher salinity. It also confirms that

solution with salinity is the reason for the release of fines under initial fluid injection.


Table 3.3: Aqueous solutions used in salinity tests of silica dissolution.

Test A Test B Test CTemperature (◦C) 20 20 20

pH 10 10 10Na+(ppm) 131 1900 7798Ca2+(ppm) 56 56 56Mg2+(ppm) 3 3 3Cl−(ppm) 310 3041 12144

Salinity(ppm) 500 5000 20001

20 40 60 80 100 1204.5

5

5.5

6

6.5


Effl

uenc

t pH

Salinity = 500 ppmSalinity = 5000 ppmSalinity = 20000 ppm

Figure 3.10: Effluent pH for salinity tests.


20 40 60 80 100 1200

1

2

3

4

5


Si c

once

ntra

tion

(mg/

L)


Figure 3.11: Effluent silica concentration for salinity tests.

20 40 60 80 100 1200

5

10

15

20


∆ k

(%)


Figure 3.12: The change of permeability relative to original permeability for salinitytests.


3.4.3 Influence of temperature

Silica dissolution of diatomite is studied at room temperature (20◦C), 120◦C, 180◦C

and 220◦C. The experimental conditions for the four tests are described in Table 3.4.

The changes of effluent pH and silica concentration with injected volume of fluid

are shown in Figure 3.13 and Figure 3.14. The effluent pH decreases slowly at higher

temperature, while the silica concentration of effluent is much higher correspondingly.

Both results suggest that silica dissolution of diatomite was strongly promoted at

elevated temperature. Comparing with the influence of pH, salinity, temperature is

more significant for the silica dissolution process. From Figure 3.15, permeability

did not change much even under high temperatures. This result indicates that longer

injection time is necessary for silica dissolution to change the permeability or porosity

of diatomite rock.

Table 3.4: Aqueous solutions used in temperature tests of silica dissolution.


pH 10 10 10 10Na+(ppm) 3961 3961 3961 3961Ca2+(ppm) 56 56 56 56Mg2+(ppm) 3 3 3 3Cl−(ppm) 6222 6222 6222 6222

Salinity(ppm) 10242 10242 10242 10242

We also conducted one test at 180◦C without applying back pressure at the outlet

of the core, so a lot of steam was generated during the experimental process. The

reason is that the outlet pressure of the coreholder is atmospheric pressure. When

the system temperature is above 100◦C, the atmospheric pressure is lower than water

vapor pressure and then water boils. At the same temperature, the results are com-

pared for silica dissolution with and without steam in Figure 3.16 and Figure 3.17.

The change of pH indicates that the extent of silica dissolution reaction is larger

without the presence of steam. The silica concentration of effluent also suggests that


20 40 60 80 100 1202.5

3

3.5

4

4.5

5

5.5

6

6.5


Effl

uenc

t pH

T = 20 degree CT = 120 degree CT = 180 degree CT = 220 degree C

Figure 3.13: Effluent pH for temperature tests.

20 40 60 80 100 1200

20

40

60

80

100


Si c

once

ntra

tion

(mg/

L)


Figure 3.14: Effluent silica concentration for temperature tests.


20 40 60 80 100 1200

200

400

600

800

1000


∆ k

(%)


Figure 3.15: The change of permeability relative to original permeability for temper-ature tests.

silica dissolution is much stronger when there is no steam. Therefore, during the

steam injection process, steam does not cause silica dissolution.

3.4.4 Influence of metal ions

According to Rudenko and Sklyar (1990), metal ions, i.e. Ca2+ and Zn2+, play roles

in diatomite hydrothermal processes. In our study, the effects of Ca2+, Zn2+ and K+

are studied. Four brine solutions with pH = 7 were prepared for this study, as in

Table 3.5. The results of metal ion tests are in Figure 3.18 and Figure 3.19. Both the

change of pH and silica concentration suggest that the influence of metal ions on silica

dissolution can be neglected, for the experimental conditions (room temperature, pH

=10, etc) used here.

3.5 Fracture reconsolidation

Based on our study of silica dissolution of diatomite, we obtain an optimal condition

for silica dissolution and use it in the study of fracture reconsolidation. The two most

3.5. FRACTURE RECONSOLIDATION 47

20 40 60 80 100 1202.5

3

3.5

4

4.5

5

5.5

6

6.5


Effl

uenc

t pH

T = 180 degree C (w steam)T = 180 degree C (w/o steam)

Figure 3.16: Effluent pH at 180◦C (w/ and w/o steam).

20 40 60 80 100 1200

20

40

60

80

100


Si c

once

ntra

tion

(mg/

L)

T = 180 degree C (w steam)T = 180 degree C (w/o steam)

Figure 3.17: Effluent silica concentration at 180◦C (w/ and w/o steam).


Table 3.5: Aqueous solutions used in metal ion tests of silica dissolution.


pH 10 10 10 10Na+(ppm) 3961 3477 3188 0K+(ppm) 0 0 0 5274

Ca2+(ppm) 56 500 56 56Mg2+(ppm) 3 3 500 3Cl−(ppm) 6222 6263 6499 4909

Salinity(ppm) 10242 10243 10243 10242

20 40 60 80 100 1204

5

6

7

8

9


Effl

uenc

t pH

base brine

Ca2+

Mg2+

k+

Figure 3.18: Effluent pH for metal ion tests.


20 40 60 80 100 1201

1.2

1.4

1.6

1.8

2

2.2

2.4


Si c

once

ntra

tion

(mg/

L)

base brine

Ca2+

Mg2+

k+

Figure 3.19: Effluent silica concentration for metal ion tests.

important parameters, temperature and pH, are chosen as 200◦C and 10. In order

to learn the mechanism of fracture reconsolidation under hot-fluid injection, we have

conducted five tests with different injection fluids, confining pressure, temperature

and core samples. The details of the five tests are stated below.

In test 1, we used a fractured core, as in Figure 3.20. The core consists of two

halves with the fracture oriented in the direction of flow. Then the two pieces were

wrapped together by teflon tape to form the fractured core. Basic brine with pH

= 10 was injected into the core. The core was heated to 200◦C and an effective

overburden pressure of 400 psi applied. The injection lasted for 100 hours. The core

was monitored by CT-scanner during the test. The change of effluent pH for test 1

is shown in Figure 3.21. The pH was always below 7. After about 1.3 pore volume

of fluid was injected, the pH even reached an acidic 2.1. These results show that the

dissolution of diatomite at elevated temperature is very strong and it can even occur

under acidic condition. However, the pH only stayed below 3 for a relatively short

time period. The pH of effluent gradually increases and reaches a plateau. According

to Figure 3.22, silica concentration of effluent varied from 150 mg/L to 300 mg/L

most of time. The extent of the dissolution reaction did not change much during the


experiment. Figure 3.23 shows that the permeability of the core increases and reaches

a peak during the early time of the injection. After that, it decreases and becomes

stable during the later stage of the experiment.

The CT images for test 1 were taken at 10 positions of the core at different

times (Figure 3.5). There was a high density area at the original position of the

fracture. It was there since the beginning of the experiment. The high density

line is silty diatomite coming from the drbris on the surfaces of the two halves. As

injection continued, the core gradually reduced volume, as shown in Figure 3.5. Two

factors account for this phenomenon. First, diatomite is soft and very porous, so the

deformation can happen very easily. In addition, the silica dissolution of diatomite

causes loss of rock material, which makes the core to shrink easily under outside force.

Figure 3.20: The fractured core used in test 1 (before fluid injection).

The same diatomite core was used in test 2. Before the injection, the core was

cleaned by deionized water and dried. In this test, the injection fluid was changed

to the synthetic steam condensate with pH = 10. The main difference between the

injection fluids for test 1 and 2 is that the synthetic steam condensate for test 2 is a

buffer solution, so the pH of solution does not change much upon addition of small

amounts of acid or base. The experimental temperature was still 200◦C and the


0 500 1000 1500 20002

2.5

3

3.5

4

4.5

5


Effl

uenc

t pH

Figure 3.21: Change of effluent pH for test 1.

0 500 1000 1500 20000

50

100

150

200

250

300

350


Si c

once

ntra

tion

(mg/

L)

Figure 3.22: Change of silica concentration for test 1.


0 500 1000 1500 20000

200

400

600

800

1000


k (m

d)

Figure 3.23: Permeability change for test 1.

effective confining pressure was 400 psi. Totally 1368 ml synthetic steam condensate

was injected.

The change of effluent pH during the injection is shown in Figure 3.25. Unlike

the pH behavior of test 1, the effluent pH was above 7 most of time. It gradually

increased from the lowest value at the beginning of the experiment. After 581 ml of

fluid was injected, the pH reached 9.6 and remained almost constant until the end of

the experiment. Figure 3.26 shows that the change of silica concentration correlates

with pH change. It was relatively high when pH was relatively low. As pH increased

to a constant value, silica concentration decreased and stayed around 200 mg/L most

of time. The behavior of permeability is also different from that of test 1. As shown

in Figure 3.27, the permeability increased constantly during the injection. In test 2,

the basic pH of the solution was maintained most of time, which is a possible reason

for the increase of permeability. Strong dissolution and long enough injection time

make the diatomite core more permeable, which even compensates the reduction of

permeability caused by confining pressure.

CT images were taken at the same positions as in test 1, as in Figure 3.5. After

456 ml of injection, some small low density areas appeared at the inlet area (x = 0.02).


(a) Injection volume = 0 ml

(b) Injection volume = 117 ml

(c) Injection volume = 266 ml

(d) Injection volume = 641 ml

(e) Injection volume = 1225 ml

(f) Injection volume = 1975 ml

(g) Color bar, CT number

Figure 3.24: CT images for test 1(from left to right: x = 0.02, 0.12, 0.23, 0.34, 0.45,0.55, 0.66, 0.77, 0.88, 0.98).


0 500 1000 15006

6.5

7

7.5

8

8.5

9

9.5

10


Effl

uenc

t pH


0 500 1000 150050

100

150

200

250

300

350

400


Si c

once

ntra

tion

(mg/

L)



0 500 1000 15000

20

40

60

80

100

120


k (m

d)


As injection continued, the areas became larger and similar areas were observed at the

positions next to the inlet area. These low density areas are so-called “wormholes”.

Wormholes are branched channels that result from selective dissolution of the rock

matrix (Hoefner and Fogler 1988). Flow rate and dissolution rate are key factors for

the formation of wormholes. If the dissolution rate is faster than the flow rate, the

base will be consumed immediately after entering the rock. If the dissolution rate is

slower than the flow rate, some base will advance ahead of the average position of

the dissolution reaction. Then the rock ahead of the front is dissolved. The selective

dissolution increases permeability of the area. As a result, more base contacts the

area, leading to further dissolution of this area. Because permeability of this area

is high relative to the other parts of the rock, a channel forms and continues to

grow. Here, the reason for the formation of wormholes is that a basic pH (9.6 or 9.7)

was maintained within the core. There were more than enough hydroxide ions in the

solution to react with the rock, then some extra base flowed ahead of the average front

and selective dissolution occurred in some areas. Consequently, wormholes formed.

The pictures of the branched channels are shown in Figure 3.29. In test 1, the solution

pH was always below 7, which is not a good condition for silica dissolution. The net


dissolution rate in test 1 was lower than the flow rate, so no wormholes were observed

even when the dissolution was not weak. The permeability of a rock can be increased

with the presence of wormholes, which was observed in several studies (Guin et al.

1971, Nierode and Williams 1971). This point is also proved in test 2. The wormholes

formed after about 500 ml of fluid was injected, while permeability began to increase

nearly at the same point.

The porosity distribution along the core before and after test 2 was also recorded,

as in Figure 3.30. The porosity distribution before test 2 was already affected by

hot-fluid injection in test 1, so the results here may not describe the porosity change

very well. For the second half of the core and close to the outlet, porosity was reduced

after test 2. This is because of the squeezing force of confining pressure. But for the

upstream half and close to the inlet, porosity increased. The formation of wormholes

compensated the reduction of porosity caused by confining pressure.

To confirm the results of test 2, a new fractured core was used in test 3, with the

same experimental condition. There are two fractures in the lengthwise direction, as

shown in Figure 3.35; 1446 ml of synthetic steam condensate (pH = 10) was injected

in the test. The changes of permeability, silica concentration, and effluent pH are

in Figure 3.33, Figure 3.32 and Figure 3.31. Similar to the results of test 2, effluent

pH gradually increased until it was 9.6 and the silica concentration decreased to a

relatively stable value of 420 mg/L. The permeability began to increase after about

450 ml of fluid was injected. According to CT images of the core in Figure 3.5,

wormholes began to form at 409 ml of injection and kept growing toward the outlet

direction, which is consistent with the change of permeability.

The fractures are not visible in Figure 3.5. This is not enough to prove that the

fractures were healed, because the confining force applied on the core squeezed the

core and made the three pieces adhere to each other tightly. After test 3, the core was

removed from the coreholder and dried. According to visual inspection of the dried

core (Figure 3.35), the two fractures are gone and the whole core is a complete piece.

We also applied force to try to split the core in the lengthwise direction. The force

was large enough to break a complete untreated diatomite core, but it failed here.

The core after test 3 was even harder than before. This phenomenon suggests that the






(e) Injection volume = 952 ml

(f) Injection volume = 1368 ml

(g) Color bar, CT number

Figure 3.28: CT images for test 2(from left to right: x = 0.02, 0.12, 0.23, 0.34, 0.45,0.55, 0.66, 0.77, 0.88, 0.98).


Figure 3.29: The wormholes formed in test 2.

0 0.2 0.4 0.6 0.8 1

0.58

0.6

0.62

0.64

0.66

x

Φ

Porosity distribution before test 2Porosity distribution after test 2

Figure 3.30: Porosity distribution before and after test 2.


fractures were healed and the core became more consolidated. Figure 3.36 compares

the relationship between permeability and confining pressure before and after test 3.

Both measurements were made at room temperature. Before test 3, permeability is a

function of confining stress. As the effective confining pressure increases from 150 to

600 psi, the permeability decreases from 6.07 to 2.82 md. This phenomenon should

be caused by the very porous structure of diatomite and the presence of fractures.

After the core was treated by hot fluid in test 3, the permeability is not dependent

on the effective confining stress. The confining pressure varies from 150 to 600 psi,

but the permeability changes only a little. According to the results, reconsolidation

of the core occurred after hot alkaline injection. The porosity distribution of the core

before and after test 3 is presented in Figure 3.37. Porosities at different positions

of the core decreased after test 3, which is consistent with the reconsolidation and

fracture healing.

0 500 1000 15002

3

4

5

6

7

8

9

10


Effl

uenc

t pH


It is clear that the fracture reconsolidation of diatomite happens upon hot-fluid

injection, but the reason is still not clear. Which factor plays a role in the recon-

solidation process, confining stress, dissolution, or temperature? In order to find the

answer, we conducted test 4 and test 5.


0 500 1000 1500100

200

300

400

500

600


Si c

once

ntra

tion

(mg/

L)


0 500 1000 15000

20

40

60

80

100

120


k (m

d)







(e) Color bar, CT number

Figure 3.34: CT images for test 3(from left to right: x = 0.01, 0.04, 0.20, 0.32, 0.44,0.56, 0.68, 0.80, 0.92).


(a) The diatomite core before test 3

(b) The diatomite core after test 3

Figure 3.35: The diatomite core before and after test 3.


0 200 400 600 8000

1

2

3

4

5

6

7

Effective confining stree (psi)

k (m

d)

Before test 3After test 3

Figure 3.36: Relationship between effective stress and permeability for test 3.

0 0.2 0.4 0.6 0.8 10.6

0.62

0.64

0.66

0.68

0.7

0.72

x

Φ

Porosity distribution before test 3Porosity distribution after test 3

Figure 3.37: Porosity distribution before and after test 3.


The core used in test 4 had two fractures in the flow direction, as shown in Fig-

ure 3.38. In test 4, only the role of confining stress was considered, so the influence

of other factors was minimized. The effective confining pressure is still 400 psi. The

injection fluid was changed to neutral deionized water and the experiment was con-

ducted at room temperature. When the core was saturated with water, the injection

was stopped so that the influence of silica dissolution was minimized. The confining

stress was kept for the same time period as in test 3. After experiment, the core was

cleaned and dried. The pictures of the dried core are shown in Figure 3.38. The core

did not shrink as much as the core in test 3, even with the same effective confining

stress. The fractures did not disappear or become smaller, suggesting there was no

fracture healing during test 4. The relationship between permeability and confining

stress is also compared, as in Figure 3.39. Permeability is a function of confining

pressure before reconsolidation. The permeabilities before and after test 4 are of the

same magnitude. Obviously the core did not reconsolidate during test 4, which means

that confining stress only can not cause the fracture consolidation of diatomite.

The role of dissolution was of the interest in test 5, so the influence of confining

stress was minimized. The core used in test 5 had two fractures normal to flow

(Figure 3.40), avoiding the influence of confining stress. The same solution as in

test 2 and 3 was injected into the core at 200◦C, which is a good condition for

silica dissolution. Since confining pressure is necessary to seal the lateral surface

of the diatomite core, an effective confining pressure of 100 psi was applied to the

core. A total volume of 1560 ml of fluid was injected during test 5. After the

experiment, the core was taken out of the coreholder and dried. The three pieces

stuck to each other like a complete core. However, it broke into three pieces again

when a little force was applied (Figure 3.40). There is some white material on the

surfaces between fractures, which looks very different from the background. It may

be precipitated silica, brine, or some materials from the other piece. Wormholes are

observed again, indicating strong dissolution occured during test 5 (Figure 3.40). The

effect of confining stress on permeability before and after test 5 was studied at room

temperature, as in Figure 3.41. The line representing the result after test 5 is a

little bit flatter than that before test 5, but generally there was no reconsolidation


(a) The diatomite core before test 4

(b) The diatomite core after test 4

Figure 3.38: The diatomite core before and after test 4.


0 200 400 600 8006

8

10

12

14

16

18


k (m

d)



happening during the experiment. Therefore, silica dissolution alone cannot cause

fracture reconsolidation, either. Both sufficient confining stress and strong dissolution

result in fracture reconsolidation of this diatomite sample.

3.6 Discussion

The influence of pH, salinity, temperature and metal ions on silica dissolution of

diatomite was studied by conducting short-time fluid injection. Among the four

factors, pH and temperature are the most significant. This is explained according to

the reaction equations of dissolution. At pH 7, the predominant form of dissolved

silica is H4SiO4. But when at basic conditions, H4SiO4 further dissociates as follows

(Ikeda et al. 2007).

H4SiO4 + OH− À H3SiO−4 + H2O (3.3)

H3SiO−4 + OH− À H2SiO2−

4 + H2O (3.4)

3.6. DISCUSSION 67

Figure 3.40: Diatomite core in test 5: a. The core before test 5; b. The core aftertest 5; c. The surfaces between one fracture after test 5; d. Wormholes formed in test5.


0 100 200 300 400 500 600 7000

0.5

1

1.5

2

2.5


k (m

d)



Increasing pH directly influences the reaction direction and makes the extent of

dissolution reaction larger. Temperature affects the kinetics of silica dissolution in a

similar way. The rate constant, k+, of the dissolution reaction in Eq. 3.1, is expressed

as below.

logk+ = a + bT + c/T (3.5)

T is in Kelvin. The values of a, b and c for amorphous silica are -0.369, −7.89× 10−4

and -3438 (Rimstidt and Barnes 1980). When temperature is below 2087 K, the

higher the temperature, the greater the rate constant, especially in the range of 0-

1000 K. Therefore, pH and temperature are the two most important factors in silica

dissolution of diatomite, while the influence of salinity and metal ions can be neglected

most of time.

According to the results of test 1 in the fracture reconsolidation study, strong

silica dissolution even happens under very acidic condition at elevated temperature.

The enhanced rate constant at high temperature is the main reason. According to

the change of silica concentration of effluent, silica dissolution of test 2 occured to

an extent similar to that of test 1, because both tests had the same rate constant at

3.6. DISCUSSION 69

the same temperature. However, wormholes were only observed in test 2. Wormholes

are branched channels that are resulted from selective dissolution of the rock matrix

(Hoefner and Fogler 1988). The magnitude of dissolution rate relative to the flow

rate is the key factor for wormhole formation. When the dissolution rate is faster,

the injected base is consumed immediately upon entering the rock. If the dissolution

rate is slower, some base will advance ahead of the average position of dissolution

reaction and dissolve the rock ahead of the front. For test 1, the solution in the pore

space was always acidic and there was no extra base for selective dissolution. The

injection fluid of test 2 was a buffered solution that maintains the solution pH upon

interruption of small amounts of acid or base. A pH of 9.6 or 9.7 was kept within the

core most of time, so some extra base flowed ahead of the average front and selectively

dissolved some areas. As this process continued, wormholes formed and propagated.

As a result, the permeability increased in test 2. There were no wormholes in test 1,

so the permeability was not enhanced.

According to the results of test 2 and test 3, the fractures in diatomite cores were

healed after hot alkaline flooding. Those core also reconsolidated. Confining stress or

silica dissolution may play an important role in this process, so we conducted two more

tests to study the mechanism of fracture reconsolidation. Test 4 suggests that only

confining stress could not result in fracture healing and consolidation of diatomite.

Test 5 shows silica dissolution alone cannot cause fracture reconsolidation, either.

Though the confining stress was relatively small in test 5, it still has its influence.

That is why the observations of test 5 are closer to reconsolidation behavior than

those of test 4. Therefore, fracure reconsolidation must result from the cooperation

of confining stress and silica dissolution. Confining stress must be strong enough and

silica dissolution also needs to be strong.

We have found the sufficient conditions for fracture reconsolidation, but we still

know little about the mechanism. Silica reprecipitation was believed to be a possible

reason. However, the experimental conditions in tests 2 and 3, i.e. high temperature

and basic pH, are favorable for silica dissolution. In other words, it is unlikely for

the reverse reaction, silica precipitation, to occur during hot-alkaline injection of

diatomite. Though the experimental condition is not good for silica reprecipitation,


it may be favorable for silica gelation. As introduced at the beginning of this chapter,

both gelation mechanisms require high temperature. Considering the pH is 9.6 or

9.7 most of time in our experiments, colloidal silica gelation is excluded. The reason

is that colloidal silica is stable and does not form gel in the pH range of 9-10. In

addition, the gelation time of colloidal silica is long (normally 100-1000 days), so

it is not applicable in our tests. Silicate gelation happens in the pH range of our

experiments and the gelation time is relatively short. It is one important factor for

the mechanism of fracture reconsolidation, but not the only factor. Silica gel is an

intermediate state between liquid and solid and it becomes a rigid solid after loss of

solvent (Larry and West 1990, Cowen et al. 1996). This process is a polycondensation

reaction, which expells water and forms SiO2 networks again. A variety of factors

affect this process, such as pH, temperature, pressure, and reagents concentration

(Larry and West 1990). For the effect of pressure, Artaki et al. (1985) found that

application of pressure to the silica gel system increases the polycondensation rate

constant. Similarly, confining stress in our study promotes the transfer from silica

gel to solid silica. The mechanism of fracture reconsolidation can be divided in three

steps. First, silica is dissolved by injected hot fluid and silicate is the main product

of this step. Next, silica gelation happens under the experimental condition and the

fracture is filled with silica gel. Confining pressure has two functions in the last step.

It pushes the core tightly and makes the size of fracture as small as possible. It also

speeds up the transformation of silica gel to solid silica in fractures.

3.7 Summary

Experiment results suggest that temperature, pH and salinity affect silica dissolution

of diatomite, especially the first two. The influence of metal ions on silica dissolution

can be ignored. When temperature is below 2087 K, elevated temperature promotes

the dissolution of silica. Similarly, the greater the pH and salinity, the stronger the

dissolution. At the same temperature, silica dissolution without steam is stronger

than that with steam, indicating that the presence of steam in diatomite slows the

dissolution reaction.

3.8. CONCLUSIONS AND FUTURE WORK 71

Wormholes were observed for silica dissolution under hot alkaline flooding. The

formation of wormholes was resulted from selective dissolution of diatomite by extra

base in injected fluid. Basic pH within the pore space of diatomite is significant

for this process. That is why wormholes were not found in test 1, even though

silica dissolution was strong. The formation of wormholes increases permeability and

porosity of diatomite core. According to the results of long-time hot brine injection

(test 1), the extent of the dissolution reaction is still large even under very acidic

conditions. Therefore, temperature is the primary factor in silica dissolution and

fracture reconsolidation of diatomite.

The mechanism of fracture reconsolidation was studied. Enough confining stress

and strong dissolution are necessary for this process. Under the experimental condi-

tion in tests 2 and 3, it is unlikely for silica reprecipitation to happen. Silicate gelation

occurs instead. The fracture reconsolidation is divided in three steps. The first step

is silicate production by silica dissolution. Next, silicate gelation occurs under the

experiment condition in test 2 or 3. In the third step, confining stress enhances the

transformation of silica gel to solid silica.

3.8 Conclusions and future work

Based on the experimental results of the silica dissolution study and hot fluid injection

tests during a relatively long time period, the following conclusions are obtained.

1. Higher pH, salinity and temperature result in stronger silica dissolution of di-

atomite, while the influence of metal ions can be neglected. Among the four

factors, pH and temperature are the most significant.

2. The presence of steam in diatomite hinders silica dissolution.

3. The formation of wormholes during hot fluid injection requires two prerequisite

conditions. First, silica dissolution rate should be lower than flow rate of injec-

tion fluid. Second, there is extra base available to dissolve selectively silica in

diatomite rock. The formation of wormholes leads to increase of permeability

and porosity.


4. Fractures are healed during hot fluid injection, that is caused by the cooperation

of silica dissolution and confining stress.

5. A mechanism of fracture reconsolidation was proposed. It consists of three steps:

silica dissolution, silicate gelation, and confining stress-promoted transformation

of silica gel to solid silica.

To better understand the process of heavy-oil solution gas drive and hot fluid

injection into diatomite, the following works need to be completed.

1. The silica dissolution and fracture reconsolidation of diatomite need to be ana-

lyzed completely by XRD, SEM and FTIR.

2. The proposed mechanism of fracture reconsolidation needs further confirmation.

3. The influence of silica dissolution and fracture reconsolidation on oil recovery

from diatomite needs to be studied.

4. A test of fracture reconsolidation at high temperature and with confining stress,

but no flow of brine should be conducted.

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the impact of oil chemistry on heavy-oil solution gas drive and

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