chemical osmosis, shale and drilling fluids

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Copyright 2002, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the IADC/SPE Drilling Conference held in Dallas,Texas, 26–28 February 2002.

This paper was selected for presentation by an SPE Program Committee following review ofinformation contained in an abstract submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the Society of Petroleum Engineers and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Society of Petroleum Engineers, its officers, or members. Papers presented at

SPE meetings are subject to publication review by Editorial Committees of the Society ofPetroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paperfor commercial purposes without the written consent of the Society of Petroleum Engineers isprohibited. Permission to reproduce in print is restricted to an abstract of not more than 300words; illustrations may not be copied. The abstract must contain conspicuousacknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O.Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435

Abst ractThis paper describes continuing efforts to develop a water-

based drilling fluid that will provide the osmotic membrane behavior and wellbore stability of an oil-based drilling fluid.A pore-pressure-transmission technique in use for severalyears as a tool to measure osmotic behavior has been refinedfor improved measurement of changes in shale permeabilityand pore pressure in response to interaction with drilling

fluids. Conventional invert emulsion and water-based drillingfluids containing selected additives were tested with outcropand preserved shale specimens using an innovative screeningmethod.

Observed pressure differences were compared with values predicted by osmotic theory. From this comparison, anempirical concept of “membrane efficiency” was developed.Three distinct types of “membranes” are postulated to describethe interaction of various drilling fluids with shales. Type 1membranes are generally characterized by coupled flows ofwater and solutes between fluid and shale. Type 2 membranesgreatly reduce surface permeability of the shale restricting

both flow of water and solutes; the latter to a greater extent.Type 3 membranes more selectively transport water but shale

permeability and fluid chemistry may alter performancemeasurements. Invert emulsion fluids tend to form efficientType 3 membranes; however, these fluids can, under certainconditions, yield lower capillary pressures than previouslydescribed and invade the interstitial fabric of a shale.

Several water-based mud formulations were preparedwhich achieve about ¼ to ½ the measured osmotic pressure ofa typical oil-based mud. Fluid additives which supplement orreinforce a Type 1 membrane, such as saccharide polymers,

(especially in combination with calcium, magnesium oraluminum salts) can exhibit relatively high efficiencies. Asexpected, fluids which form a Type 2 membrane such assilicate and aluminate muds, provide the highest membraneefficiencies. Some may prefer to view these describedmembranes as a simple seals, but they are less or moreefficient membranes, nonetheless.

Basic Osmosis ConceptsLeakiness governs the effectiveness of osmosis and is thedeterminer of efficiency for a semi-permeable membrane. Asemi-permeable membrane restricts the passage of soluteswhile the solvent is relatively unrestrained. Leakiness maymore accurately describe a phenomenon for which the term“selectivity” has been previously applied.

Efficiency of the membrane is quantified by the reflectioncoefficient, σ. The “reflection” analogy comes from an opticalmodel adopted by researchers. The model assumes a semi-

permeable membrane analogous to a mirror – fully or semi-

silvered. All solutes of a solution to which a membrane isexposed will be fully or partially “reflected” by the membrane.An ideal semi-permeable membrane, i.e. one that allows

passage of the solvent only, has a reflection coefficient, σ, of100% or 1. Non-ideal membranes which allow partial passageof solute have reflection coefficients, σ, of less than 1 and aretherefore referred to as “leaky”.

Clay-based materials have intrinsic membrane behaviorwith reflection coefficients between 0 and 1, depending on thefluid contacting the clay surface. A high-permeability sand,on the other hand, does not exhibit semi-permeable propertiesand the reflection coefficient of the sand is essentially zero.

For a system at thermal and electrical equilibrium, osmosisacross a semi-permeable membrane consists of transport ofsolvent – usually water – from higher water activity to lowerwater activity, i.e. from the side containing a lowerconcentration of solute (dilute) to the side with higherconcentration of solute (concentrated) such as a salt, sugar, orglycol. This flow of pure solvent is commonly referred to as“chemico-osmosis” or “chemical osmosis.” Flow of solventwill continue unless or until osmotic pressure is balanced byhydraulic pressure. For an ideal semi-permeable membrane,that is the extent of osmosis. For a leaky membrane, however,

IADC/SPE 74557

Chemical Osmosis, Shale, and Drilling Fluids

R. Schlemmer, J.E. Friedheim, and F.B. Growcock, M-I L . L . C . ; J.B. Bloys, ChevronTexaco



2 R. Schlemmer, J.E. Friedheim, F.B. Growcock, J.B. Bloys SPE 74557

solute species will also flow, and can flow in both directions; 1-

3 furthermore, hydrated species will carry solvent with them,thus leading to countercurrent flow of water and solutes. 4,5 For a shale in contact with a typical salt-based aqueousdrilling fluid, water will flow from the shale into the drillingfluid, but opposing, hydrated, cations and anions will flowfrom the drilling fluid into the shale. Additionally, hydrated

salt species in the pore network of the shale will tend to flowinto the drilling fluid. Further complicating the picture is theresulting exchange of ions on the clay, which will then alsocontribute to the complex dance. These “coupled flows”which characterize osmosis complicate prediction ofmembrane efficiency. 5

Soil scientists and drilling fluids researchers commonlyobserve osmotic pressure development as a developinghydraulic head in an atmospherically pressured environment.Measured osmotic pressure curves typically develop as

presented in Figure 1 The slope of the pressure developmentcurve of an ideal membrane approaches zero. The slope of the

pressure development curve of a non-ideal membrane becomes negative after a period of equilibration.

Fig. 1 – Pressure Development Curves for ideal and non-idealsemi-permeable membranes. 1 (reproduced with permission ofThomas Keijzer)

The clays composing shales are natural membranes. Theyare made up of combinations of two basic structural units.The silica tetrahedron and alumina octahedron are assembledin sheets. Clay minerals are characterized by the differencesof stacking of these sheets and the manner by which the sheetsare held together. Differences in the crystal structure of thesheets (isomorphic substitutions) are seen commonly asreplacement of Al 3+ for Si 4+ in the tetrahedral sheet and Mg 2+

for Al3+

in the octahedral sheet. These substitutions cause claysurfaces to have a net negative surface charge. Electricalneutrality is preserved by attraction of cations which are held

between the layers and at the surface of the platelets. Thiselectrostatic attraction results in a charged clay surface and aconcentration of counter-ions which diminishes with distancefrom the surface. The charged clay surface, with the counter-ions in the pore water, forms the diffuse double layer. Thedouble layer is affected by changes in salinity, pH,temperature, and valence of counter-ions. 1

The ability of clays to act as membranes is a consequenceof overlapping double layers of adjacent clay platelets.Compaction, as occurs during formation of shales, results inhigher concentration of cations and reduced concentration ofanions in the double layer with respect to an equilibriumsolution. The aqueous environment of narrow pores can beoverwhelmed by the merged, opposing double layers.

Diffusion of anions through the narrow aqueous film isinhibited, because the anions are repelled by the net negativecharge of the platelets. Advection (flow of solutes and heatthat accompany bulk motion of a fluid) is restrained. Theeffect is known as the “Donnan Exclusion”. 4

Because anions are inhibited from diffusion into the pores,associated cations are also inhibited from moving across theclay. This inhibition contributes to a membrane effect andincreasing membrane efficiency, σ. The stacking of clay

platelets and the narrow pore openings in shales also creates amatrix capable of supporting deposited (Type 2) and non-aqueous (Type 3) membranes. Thus, in principle, Type 2 andType 3 membranes do not require or depend on fluid-clayinteractions. 4,6 whereas Type 1 membranes are stronglyinfluenced by fluid-clay interactions. In practice, morphologyof the clay structure and fluid-pore water interactions may

play significant roles in the construction and maintenance ofall three types of membranes.

Membrane ideality of an exposed natural clay/shaledepends on several factors; most important are:

• Clay type; clay with high negative charge (expressedas the CEC) generally provide superior semipermeablemembranes than clays with a lower CEC. The doublelayer is “thicker”.

• Clay/Shale porosity; the more compacted theclay/shale, the more double layers overlap to form acontiguous membrane.

• Salt concentration of the pore water of the clay; lowersalt concentration also results in a “thicker” doublelayer, and more ideal membrane. 1

• Change in any of the above due to compaction.• Drilling fluid composition; the nature of the clay/fluid

interface is influenced strongly by physical andchemical interaction of solute species in the mud withthe clay surface and/or dilution of bound water bydrilling fluid solvent.

Illustrating these factors are Figures 2 and 3. Figure 2 presents reflection coefficients, σ, as a function of porosity fora refined montmorillonite with CEC of 100 meq/100 g and anillite with CEC of 20 meq/100 g, using a mean saltconcentration of 0.35 mol/L NaCl. Figure 3 comparesreflection coefficients of a commercial montmorillonite testedat two salt concentrations. 2

The interaction of drilling fluids with shales may becategorized in terms of formation of three types of“membranes,” as shown in Table 1. It should be emphasizedthat the term “membrane” is used here solely for the purposeof illustrating how the drilling fluid/shale interface affects theflow behavior of species between the drilling fluid and shale.



SPE 74557 Chemical Osmosis, Shale, and Drilling Fluids 3

Fig. 2 – Clay type - Reflection coeffic ient vs. porosi ty. 2

(reproduced with permission of Soil Science of America)

Fig. 3 – Salt concentration - Reflection coefficient vs. porosi ty. 1 (reproduced with permission of Thomas Keijzer)

Membrane Type 1 is constructed within the shale. For thistype membrane, drilling fluid filtrate, shale/clay, and porefluid chemistry, as well as pore dimension, filtrate viscosity,

permeability, clay components, and shale cementation all cancontribute to development of membrane effect and a moreideal σ . The major portion of developmental effort has beenon water-based materials supporting Type 1 membranes. Type1 membranes are generally characterized by σ < 0.2. 7

Membrane Type 2 side-steps the physicochemical forcecomplications. A Type 2 membrane is efficiently laid down asa relatively impermeable deposit or precipitate primarilyexternal to or within the near-wellbore shale matrix. This type

of membrane is typical of in-situ polymerized oligomer,silicate, and some aluminum-based fluids. 3

Membrane Type 3 is associated with invert emulsion-baseddrilling fluids and does not depend upon a deposited or

precipitated solid film. A mobile film of the continuous phase plus surfactants of the drilling fluid bridges and separates the

internal aqueous phase of the drilling fluid from water-filledshale pores. Although it is possible for anions and cations todiffuse through non-electrolytes as charge neutral ion pairs ornet charge neutral groups, 8 laboratory studies of low-

permeability shales indicates that solutes do not readily diffuseacross the non-aqueous membranes generated by invertemulsion fluids. 3 Downhole Simulation Tests conducted withhigh-permeability shales, on the other hand, have generatedconflicting results. In earlier work with a conventional low-toxicity mineral oil invert mud, no ion exchange appeared tooccur in the shale. 9 Later studies with a synthetic-based invertmud indicated that ion exchange occurred as deeply as ¼ to ½in. into a relatively high permeability shale. 10

Table 1 - Membrane TypesMembrane Type 1 Type 2 Type 3

Position Internal PrimarilyExternal

PrimarilyExternal

Character Dynamic, NotPermanent

Static FixedDurable

Dynamic, NotPermanent

Double LayerEffects Dependent Independent Independent

Clay/shaleEffects Dependent Independent Independent

TypicalReflection

Coefficient ( σ )<0.2 >0.5 1.0*

OsmoticPressure

To 1000 psi6.9 MPa

To 4000 psi27.6 MPa Variable

* Ref. 2

Shale Stability and Membranes. The phrase "ShaleStability" will be avoided in this paper, but if one goal is to beascribed to the shale membrane studies, it would be todemonstrate "shale stability" improvement in a variety ofwater-based drilling fluids. As described here, the term is notassociated with traditional cuttings stability, bentonite pelletstability, or bulk hardness tests. Shale bits and pieces,disrupted by mechanical and hydraulic forces at the bit andfurther influenced by chemical effects on their way to thesurface, are only of concern to the operator and mud engineerfor about an hour or two. At issue here is the ability to

maintain an open hole through sensitive shale for periods ofdays or weeks, allowing extended trouble-free drilling usingwater-based drilling fluids. For decades, intact shale pieceshave been evaluated, as presented in Table 2 , by exposure todrilling fluids in pressured and unpressured vessels. In recentyears, shale samples have been routinely exposed todifferential pressures which induce fluid diffusion through aconfined shale specimen. Traditional shale stability teststypically measured changes in physical properties. Shale




membrane tests measure development of pressure changesand/or fluid flow across the shale.

Table 2 – Shale Test Characteris tics

Shale Stability Test Shale Membrane Test

• Hardness change• Moisture content change• Dimensional change• Tensile/compressive

strength change• Extrudability• Dispersibility

abrasionhot-roll

• Salinity change

• Chemical osmotic flow volume• Chemical osmotic pressure

development• Hydraulic flow volume• Hydraulic pressure development• Net direction & volume of flows• Shale permeability• Shale/fluid conductivity• Water/oil content

The standard by which fluids are judged is the invertemulsion drilling fluid. The diesel oil-based fluids of the1960’s, built from tall oil soaps and polyamide surfactants, arethe prototype for recent variants and continue to be used.

Diesel oil has been replaced to a degree, market by market,with mineral oils, hydrogenated mineral oil, paraffins,hydrogenated olefins, polyolefins, ethers, and esters. Theoriginal polyamide-type surfactant, calcium soaps, and similarmaterials provide excellent emulsion stability. Thesematerials concentrate at the interface between the dispersedaqueous phase and the continuous non-aqueous fluid. Saltsand other water-soluble materials are dissolved in the internalaqueous phase of invert emulsion fluids to establish aconcentration gradient and generate a chemical osmotic force.The backflow of simulated pore fluid resulting from thisosmotic force is measurable in the laboratory. In the field,anecdotally, the induced osmotic backflow of formation-porefluid into the invert emulsion drilling fluid is observed aschange in oil/water or synthetic/water phase ratio and areduction in salt concentration of the internal phase. Activitymeasurement applied to the Gibbs activity-osmoticrelationship predicts that a potential osmotic pressuredevelopment for an invert emulsion fluid with 300,000 mg/LCaCl 2 dissolved in the internal aqueous phase is 10,000 psi.With literature reporting σ = 1 for invert emulsions, thosemuds must be powerful indeed!

System Design. The Shale Membrane Tester (SMT) issimilar to the pore-pressure-transmission device described in a

paper presented at Eurock '94. 11 The five membrane-test cellseach mount a shale core, diameter of 25.4 mm and length of 6to 8 mm. A radial confining stress is applied. Test cells andshut-in valves are enclosed in an oven which allows testing to250°F. The basic equipment arrangement is as shown in Fig.4. A more detailed description of Test Equipment, Procedure,and Sources of Error can be found in Appendix B .

The shale cores used in these experiments were cut fromoutcrop. The shale (X-ray diffraction, ion exchange, and

porosity/permeability data are given in Table 3 ) was supplied

by TerraTek Inc., Salt Lake City, USA and described as“Pierre 1e”.

Table 3 – Shale Characterization DataPierre 1e

Quartz 34%

Feldspar 6%

Calcite 1%

Dolomite 5%

Siderite -

Pyrite 2%

Kaolinite 6%

Illite/Mica 18%

Chlorite -

Smectite and Mixed Layer 28%

CEC (mEq/100 g) 22

Porosity 17%

Permeability, Horizontal (D) ~ 1x10 -6

Permeability, Vertical (D) ~ 1x10 –7 – 10 –8

Reservoir Pressure Development. Reservoir pressuredevelopment is dependent upon factors including, but notnecessarily limited to ion diffusion, osmotic diffusion,

hydraulic (Darcy) flow, barrier development, and, perhaps,viscosity of the diffusate. Osmotic diffusion of water isdependent upon a difference in ion/solute concentration on therespective wellbore and reservoir sides of the test cell. Asion/solute diffusion progresses, osmotic differential pressurewill decrease. Darcy flow of water is dependent upon pressuredifference between wellbore and reservoir sides of the testcell. Darcy flow can be opposed by osmotic diffusion.

The addition of any dissolved material to the mud willgenerally decrease its water activity and increase potential

Fig. 4 – SMT System Schematic.




osmotic pressure development. While measured pressuredifferential may increase only temporarily, dissolved mineralsalts can produce long-term effects on shale in several ways:

1) collapsing the double layer on clays2) dissolution of sulfate or carbonate cementation

3) alteration of swelling characteristics by ion exchange.Mineral salts will also affect polymers present in the drillingfluid. If the viscosity or plugging effect is decreased, themeasured osmotic pressure can decrease despite a loweractivity of the drilling fluid. On the other hand, it is seen thataddition of moderate amounts of calcium salt may so affectthe structure of polymer or shale that the permeability isdecreased or polymer-mediated viscosity increased, therebyreducing the flow of fluid into or out of the shale.

Experimental Definition of Membrane Efficiency. For purposes of this screening work, a very simple model ofmembrane efficiency is applied. Membrane efficiency, as

presented in Equation 1, is calculated from the measuredinitial stable differential pressure compared to the potentialosmotic pressure.

( )

Pr)-PwM e

π = (Eq. 1)

whereMe = nominal membrane efficiencyPw = applied wellbore pressurePr = recorded equilibrium reservoir pressureπ = potential osmotic pressure

Osmotic pressure, π , is dependent upon the relative

colligative properties of the test fluids which are oftenmeasured as solution activities. When water is the testsolvent, π can be calculated from the difference in wateractivities of the test fluids. Osmotic pressure can be calculatedfrom measured activity values or published values asappropriate for each test solution may be applied. Figure 5was prepared from published activity values. Such publishedvalues are used to calibrate a laboratory activity test device.

Potential osmotic pressures for saccharide-based and othersolutes were calculated individually from activity values

measured using vapor-pressure osmometry. Measured activityvalues were converted to osmotic pressure using the Equation2:

π = RT lnXA (Eq. 2)where

π = osmotic pressureR = gas constant (0.08206 L atm/mol K)XA = activity

For SMT tests, the reservoir fluid has water activity ofapproximately 1, thus the potential osmotic pressuredeveloped between the test fluid and the reservoir fluid isessentially that given by Equation 1. However, thesemeasurements, adequate for sample screening, do not take intoaccount ongoing changes to the shale. In addition to initial

pressure development, subsequent changes are indicative ofthe net effect of exchange of water, non-aqueous liquid, orsolute over time. Those ongoing changes are manifested inthree ways in the SMT. The initial osmotic effect may be

profound or gradually trending up or down or change not at alldepending on the type of membrane that is formed. Using thetest apparatus described the pressure differential of appliedmud pressure and developed reservoir pressure is recorded.This measurement method produces a curve inversely

proportional to the hydraulic head development curve presented in Figure 1. Therefore generally one can expect a positive slope of increasing reservoir pressure with a Type 1membrane, a zero slope and constant reservoir pressure with aType 2 membrane, and, frequently, a negative slope ofdecreasing reservoir pressure with Type 3 membrane. Whenrecording differential pressure a zero slope or negative slopeindicates stable or increasing osmotic pressure and is

preferred.

A rising pressure curve indicates decay of osmotic pressure differential and is typical of water-based drillingfluids. A constant pressure indicates that fluid flux is zero orthat a solvent/solute equilibrium condition has beenestablished across the shale membrane. This equilibrium istypical of properly formulated silicate drilling fluids. Fallingreservoir pressure indicates improving membrane efficiency.This study demonstrates that in some cases pore fluid movesout of the reservoir but may be partially or totally replaced bynon-aqueous filtrate from the drilling fluid in the wellbore.

Membrane efficiency, σ, generally changes with shaleexposure time, pressure differential, and salt concentration. Asimple membrane efficiency calculation is therefore not

available for judging solute performance in these tests. Thenominal, initial σ is therefore adjusted by the slope of thedeveloping osmotic pressure curve to yield, for convenience

of chemical evaluations and comparisons , a “ factor” for judging the effectiveness of additives. The developingosmotic pressure and slope of the ongoing pressure curve arequantified in the data collection, Appendix A . The slope ofthe ongoing pressure curve is normalized against pressuredrop and time. A negative or low “ σ factor” is an indicator ofreasonably stable osmotic properties ( Figure 5 ). Both initial

Fig. 5– Osmotic Pressure of Salt Solutions.




osmotic pressure and a slope of the developed pressure curveare combined in a “ σ factor” calculated by Equation 3:

σ factor = 10000 * m / π (Eq. 3)

Where:m = slope of ongoing pressure trendπ = nominal osmotic pressure (from y intercept)

Both slope and nominal osmotic pressure are determinedfrom the linear regression trendline of data collected aftersystem is reasonably equilibrated. Nominal osmotic pressureis the difference between applied mud pressure and y-interceptfrom regression data.

Because the SMT measures reduction in reservoir pressurerather than an increase in wellbore hydraulic head, the

pressure response and slope measurement will be oppositethat discussed in the introduction/background. Reducedmembrane efficiency ( σ < 1) or leakiness is demonstrated by a

positive “ σ factor”. Membrane efficiency of 1 is predicted by

a calculated “ σ factor” of zero or, in the case of invertemulsion-based fluids, a negative value.

Example Test and InterpretationFigure 6 illustrates that osmotic effect persists through the192-hour test. To test for osmotic effect, the reservoir

pressure of WBM B, 10% CaCl 2 formulation, was raised by100 psi at 132 hr into the test. Over the next 24 – 28 hr, thechemical osmotic pressure product of the residual salt-concentration gradient returned the reservoir pressure to anormal and natural trendline; thus demonstrating a persistentand continually changing membrane efficiency.

More important for test purposes is the relationship

between the two pressure response curves. The compositionof the two test fluids was as shown in Table 4 . As might beexpected, WBM A, the lower activity fluid, produced thegreatest drop in reservoir pressure. Salts of divalent cations

generally produce more stable membranes which is shown bythe reduction in slope of the ongoing pressure curve of WBMB as compared to WBM A. A linear trend line wasestablished for a equilibrium section of each curve and slopecalculated. From slope, y-intercept, an initial maximumosmotic pressure was calculated “ σ factor”.

In this test, the 24-hr pressure fluctuations were caused by

change in pump-control sensitivity resulting from diurnalswings in room temperature. Wellbore pressure ranged from882 to 911 psi tracking building environmental change. Oventemperature was nominally 150°F with variance of no morethan +/- 0.1°F during the test. Daily fluctuation in wellbore

pressure was passed to reservoir measurements with no morethan 15% degradation in amplitude.

Materials of InterestInitially the materials of interest were evaluated in fresh waterand in 20% sodium chloride salt solutions. As need arose toscreen more materials, a standard test fluid was mixed fromtap water, 20% w/w sodium chloride salt, and with up to 30-

lb/bbl test material. Reduced concentrations of test materialwere used to compensate for excessive viscosity developmentof polymers and other higher viscosity additives (viscosity

building materials typically did not perform well in thesetests). A concentration was selected which allowed

preparation of a mixed test sample which displayed a yield point of less than 20 lb/100 ft 2. Xanthan gum polymer wasadded to increase and equalize yield point of fluids.

A 20% salt solution was selected for use in these tests forthree reasons. Many Gulf of Mexico water-based drillingfluids specify 20% sodium chloride to reduce thecrystallization of gas hydrates at the low temperaturesexperienced in deepwater drilling. In addition to gas hydratesuppression, sodium chloride has been shown to provide ameasure of shale stability in traditional tests. Other salts,which may provide improved membrane effects, aredetrimental to the mysid shrimp used to test toxicity of Gulf ofMexico drilling fluids. Since a 20% sodium chloride solutioncan potentially produce an osmotic pressure of 3500 psi,measurable pressure development can be expected to occurdespite membrane efficiencies reported in the literature to betypically less than 5%. 7

Individual novel materials tested during three yearsincluded:

Acrylic acid based polymers (14)Siloxanes (11)Polyamines (6)

Saccharides and derivatives (28)Lignosulfonates, tannins, resins (7)Other polymers (16)Plugging materials (5)Glycols, polyglycols, and derivatives (13)Miscellaneous surfactants (26)

When materials with interesting membrane properties werediscovered, they were also tested at one or more calcium

Shale Membrane TestPierre 1E shale sample - High Performance WBM

with carbohydrate blend and selected saltPore Fluid 0-17hr Test Fluids 17-185hr

400

500

600

700

800

900

1000

0 24 48 72 96 120 144 168 192Time, hr

P r e s s u r e

, p s

i Wellbore (Mud) Pressure

Pore Pressure, HPWBM - 20% NaCl

Pore Pressure, HPWBM - 10% CaCl2

Fig. 6 – WBM Comparison.




chloride concentrations. The most successful candidates werealso combined with other novel shale stabilizing materials forfurther product development.

A partial list of “activity enhancers” which were tested inwater-based drilling fluids and/or synthetic-based drillingfluids included both ionic and non-ionic materials along withsolutes intended to replace or supplement 20% NaCl as water

activity suppressants:calcium chlorideformatesglucose (Aldrich Chemical Co.)sucroseglycolsmethylglucoside monomer (Sigma Chemical Co)commercial methylglucosidesmolassescommercial table sugarvinyl alcohol

In addition, fully formulated muds weighing up 20 lbm/galwere evaluated.

Performance Resul ts - Membrane Type 1Saccharides and derivatives. As a class, the saccharidesmaterials are promising. Osmotic pressures of severalhundred pounds per square inch characterized certainundiluted commercial methylglucoside materials. Addition of50% water to commercial methylglucoside concentratedmaterial with addition of sodium chloride salt to restore fluidactivity did not maintain the osmotic pressure developmentseen with the pure or less dilute commercial material.

Proprietary saccharide mud systems containing blends ofsugars and oligomers, originally applied in the North Sea in1991, display an osmotic effect similar to and in manyapplications superior to commercial methylglucoside. Use of

polyvalent salts improves the plugging/viscosity effects of thisclass of osmotic enhancers. Proprietary saccharides muds do,as originally claimed, provide stable osmotic pressuredevelopment. Commercially available table sugar mixed atequal solids concentration to the proprietary saccharides mudsystem did not provide equivalent osmotic pressure. Peakosmotic drawdown of recorded reservoir pressure was highand pressure recovery curve was nearly horizontal,approaching zero slope and indicating a σ = 1.

Specially prepared starches and other saccharides canenhance membrane efficiency in virtually every water-baseddrilling fluid to which they are added including silicates andother primarily Type 2 membrane formers. Peak osmotic

reservoir pressure drawdown was usually but not necessarilysignificantly improved. The slope of the pressure recoverycurve was less positive indicating viscosity and/or pluggingeffects as σ approaches 1.

Test results indicate that selected materials, typically low-molecular-weight saccharides and substituted carbohydrate

polymers applied in high concentration increase membraneefficiency. Precipitative polyvalent salts are shown to increasethe effect of many materials in this category of polymers

perhaps by crosslinking mechanisms and/or increasedhydrated ion diameter.

It has been demonstrated that a proper mix of polymermolecular weights will yield significant beneficial effect. Theeffect can be used to establish a membrane with a measurable“membrane efficiency”. A range of short chain, low-molecular-weight polymers should be sufficiently small to just

enter the shale pores. As the largest fraction of these polymersis physically trapped by torturosity of the capillary structures,hydrogen bonded to sites on exposed clays within the shale, orotherwise reacted, the permeability of the shale is effectivelyreduced. These trapped polymers reduce the internal poredimensions. What follows is a cascade of entrapment ofsmaller, shorter, lower molecular weight polymers until someminimum dynamic pore dimension remains. The hydrated

polymer molecules and constrained water molecules furtherslow fluid movement through the matrix of permeability. Thisrepresents a combined viscosity and plugging effect.

Acrylic acid-based polymers. Generally positive resultswere not obtained with the polyacrylate, polyacrylamide, andrelated copolymers tested over a range of molecular weights.One low-molecular-weight polyacrylate demonstrated anosmotic pressure differential of 150 psi and a sigma factor of

–0.03 based on a 20-hr test. A long-term test is required forvalidation.

Siloxanes (dispersed or in an aqueous solution). Siloxanesas a class were unpredictable in performance. One silicon

polymer derivative may double the permeability of shale to pore fluid and the next sample may decrease permeability by50 to 80%. Positive membrane-forming effects were notgenerally significant in 20% sodium chloride solution.

Lignosulfonates, tannins, resins. Lignosulfonates mixed atconcentrations above 25 lb/bbl effectively reduced shale

permeability by 50 to 70% in pore fluid-based formulations.This supports old claims that drilling fluids with highconcentrations of lignosulfonate provide shale stabilization.However, lignosulfonate was not helpful in a 20% sodiumchloride-based fluid.

Glycols, polyglycols, and derivatives. A few glycols and polyglycols when used at high concentrations providedinteresting osmotic differential pressures. This apparently wasdue to a water activity effect rather than stable membraneformation. The materials as a class failed to provide stable

reservoir pressure for extended time.

Miscellaneous surfactants. A variety of surfactants weretested including alkyl betaines, fatty acid salts of sorbitans,and others. The effect on osmotic pressure and stablereservoir pressure were not significantly improved comparedto other materials.

Traditional high-performance and highly inhibitive water-based drilling fluids. Virtually all high-performance water-




based fluids will benefit from the addition of low-molecular-weight saccharide polymers. Relatively high concentrationsof these materials must be applied to reduce fluid flow intoshale. A range of 15 to 30 lb/bbl was used in preliminarytests. Potassium and ammonium-based fluids, in general,reduce formation of or disrupt Type 1 membrane.

Performance Resul ts - Membrane Type 2Polymerized films - In-situ polymerized films are efficientmembranes. Work with polyacrylates, sugars, and glucosidesled to an understanding of the role played by low-molecular-weight polymers in membrane development in and on shale.Low-molecular-weight polymers from several suppliers weretested. A variety of cellulose-derived and polyacrylateoligomers increased σ to provide enhanced osmotic pressure.A family of economical proprietary material remainedconsistently interesting throughout testing during 2001 and2002. 13

The novel oligomers compared favorably to similarly performing proprietary acrylic acid-derived oligomers. One

such experimental oligomer is totally soluble in virtually alltypes of aqueous-based fluids including KCl-polymer,calcium-based muds, bromide and formate-based fluids, andthe currently used ether amine inhibited HPWBM systemsused in the Gulf of Mexico, Canada and southern Europe.

This very soluble oligomer provides both the sub-unit for ahighly crosslinked polymer membrane and contributes to shalestability and improved HTHP filtrate control. Two

personalities of the new HPWBM can be seen with change in pH. At pH above 9.5, a crosslinked-polymer membranereadily forms to coat the formation. At lower pH, the materialdoes not readily polymerise but supports traditionallymeasured clay inhibition and stabilization. Available amineand oligomeric additives can easily enter the lamellae of theclay and serve as complementary hydration suppressants.

One method used to form a polymer membrane in situ is by condensation of an aldehyde or ketone with a primaryamine to form a Schiff base, as shown in Fig. 7 . In thisexample, the primary amine (Reactant #1) is a diamine, butother primary amines and polyamines will react in the sameway. The carbonyl molecule shown in Fig. 7 (Reactant #2) isglucose, but other sugars and polysaccharides may be used.

Many of the carbonyl molecules that participate in thiscrosslinking reaction require an elevated pH to present an

aldehyde functionality, which facilitates the polymerizationreaction. In some cases, the primary amine or polyamine will

provide the pH environment required to drive the reaction.However, long-chain amines, diamines, or polyamines with arelatively low amine ratio may require supplemental pHadjustment using materials such as sodium hydroxide,

potassium hydroxide, sodium carbonate, potassium carbonate,

or calcium hydroxide. Effect of pH on osmotic pressuredevelopment is presented in Fig. 8 which shows decrease inreservoir pore pressure with time at pH 10. 13

Component solubility is affected by the workingenvironment established by the carrier brine concentration andtemperature of application. Reactant #1 and Reactant #2should be selected to be soluble in the specific workingenvironment. Solubility is primarily associated withmolecular weight and polymer chain length but componentmoieties of both reactants will also affect solubility of theresulting Schiff base product.

The Schiff base formed by the reaction of Reactant #1 andReactant #2 must be of reduced solubility or insoluble in thecarrier brine in order to form a sealing membrane on shale orother formation exposed during drilling of a well. Carrier

brine salinity typically and usually applied in the testing of the present invention is 20% w/w which is a commonly usedstandard concentration used for offshore drilling in the Gulf ofMexico - USA. Salt concentrations from 5% NaCl tosaturation have been tested and found effective in supportingthe reaction. Application is not limited to sodium chloride-

based carrier solutions. The Schiff base forms in potassiumchloride, calcium chloride, and sulfate and nitrate saltsolutions and in sugar, molasses, and methylglucosidesolutions as well. 13

Salinity is not required for the Schiff reaction to occur.Proper selection of Reactant #1 and Reactant #2, each solublein distilled, fresh, or tap water can produce a reaction productinsoluble in fresh water and membrane formation would occurin that environment as well. If the salinity (more accuratelystated as the water activity) of the wellbore fluid is equal to orless than the salinity (more accurately stated as the wateractivity) of the reservoir fluid then the desired osmotic

pressure development would not occur. The membraneformed in a high activity environment will reduce water flowor diffusion into or through shale and also contribute to shalestability despite not contributing to a strong osmotic effect. 12

Plugging materials. Plugging materials such as silicates,fumed silica, aluminates, aluminum salts, calcium hydroxide,

and phenolic resins were tested. Sodium silicate-based fluidssupplemented with sodium and potassium chloride salts

provided the highest osmotic pressure development of allfluids tested. Sodium silicate-based fluids supplemented with

proprietary saccharide-based polymers build and maintainosmotic pressures closest to their theoretical osmotic potential.Silicate-based fluids can provide membrane efficiency inexcess of 70%.

Field results of fluids which yield Type 2 membranes have

HC–OH H 2 –N HC–OH CH 3 CH 3 HC–OH| | | | | |C=O CH–CH 3 C = N–CH–X–CH–CH 2 –CH–N = C| | | | |

HO–CH X HO – CH CH 3 CH-OH| | | | + HOH

HC–OH + CH 3 –CH ---> HC–OH HO–CH (2)| | | |

HC–OH CH 2 HC–OH HO-CH| | | |

H2 C–OH CH–CH 3 H 2 C–OH H 2 C–OH|

H2 -N

(2) (1)

Fig. 7 – Condensation Reaction Example.




been encouraging. Bit balling has been less of a problem thanexperienced with Type 1 membrane fluids. Formation andcuttings stability have been excellent. Type 2 membranes aretypically formed by reaction or interaction of specific drillingfluid components with the surface of the formation. Materialdepletion is the greatest concern. Drilling fluid should bemonitored for more than physical properties. Levels of

reactive membrane-forming ingredients must be maintained todrive membrane formation. Maintenance of perfectrheological properties, HTHP, or pH in no way guarantees thatmembrane formation is occurring.

Performance Results - Membrane Type 3

Non-Aqueous Fluids, Synthetic-Based Fluids and InvertEmulsion Fluids. Oil-based and synthetic-based invert muds(OBM and SBM), now often referred to as non-aqueous fluids,have long been considered ideal drilling fluids for shalestabilization. It has been claimed that invert emulsion fluids

produce a semi-permeable membrane on wellbore surfacesthat prevents transport of all materials except water across thewellbore interface. 14 Other experiments suggest that this maynot be the case. 15,16 In addition, the argument is made thatthere exist large capillary forces which in themselves preventoil filtrate or oil-based mud (and emulsified water) frominvading the rock fabric, 16-19 implying that osmotic flowcontrol with invert muds may not be critical for wellborestability. Wettability measurements of oil-based muds onmineral surfaces suggest otherwise. 20

The net steady-state pressure measured at the interface between an invert emulsion fluid and shale is expected to be

Pnet = π + P c (Eq. 4)

where P c, the capillary pressure developed by the fluid at theentrance to a pore or void in the rock, is given by Eq. 5:

Pc = 2 γmp cos θ/r p (Eq. 5)

Here γmp is the interfacial tension between the mud and the pore fluid, cos θ is the cosine of the contact angle made by themud displacing the pore fluid, and r p is the radius of the porethroat. For r p values considered typical of many shales, e.g. 10nm, P c is predicted to be as high as 15 MPa (2250 psi). 21 Thisis based on the assumption that the pore surfaces arecompletely water-wetting, i.e. θ = 0, and γmp = 0.074 N/m (74dyne/cm). This prediction is consistent with several

previously published SPE papers which suggested that oil willnot enter a water-saturated shale. 3,15 Now, if an invert mudhas a membrane efficiency of 1.0 and it contains ~ 19% w/wCaCl 2 in the internal phase, the steady-state osmotic pressure,π, should be about 2,750 psi (see Figure 5 ). Thus, P net might

be expected to reach 5,000 psi.On the other hand, measured values of P net are much more

modest. Recently a maximum value of 1 MPa (150 psi) wasreported for a shale. 22 The pressure differentials observed herefor invert emulsion fluids are likewise quite small, rangingfrom 200 to 1200 psi. Use of natural cores contributed to thevariability in the test results, and certainly mud rheological

properties affected the rate of pressure development. Yet inno case did P net approach 5,000 psi.

Invert emulsion fluids have significant membraneefficiencies demonstrated in experiments which show clearlythat water moves from a high water-activity shale to a lowwater-activity invert emulsion fluid. Exchangeable ions donot readily move between the shale and the mud. 21,23 Thus,the membrane established by OBM/SBM appears to be

essentially perfectly selective and should have an efficiency ofaround 1.0.With respect to capillary pressure, shale permeability tests

using neat oils and synthetic materials ( Fig. 9 ) do revealelevated entry pressure, in keeping with previousmeasurements of water/oil displacements. 24 Using a morereasonable value for γmp for displacement of the pore water ina shale sample with a hydrocarbon (say γmp = 0.03 N/m) andr p ~ 10 nm, we may expect P c ~ 900 psi. This is consistentwith the results from our study: the entry pressures measured

Pierre 1E shale sample - high and low permeabililt y testsInvert Emulsion Drilling Fluid - Activity 0.84

maximum recordable pore pressure = 980psi

0

250

500

750

1000

1250

0 12 24 36 48 60 72 84

Time, hr

P r e s s u r e

, p s

i

Well Bore (Mud) Pressure

Pore Pressure, low permeability shalePore Pressure, high permeability shale

Fig. 10 – Shale Entry Pressure of Invert Emulsion Mud

Pierre 1E Shale - pore entry comparisonFluid - IO1618

(maximum recordable reservoir pressure = 980 psi)

0

250

500

750

1000

1250

1500

0 12 24 36 48 60 72 84

Time, hr

P r e s s u r e ,

p s

i

Wellbore (Mud) PressurePore Pressure, low permeability shalePore Pressure, high permeability shale

Fig. 9 – Shale Entry Pressure for Olefin IO1618.




for neat IO1618, an olefinic hydrocarbon, were ~ 1300 psi fora water-wet low-permeability shale and ~ 200 psi for a high-

permeability (~ 1 μD) shale.A second set of tests ( Figure 10 ) was run using a typical

invert emulsion drilling fluid formulation. There was no clear barrier to fluid entry into shale of either high or low permeability. Indeed, reservoir pressure appeared to beestablished completely by the osmotic effect. This isconsistent with previous measurements on water/oildisplacements. 24 For invert OBM or SBM, the emulsifiers andwetting agents can lower this value to < 0.001 N/m, 20 so thatPc may be negligible for all but the finest pores. Based on

post-test shale analysis and content of the stainless steel filterdisk, a substantial amount of oil can find its way through ashale exposed to an invert emulsion drilling fluid.

The photo in Fig. 11 demonstrates the near miscibility of

oil and water in the presence of an equal volume of polyamidesurfactant, in keeping with the very low value ascribed to γmp

between invert emulsion fluids and pore fluid. In addition, itcan be demonstrated that shale core samples exposed in theSMT to invert emulsion drilling fluid become oil wet.

As shown in Figure 12, a drop of water placed on the face

of such a core forms a steep contact angle and “beads up,”whereas a drop of water placed on the face of a core exposedto polymer/20% NaCl immediately spreads across the surface.

Not only does the invert emulsion drilling fluid oil-wet thesurface of the shale, it also permeates the core and ultimatelygenerates a significant amount of filtrate; this conclusion is

supported by analyses of fluid extracted from the sinteredstainless steel disk supporting the shale core ( Table 5 ).

Not only does the invert emulsion drilling fluid oil-wet thesurface of the shale, it also permeates the core and ultimatelygenerates a significant amount of filtrate; this conclusion issupported by analyses of fluid extracted from the sinteredstainless steel disk supporting the shale core ( Table 5 ).

Thus, if P c is quite low for invert emulsion fluids, the

differential pressure measured across the fluid/shalemembrane should be approximately equal to π. That themeasured values of P net are considerably lower than the

predicted values of π suggests the strong influence of kineticson shale dehydration 3 and/or the influence of some other

process(es). The most likely scenario derives from theobservation of filtrate invasion (primarily base fluid + freesurfactants), which leads to formation of a distribution ofmembranes throughout the invaded zone. This distribution ofmembranes within the fabric of the shale reflects a change in

pore fluid composition and increasing pore fluid activity thataccompanies the transport of filtrate. As evidence for this, thelower-permeability shale sample exhibited significantly higherPnet than the higher-permeability sample. Very likely thelower-permeability sample still suffered from filtrate invasion,though not to as great an extent as the higher-permeabilitysample. Tests with a very-low-permeability shale may help toresolve this issue.

Table 5 – Recovered from Fil ter MediumDisk

1Disk

2Disk

3Disk

4Mud type Invert Invert WBM WBMDisk wt (g) 23.22 23.09 23.15 23.23Disk Volume (cm 3) 5.03 5.03 5.03 5.03Matrix Volume (cm 3) 2.92 2.90 2.91 2.92Pore Volume (cm 3) 2.11 2.12 2.12 2.11

Air (cm3) 0.22 0.39 0.18 0.35

Oil (cm 3) 1.02 0.68 0 0Water (cm 3) 0.87 1.05 1.94 1.76

Fig. 11– Photograph

Sample 1 diesel oil + freshwater + surfactant Sample 2 diesel oil + CaCl2 25% + sur factant Sample 3 LVT + freshwater + surfactant Sample 4 LVT + CaCl 2 25% + surfactant

Fig. 12 – Oil and Water-Wet Shale.

Pierre 1E shale sample - high and low permeabililt y testsInvert Emulsion Drilling Fluid - Activity 0.84

maximum recordable pore pressure = 980psi

0

250

500

750

1000

1250

0 12 24 36 48 60 72 84

Time, hr

P r e s s u r e

, p

s i

Well Bore (Mud) Pressure

Pore Pressure, low permeability shale

Pore Pressure, high permeability shale

Fig. 10 – Shale Entry Pressure of Invert Emulsi on Mud




Conclusions

Three distinct types of membranes are produced byconventional water-based drilling fluids, polymer filmforming/silicate based fluids, and invert emulsion basedfluids. The osmotic mechanism is very different for eachtype of membrane.

In-situ polymerization of proprietary oligomers by polyamines provides membrane performance comparableto that of silicate-based drilling fluids.

Silicate-based drilling fluids provide nearly optimummembrane efficiency and osmotic effect.

Specific saccharide-based polymers enhance membraneeffects and promote osmotic pressure when used in 20%sodium chloride-based drilling fluids. Reduction of

permeability and viscosity enhancement (reduction ofhydraulic inflows) are two mechanisms that can accountfor the observed effects.

Saccharide-polymer performance is enhanced by additionof calcium, magnesium, and aluminum salts tosupplement or completely replace sodium chloride.

Calcium chloride 10% is superior to sodium chloride 20%for building osmotic pressure and improving membraneefficiency.

Invert emulsion fluids can provide excellent osmoticeffects, though fluid invasion is apt to occur. Interactionof these fluids with shales is stronger than previouslythought, resulting in capillary pressures and apparentmembrane efficiencies that are significantly smaller thanthose assumed or reported in earlier work.




Nomenclature

σ = Reflection coefficient P c = Capillary pressurer p = Radius of pore throatθ = Contact angle of wetting phase in poresγmp = Interfacial tension between mud and pore fluid

M e = Nominal membrane efficiency P w = Applied wellbore pressure P r = Recorded equilibrium reservoir pressureT = Temperature (°K)

X A = Measured activityπ = Osmotic pressurem = Slope of ongoing pressure trend

References

1. Keijzer, Th.J.S.: “Chemical Osmosis in Natural ClayeyMaterials”, Geologica Ultraietum 196, PhD thesis,Universteit Utrect, Utrect, The Netherlands (2000).

2. Keijzer, Th.J.S. and J.P.G. Loch, J. P. G.: "Chemical

osmosis in compacted dredging sludge", Soil Sci. Soc. Am. J 65: 1045-1055 (2001).

3. van Oort E., et al. : “Critical Parameters in Modelling theChemical Aspects of Borehole Stability in Shales and inDesigning Improved Water-Based Shale Drilling Fluids,”SPE 28309, SPE Annual Technical Conference, NewOrleans, Sept 25-28, 1994.

4. Mitchell, J.K.: Fundamentals of Soil Behavior , Wiley(1993) Chapter 12.

5. Yeung, A.T. & Mitchell, J.K.: “Coupled Fluid, Electricaland Chemical Flows in Soil,” Geotechnique, 43 (1993)121.

6. Fritz, S.J.: “Ideality of Clay Membranes in OsmoticProcesses: A Review,” Clays and Clay Minerals , 34 (1986) 214.

7. Ewy, R.T.: “Pore Pressure Change Due to Shale-FluidInteractions Measurements under Simulated WellboreConditions,” Fourth North American Rock MechanicsSymposium, Seattle, Washington, July 31, 2000.

8. Cussler, E.L.: Diffusion – Mass Transfer in Fluid Systems, Cambridge University Press (1984) 159.

9. Simpson, J.P. and Dearing, H. L., “Diffusion Osmosis – AnUnrecognized Cause of Shale Instability,” IADC/SPE59190, 2000 IADC/SPE Drilling Conference, New Orleans,LA Feb. 23-25, 2000.

10. Simpson, J. P. and Dearing, H. L., “Drilling Gumbo Shale – A Study of Environmentally Acceptable Muds toEliminate Shale Hydration and Related BoreholeProblems,” DEA-113, O’Brien-Goins-Simpson &Associates, Inc., Houston, July 2001.

11. Van Oort, E.: “A Novel Technique for the Investigation ofDrilling Fluid Induced Borehole Instability in Shales,”Eurock '94, Balkema, Rotterdam, 1994.

12. Hale, A.H., Mody, F. K. and Salisbury, D. P.:“Experimental Investigation of the Influence of ChemicalPotential on Wellbore Stability,” IADC/SPE 23885,

SPE/IADC Drilling Conference, New Orleans, Feb 18-21,1992.

13. Schlemmer, R., et al. : “Progression of Water-Based FluidsBased on Amine Chemistry – Can the Road Lead to TrueOil Mud Replacements?,” AADE-03-NTCE-36, AADE2003 National Technology Conference, Houston, Apr 3,2003.

14. Ballard T.J. and Dawe R.A.: “Wettability Alteration

Induced by Oil-Based Drilling Fluid,” SPE 17160, SPEFormation Damage Control Symposium, Bakersfield,California, Feb 8-9, 1988.

15. Santos, H. and da Fontoura, S. A. B.: “Concepts andMisconceptions of Mud Selection Criteria: How toMinimize Borehole Stability Problems?” SPE 38644, SPEAnnual Conference, San Antonio, Oct 5-8, 1997.

16. Santarelli, F. J. and Carminati, S.: “Do Shales Swell? ACritical Review of Available Evidences,” SPE/IADC29421, SPE/IADC Drilling Conference, Amsterdam, Feb28 – Mar 2, 1995.

17. Gazaniol, D., et al. : “Wellbore Failure Mechanisms inShales: Prediction and Prevention,” Journal of PetroleumTechnology (July 1995) 589.

18. Fam, M. A. and Dusseault, M. B.: “Borehole Stability inShales: A Physico-Chemical Perspective,” SPE/ISRM47301, SPE/ISRM Eurock ’98, Trondheim, Norway, July8-10, 1998.

19. Bol, G. M., et al. : “Borehole Stability in Shales,” SPE Drilling & Completion (June 1994) 87.

20. Cline, J. T., Teeters, D. C. and Andersen, M. A.:“Wettability Preferences of Minerals Used in Oil-BasedDrilling Fluids,” SPE 18476, International Symposium onOilfield Chemistry, Houston, Feb 8-10, 1989.

21. Van Oort, E., Hale, A. H., Mody, F. K. and Roy, S.:“Transport in Shales and the Design of Improved Waster-Based Shale Drilling Fluids,” SPE Drilling & Completion(Sept 1996) 137.

22. Onalsi, A., Durand, C. and Audibert, A.: “Role ofHydration State of Shales in Borehole Stability Studies,”Eurock ’94, Balkema, Rotterdam, (1994) 293.

23. Simpson, J. P., Walker, T. O. and Aslakson, J. K.: “StudiesDispel Myths, Give Guidance on Formulation of DrillingFluids for Shale Stability,” IADC/SPE 39376, IADC/SPEDrilling Conference, Dallas, Mar 3-6, 1998.

24. Teeters, D. C., Anderson, M. A. and Thomas, D.C.:“Formation Wettability Studies that Incorporate theDynamic Wilhelmy Plate Technique,” in OilfieldChemistry: Enhanced Recovery and ProductionStimulation ; J. Borchardt and T. Yen, Eds., ACSSymposium Series no. 396, Washington, D.C. (1989) 560.

SI Metric Conversion Factors

psi (lbf/in2) x 6.895 E-03 = MPa

lbm/bbl x 3.5 E-01 = g/Llbf/gal x 1.12 E-01 = Specific Gravity (SG)lbm/gal x 1.20 E+02 = kg/m 3

lbf/100 ft 2 x 4.79 E-01 = Pa(°F–32) 5/9 = °C




Appendix A – Sample Data Set

Tested material Comment Activit y Comment MembraneType

NominalOsmoticPressure

(psi)

slopepressure

return

sigmafactor

invert 60/40 ES 215v CaCl2 30% 3 277 -1.49 -54

invert 90/10 ES 476v CaCl2 30% 3 204 -1.00 -49

invert 70/30 ES 160v CaCl2 30% 3 313 -0.36 -12

invert 70/30 ES 428v CaCl2 22% 3 200 -0.18 -9

Field invert 80/20 ES 566v CaCl2 19.3% 3 398 -0.08 -2

invert 80/20 ES 210v CaCl2 30% 3 266 -0.05 -2

invert 80/20 ES 278v NaCl 25% 3 911 -0.15 -2

sodium silicate 2.6 specialformulation

KCl / NaClas specified

3000 psiformulation 2 2650 -0.07 0


NaClas specified



NaClas specified


Polymerised film –oligomer +

primary amine

25 ppb5 ppb

NaCl 20% pH 10.5 2 1600 0.01 0


NaClas specified

500 psiformulation 2 755 0.01 0

proprietary oligomer blend 50% CaCl2 10% 1 269 0.03 1

methylglucoside Type 206(1747) with special

additives30% CaCl2 18% experimental

sample 1 279 0.10 4

salt blank CaCl2 30% 1 230 0.15 7

sugar blank sucrose 50% 1 267 0.23 8

sodium gluconateMP42 LMW cellulosic

polymer

30%15ppb CaCl2 18% 1 610 1.05 17

sodium gluconateMP42 LMW cellulosic

polymer

20%15ppb CaCl2 18% 1 213 0.45 21

MP93 MEGMP42 LMW cellulosic

polymer

20%15ppb CaCl2 18%

“Sigma”methyl

glucosidemonomer

1 205 1.10 54

sulfonated asphalt 30 ppb NaCl 20% 1 120 0.87 72

MP7 polyglycol 30 ppb NaCl 20% 1 135 1.20 89

salt blank NaCl 20% 1 250 2.38 95KCl polymer system KCl 6% 1 42 0.53 127

MP61 CMC 25 ppb NaCl 20% 1 160 2.10 131

resin lignite 30 ppb NaCl 20% 1 168 2.25 134

lignosullfonate 30 ppb NaCl 20% 1 110 2.33 212




Appendix B – Details of Test Equipment , Procedures, and Sources of Error

Test - Equipment Preparation. A typical test scenario begins with a thorough cleaning of all wetted surfaces anddistilled water rinses of the test assembly. A 25.4-mmdiameter core sample 6 to 8 mm in length is installed in a

beveled rubber confining gasket mounted in a matching core

holder subassembly of the test cell. Using a torque wrench, aclamping ring is installed on the core holder which compressesthe rubber confining gasket to provide a calibrated fixedconfining stress of up to 1000 psi (compression mechanicallyimposed) on the shale core. Confining stress cannot bereadjusted after a test begins but does change to match mudfluid pressure when fluid pressure exceeds the preset

confining stress. O-ring seals between coreholder and cell body are lubricated with viscous silicone-based lubricants toeliminate leaks. Before installing the coreholder, the cell bodyis filled with pore fluid.

The coreholder is then pushed into the cell body until itsexternal o-ring beds at a positioning step. Using a 60-mLsyringe, excess pore fluid is removed from the reservoir side

of cell holder, thereby pulling the coreholder into the cell bodyuntil fully seated. When seated in Type A cell, Fig. A1 , areservoir volume of 55.5 mL is established, which includes the

porous stainless steel support disk, cell reservoir, gaugevolume, and closed valve volume which completes the shut-inreservoir side of the cell assembly. When seated in Type Bcell, a reservoir volume of approximately 6 mL is establishedwhich includes the sintered stainless steel support disk,

passages through the base of the coreholder, the gauge and theclosed valve volume. Test results using either Type A or TypeB cells were comparable.

After installation of the shale core in the cell assembly, the borehole side is filled with pore fluid. The cell cap is pushed

into place and the clamping collar screwed down. Filling ofthe reservoir side of the cell is then completed. Air is removedfrom the reservoir side of the apparatus in every test. If air isnot removed, all pressure build-ups below 200 to 300 psidisplay substantial lag due to compressibility. The lag

precludes consistent test results. Acceptable linearity of the pressure and volume relationship generally begins above 150- psi reservoir pressure, depending upon volume of residual airin the apparatus.

The oven is then closed and heater is switched on. Forcedconvection maintains oven and test cell temperature to within0.1°F up to 250°F. The data acquisition system is started torecord ongoing system adjustments, pressure changes, andtemperature stabilization. After a minute, with 6000 data

points collected (100 data points / sec), the data are averaged,queued for display, and transferred to a Microsoft Excelspreadsheet. Update of the displayed spreadsheet occurs every10 min.

Hydraulic pressure of 200 psi is applied to the wellbore(top) side of the test cell. Approximately 2 to 2.5 hr arerequired for the oven and contents to stabilize at the selectedoperating temperature but stabilization overnight is preferred.Hydraulic pressure of the wellbore (top) side of the test cell isadjusted to 600 psi. Reservoir pressure is adjusted manuallyto 200 psi using a 3cm 3 syringe and the reservoir side shut-invalve closed. Reservoir pressure development is observed andrecorded until reservoir pressure approaches wellbore

pressure.Shale permeability is calculated as a function of increase in

reservoir pressure. The test cell includes wellbore andreservoir containers separated by the shale core. A fluiddifferential pressure is applied across the shale core. As

presented in calibration data, Fig. A2 , an increase in reservoir pressure of 1000 psi represents a flow measurement ofapproximately 600 μL into the reservoir of Type A cell and 78μL into the reduced reservoir volume of Type B cell.

Fig. A2 – System Pressure-Volume Relationshi p

The recorded pressure increase is converted to equivalentvolume of perfusate. Fluid volume, differential pressure, corediameter, core length, and time are applied to Darcy’sequation to calculate shale permeability.

Pore fluid in the wellbore side of the cell is then replaced by a test fluid. To separate the test fluid from the supplymanifold, a diaphragm is placed atop the core holderassembly. The cell cap is pushed into place and a clampingcollar screwed down upon the complete assembly to close and

Fig A1 – Cell Types




seal the device. Approximately 2 to 2.5 hr are required for theoven and contents to restabilize at the selected operatingtemperature. The borehole pressure is then set to 600 psi

using a syringe pump. Reservoir pressure is adjustedmanually to 200 psi using a 3-cm 3 syringe and the reservoirside shut-in valve closed. Reservoir pressure development isobserved and recorded for a period ranging from 3 hr to 10

days. All current testing is conducted for at least 120 hr if acandidate material is promising.Many tests, especially in case of invert emulsion, silicate,

and saccharide-containing drilling fluids, require an increasein wellbore pressure to exceed rapidly building osmoticdifferential pressure. The highest pressure applied in any testto the wellbore side of the cell was 4500 psi for a silicate/saltmud system. The reservoir pressure was reduced to less than100 psi by the osmotic pressure established by the silicatefluid. The reservoir pressure transducers have a maximumrange limit of 980 psi. With two pressurizing pumps availablefor 5 cells, a required increase in wellbore pressure foradjacent cells to compensate for exceptional osmotic effectmay occasionally drive an individual reservoir pressure offscale.

Sources of Error

Shale variation. Permeability tests with water indicated thatthe Pierre 1e shale ranged from approximately 0.3 to 10 μ Dwhen tested parallel to the bedding plane (horizontal tests).The range of permeability when tested perpendicular (verticaltests) to the bedding plane was 0.01 to 0.5 μ D. The testsdescribed here were originally designed for rapid samplescreening and a cursory attempt was made to match shale

permeability to a specific test or series of tests. Shale sampleswith permeability greater than 5 μ D were either discarded orthe collected data used for equipment evaluation only.Consistent media is considered more important for initialscreening tests and may be superior to preserved shale for that

purpose.

Gauge displacement. When the project began, the first goalwas to standardize on a simple screening process and test forthe effects of fluid chemistry on permeability, sequentiallyapplying as many candidate chemicals as possible. It wasreasoned that thin shale disks would permit measurement of

permeability changes in 8 hr or less for each individualcandidate sample. Pressure of less than 200 psi was applied totest fluids and resultant reservoir response was recorded.Results were occasionally repeatable. Error investigationrevealed that the precision transducers used to measurereservoir pressure required 80 μ L to achieve a full scalereading. Gauge displacement contributed to poor quality

permeability measurements until the system pressure-volumerelationships were delineated.

Air Entrainment. Non-linearity of the system's PVTresponse was also attributed to residual air in the reservoir side

of the device. A small bubble of air in the 50-mL reservoirside of cell severely affects low pressure responsiveness of thedevice. An air bubble 10mm in diameter represents more than500 μ L of readily compressible media in the reservoir. Ifexcess air is not removed, all pressure build-ups below 250 psiare of questionable accuracy and usefulness.

Temperature effects. The Honeywell precision transducers,as originally installed external to the oven, were sensitive totemperature changes with a design limit of 130°F.Transducers and pressure tubing mounted outside the test ovenwere directly affected by fluctuations of room temperature.Swings in reservoir pressure of more than 50 psi resulted fromtemperature-mediated fluid expansion or contraction in thegauge and tubing external to the oven. When gauge andtubing were mounted in the oven, accurate measurementsoriginally were limited to 130°F or less due to gaugedurability.

Despite double electronic controllers, extra insulation, anda more rigorously controlled environment, reservoir pressure

can respond to small temperature changes due to night andweekend building environmental changes. Opening the doorto the oven for a few seconds can result in a temporaryreservoir pressure change of more than 50 psi. When thetemperature restabilizes, reservoir pressure returns to itsoriginal trendline unless some other problem exists or changeshave been made in the system.

There were many instances of data recorded which agreedwith expectations. As often happens when things seem toogood to be true, repeat runs revealed that interesting reservoir

pressure changes reflected, more often than not, a fortuitouschange in building temperature due to the setting sun ratherthan shale-fluid interactions or, more often, a system leak.Low displacement gauges providing calibrated response to180°F and acceptable accuracy and excellent repeatability to250°F are now in use and installed in the oven along with allvalves and connecting tubing. The number of compressionfittings has been reduced from eight to two on the reservoirside of the cell assembly.

Seal effects. The rubber retaining ring for the shale disk isdesigned to translate compressive forces applied manually

before the test begins to radial confining stress on the shale pellet. The preset confining stress preload remains constantuntil the wellbore fluid pressure exceeds the preload. Abovethe maximum preload of about 750 psi, confining stress isequal to wellbore fluid pressure. This is a weakness of the

cell design and remains a nagging concern when high-pressuretest results of certain fluids are considered.

Shale bedding plane orientation. A technique used byearlier investigators was repeated in these tests. If a reduced-

permeability shale was required for a specific test, the sameshale, used for tests parallel to the bedding plane, was simplyturned 90° so as to flow perpendicular to the bedding plane.The decision to use this technique rather than seek out a shale




with lower permeability parallel to the bedding plane was based upon expedience and cost. The dimensional and permeability change responses of shale to axial stress mayvary markedly when comparing vertical and horizontalorientation.

Manifold communication. Individual cells are manifolded to

a common pressurizing pump through ⅛-in. plastic tubing.An earlier system design included individual accumulators toisolate each test fluid and cell from the next test fluid and cell.The accumulators were modified Baroid/OFI-type HTHPfiltration cells with a piston to separate pressurizing fluid fromtest fluid. The additional thermal mass in the oven requiredwarm up times of 4 hours. As fluid pressure of the testsincreased, friction between o-rings and accumulator body

produced pressure fluctuations of more than 25 psi. It wasdecided to forego use of the accumulators.

Occasionally nearly identical pressure response curveswere observed in adjacent cells. This was an indication thatsolute flux between the test fluids through the ⅛-in.

pressurizing tubing may have been interfering with the test. Aflexible nitrile rubber/vinyl laminated diaphragm is nowinstalled in each static cell to physically preclude ion flux orwater movement between cells through the pressurizingmanifold. A single stirred cell is pressurized through anaccumulator-type device devised from a small field-typeHTHP cell with a standard PPA piston using one o-ring.Removal of one o-ring from the piston reduces frictionaleffects. The atmospheric-pressured cavity between two o-rings is eliminated which reduces friction. Recorded pressurefluctuations were reduced from 25 psi at 600-psi wellbore

pressure to less than 5 psi when a small polished HTHP celland modified piston was used.

chemical osmosis, shale and drilling fluids

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