FORMATION DAMAGE DUE TO MINERAL ALTERATION … Damage... · FORMATION DAMAGE DUE TO MINERAL ALTERATION AND WEnABILITY CHANGES DURING HOT ... with thermal recovery projects and ...

FORMATION DAMAGE DUE TO MINERAL ALTERATION ANDWEnABILITY CHANGES DURING HOT WATER ANDSTEAM INJECTION IN CLA V-BEARING SANDSTONE

RESERVOIRS

By

D. Brant Bennion, F .B. ThomasHycal Energy Research laboratories Ltd

D.A. SheppardSceptre Resources Ltd.

THIS PAPER IS TO BE PRESENTED AT THE 1992 SPE SYMPOSIUM ON FORMATIONDAMAGE CONTROL TO BE HELD FEBRUARY 26-27, 1992 IN LAFAYETTE, LOUISIANA

ABSTRACT INTRODUCTION

Detailed laboratory studies were conducted tostudy the effect of hot water and steam injection on thepenneabillty, relative penneability, wettability, residualoil saturation and mineralogic composition and structureof a clay bearing sandstone reservoir in SouthernAlberta, Canada. The san1)les initially contained onlykaolinite and illite clays, classically classified asnon-water sensitive. This paper presents the results ofthree detailed laboratory coreflow experiments anddocuments the degree of fonnation damage (up to 95%reductions in penneability were observed) due totemperature induced mineralogic and wettabilltyalterations. Multipoint temperature tests from 32 to265°C (90 to 510°F) were conducted at full reservoirconditions on preserved core material to generate thisdata. The effect of steamflooding vs merely hotwaterflooding at 265°C (51 oaF) on residual oil saturationis also illustrated indicating up to a 20% additionalreduction in res~ual oil saturation by steamflooding. Acomplete suite of pre and post test petrographic studieson each sample tested including x-ray diffraction, thinsection and scanning electron microscope analysisindicate the definitive transfonnation of inert kaoliniteclay into water sensitive swelling smectitic clay due toreactions between the kaolinite clay and the quartzduring the high temperature flooding process. Theresults of this study have specific application to thedesign of hot water and steam injection projects inother similar types of sandstone reservoirs.

Hot water and steamflooding are commonly usedtechniques to mobilize and recover substantialadditional low and mid API gravity oil from shallowhydrocarbon bearing formations. The input of thermalenergy into the reservoir reduces the viscosity of the oiland increases the reservoir energy allowing mobilizationand production of the crude oil. As with any type ofreservoir injection and production process, the ability tosuccessfully inject and produce the fluids is ofparamount importance. Formation damage in thereservoir can greatly reduce injectivity into theformation. If the thermal process is of a cyclic nature,the productivity of the formation on the production cyclecan also be adversely affected and result in an overallreduction in the fraction of recoverable oil. Formationdamage mechanisms during hot water andstearnflooding are somewhat different processes thancommonly associated with conventional wells. Thispaper will document some of the common causes ofpermeability i"1>8irment associated with thermalrecovery projects and illustrate these phenomena usingthe results of a comprehensive suite of laboratory data.

MECHANISMS OF THERMALLY INDUCEDFORMATION DAMAGE

Formation damage occurring during normaldrilling,completion and stimulation operations has beendocumented in the literature 1.2. This paper is concemedwith the mechanisms of permeability impairment whichcan occur during a thermal stimulation operation.

solubility of quartz in the water phase and the presenceof Ca, Mg or Fe in the injection fluid from directInjection or solubilization of carbonate/dolomitecementing materials. The fluid which is in contact withthe resulting newly formed swelling clay Is fresh steamcondensate. Since the steam condensate contains nostabilizing ions it will rapidly substitute into the smectitestructure causing the clay to swell and reducepermeability. This phenomenon has also beendocumented by others.8.7.8.9

These processes would include:

1. Mineral transformations2. Mineral solubilization/dissolution3. Wettability alterations4. In-situ emulsion formation.

Each of these damage mechanisms will now bediscussed In greater detail.

Mineral Transformations

Mineral DissolutionMineral transformations can be a particularproblem in reservoirs which contain a substantiveamount of in-situ clay, Many reservoir systems areevaluated prior to testing for the presence of smectiteclay. Smectite clay's structure is such that due to anuneven charge distribution, layers of fresh water canreadily substitute themselves between clay crystalscausing an expansion of the clay structure. When fullyhydrated, a smectite clay crystal can almost double insize from 9.2 Angstroms to over 17 Angstroms3,Obviously, If smectitic clay is present in the matrix of areservoir, sensitivity to fresh low salinity Injected watermay be a potential mechanism for formation damage.This problem is often overcome in regular waterfloodoperations by increasing the ionic strength or divalention concentration1.4 in the injected water stream. Thiscauses the substitution of a smaller mineral ion in theclay structure in lieu of water. This results in claystabilization and the exclusion of the water from theclay matrix.

Figure 1 illustrates the phenomenon of mineraldissolution. Damage from mineral dissolution can taketwo forms, these being:

a) Damaging reprecipitation of the solubilizedminerals either as the reservoir cools or as thesaturated hot water phase cools as it movesdeeper into the formation.

b) Often clasts of soluble material will containencapsulated insoluble fines. As the hightemperature injected water dissolves the solublematerial, the non-soluble encapsulated fines arereleased where they then migrate into the flowingfluid stream. If of sufficient size, these fines canbridge and plug at pore throats.

Wettabilitv Alterations

The effects of temperature on wettability havebeen previously documented by several authors1O.11.Almost all minerals in a natural, clean state exhibitwater wet behaviour. Polar high molecular weightcompounds that tend to be physically adsorbed on thesurface of minerals. particular1y on carbonates. are themotivating cause of neutral or oil-wet behavior. Studiessuggest12 that up to half of all sandstone and about90% of all carbonate oil reservoirs exhibit neutral tooil-wet behavior. The degree of physical adsorptionwhich adheres these oil-wetting hydrocarbon agents tothe surface of the minerals in the reservoir is controlledby temperature. The higher the temperature becomes.the less of these types of hydrocarbons can be retainedon the surface of the reservoir rock. Therefore, thehotter a system becomes (while under a hotwaterflood), in general. the more water wet it becomes.

Many reservoirs also contain what wouldnormally be classed as non-swelling clays. Theseclays would include materials such as kaolinite, illiteand chlorite3. Clays of this type generally exhibitbalanced charges and hence are not susceptible toswelling, although they may exhibit deflocculative4 ormigrative5 tendencies.

The potential for mineral transformation in hightemperature thennal operations occurs when relativelyinert kaolinite clay is transfonned into fresh watersensitive smectite clay. This reactionS occurs asfollows:

Ale7A1. &.. 04 + s.s.o.[KacJH. a.JI [~~ ~

2(A'-' AI, ~10s0 (~.+7H2O[Sr7*,*~

2hIt is well understood that wettability strongly

influences the flow and relative permeabilitycharacteristics of porous media 13. Figure 2 illustrateshow a typical temperature induced shift in wettabilitycan influence the flow behavior of an initially oil wetreservoir. In general, penneability to water dropssubstantially even though maximum water saturation

(1

where Me Is Ca, Mg or possibly Fe

The transfonnation from inert kaolinite clay tosmectitic clay is induced by the temperature Induced

In general, fresh, lower density water tends toemulsify with crude oil more readily than higher densitysaline brines. This being the case, production from hotwater and steamfloods are particularly susceptible toemulsification problems due to the fact that theseprocesses are most commonly associated with lowgravity crudes and fresh Injection water/steamcondensate. The In-situ formation of emulsions tendsto cause the formation of a trapped highly viscousimmobile phase. This trapped phase greatly impedesthe flow of subsequently mobilized oil and increases theturbulence between produced oil and water, therebycausing further emulsification problems.

increases due to a reduction in the residual oilsaturation by viscosity reduction effects. Oilpermeability may also increase in some cases due tothe shift to more water wet behaviour.

This type of behaviour can be advantageous,particularly in a cyclic thermal production project as ittends to greatly improve the oil-water mobility ratio andimprove speed and efficiency of overall oil recovery.Injectivity of water due to a reduction in water phasepermeability is generally not a problem as the waterviscosity reduction with temperature in most casesoffsets the reduction in injectivity thereby maintaining aconstant or decreasing injection pressure.

DESCRIPTION OF THE EXPERIMENTAL STUDYFigure 3 illustrates how an abrupt wettabilitytransformation can occur when the transition from hotwaterflood to steamflood occurs. Figure 3A illustratesa typical pore when hot waterflooding. The pore iswater wet at high temperature and the residual oilsaturation is trapped in the central portion of the pore,encapsulated and shielded from contact with the rockmatrix by the surrounding liquid hot water phase.When the transition to steamflooding occurs,(Figure 38), the shielding water phase is vaporizedallowing the residual oil saturation to contact thesurface of the rock directly. This allows directunshielded adsorption which in many cases, even atelevated temperatures. can cause a very rapidalteration to an oil wetted state (Figure 3C).

Three detailed high temperature displacementstudies were conducted on preserved state coresamples from a selected well in a Glauconiticsandstone reservoir in Southern Alberta, Canada. Thetests were specifically designed to investigate:

1. Reservoir condition water-oil relativepermeabilities.

2. Recovery efficiency to hot water as a function oftemperatu re.

3. Incremental oil recovery by steamflooding.4. The potential for and mechanisms of thermally

induced formation damage for this system.

Figure 4 illustrates how a transition in wettabilityinduced by steamflooding can adversely affect thewater-oil relative pe""eability characteristics of aporous media. The large increase In water phaserelative pe""eability can greatly reduce the recoveryefficiency of the mobilized oil on the return productioncycle. Wettability changes of this type can bepe""anent or gradually reversible (due to gradualdesorption after hot waterflooding resumes) dependingon the specific nature of the system underconsideration.

EXPERIMENTAL EQUIPMENT

A schematic of the high temperature coredisplacement apparatus appears as Figure 5.Preserved core material is mounted in a ductile leadsleeve to allow the transmission of a confiningoverburden pressure in both radial and axial modes tothe core material. Sintered glass disks are used toretain the core material and radial distribution headsensure that flow into and out of the core specimens isevenly distributed eliminating potential areas oflocalized high fluid velocity. The core assembly ismounted inside a high temperature core jacket encasedin a digitally controlled 6 kilowatt heating mantlecapable of elevating core temperature up to 340°C(6500F). The pressure rating of the core jacket at thistemperature was 21000 kPa (3000 psi).

Emulsion Formation

The formation of high viscosity oil externalemulsions can be a severe problem both in thereservoir and in surface production systems. Many midand low API gravity crude oils can contain up to 70%water by volume internally emulsified in anencapsulating external oil phase. These oils are readilycharacterized by their .creamy. appearance and it isnot at all unusual for oils with high water contents toexhibit dynamic viscosities an order of magnitude ormore greater than clean, unemulsified oil.

Pressure differential measurements across thecore sample, to facilitate penneability calculations, wereconducted through the use of a manifold system of twocapacitance type pressure transducers. One transducerhad a range of 0 to 150 kPa (0 to 20 psi) and thesecond from 0 to 1500 kPa (0 to 200 psi) to facilitate

the accurate measurement of a wide range of pressuredifferentials which might occur over the course of adisplacement test.

2.

Fluids were displaced through the core samplesusing digitally controlled, constant rate, positivedisplacement pu~s. The use of positive displacementpumps obviates problems associated with pressure.shocking. the core samples (as can occur withconventional reciprocating chromatographic stylepumps) and reduces the potential for prematuredamage due to fines mobilization.

3.

Backpressure on the system was controlled usinga precision backpressure regulation system accurate to0.5% of the setpoint value. Fluids were produced intoa test separator where exact volumes of produced oil,water and gas as a function of time could bedetennined. All system components were constructedof corrosion resistant monel or 316 stainless steel.

4.

5.

6.

7.

8.

EXPERIMENTAL PROCEDURE

Selected samples of preserved state glauconiticcore were utilized for the three different experimentsconducted as a portion of the study. Table 1documents a summary of pertinent core physicalparameters for each of the three tests. Samples offresh unoxidized reservoir crude 011 were obtained fromfield separators in sealed pressurized stainless steelcylinders and recombined with equilibrium separatorgas to yield a saturation pressure of 3250 kPa (471psig) at 3~C (90°F) and a resulting gas-oll ratio of 22m3/m3 [124 scf/bbl] for the live 011. The actualdisplacement tests were conducted at 7500 kPa (1090psi) as this was the current reservoir operating pressurein the reservoir under study. Table 2 documents thepressurized viscosity measurements conducted on thelive 011 and injection water at 7500 kPa (1090 psig) atthe different temperature levels utilized In the study.

9.

10.

Displace dead reservoir crude out of the coresample at 7500 kPag (1090 psig) by injection of10 pore volumes of live crude oil. Detennineinitial stabilized permeability to live crude oil.Verify that effluent oil GOR and composition areidentical to the initial injected live reservoir oil toensure complete saturation of the sample.

Conduct an unsteady state, water saturationincreasing, constant rate relative penneability teston the core at 7500 kPag (1090 psig) and 3~C.Collect Incremental production and transientpressure history data to facilitate computation offull water-oil relative penneability curves viaimplicit computer history matching techniques'4.

While continuing to waterflood, slowly elevatecore temperature to 100°C. Measure finalstabilized penneability to water at 100°C andnote residual oil saturation.

Heat core to 175°C, repeat step #4.

Heat core to 22OOC, repeat step #4.

Heat core to 265°C, repeat step #4.

Steamflood core at 265OC by slowly reducingintemal pressure to 5800 kPag (700 psi) togenerate steam in-situ in the porous media.Steamflood the sample until no additionalreduction in oil saturation is observed.

Repressurize core to 7500 kPag (1090 psig) tore-establish liquid phase flow. Remeasure poststeamflood brine penneability to note the effectof steamflooding.

Cool core, dismantle, measure final saturationsand post test air permeability and porosity.

Subject pre and post test core samples fromeach test to thin section, XRD (X-Ray Diffraction)and SEM (Scanning Electron Microscope)analysis to quantify the mechanisms of anyobserved fonnation damage.

11

RESULTS OF EXPERIMENTAL TESTS

The following identical procedure was utilized foreach of the three different core samples in the study:

1. Mount core stack as previously described in aductile lead sleeve. Apply 9390 kPag (1360psig) of initial net overburden pressure. Heat thecore sample slowly to the reservoir temperatureof 32°C (90OF). Intemally pressurize the sampleto 7500 kPag (1090 psig) by the injection ofunoxidized dead reservoir crude oil whilesimultaneously increasing the overburdenpressure to 16890 kPa (2450 psig) to alwaysmaintain a net overburden pressure of 9390kPag (1360 psig).

Initial Mineraloav

Table 3 presents the initial bulk and clay XRDanalysis summary for each of the three samples whichwere evaluated during the study. The samples weregenerally silt sized to fine and medium grainedlithanerite sandstones. The framework mineralogy waspredominantly monocrystalline quartz with lesseramounts of sedimentary rock fragments, chert,polycrystalline quartz and trace amounts of feldspar.

Matrix clay occupies up to 6% of the rock volume (andup to 9% of the mass on a bulk compositional basis -Table 3). This clay lines the pores and occasionallyblocks pore throats. The analysis indicated that theclay material was predominantly detrital kaolinite with aminor illitic component and the case of sample "B" atrace smectitic component. Calcite and ferroan (ironbearing) dolomite cements occur in trace quantitiesprecipitated in the intergranular pore system.

highest residual oil saturation. This is believed to bedue to macroscopic channelling effects and thesubsequent bypassing of a large amount of trapped oilin lower permeability portions of the sample. All of thetests indicated that a substantial additional volume of oil(15 to 20% of the total pore space could be recoveredby steamflooding at 265°C versus merely waterfloodingat the same temperature. This substantial additionalrecovery, while still maintaining a constant temperature,is believed to be due to a combination of steamdistillation and stripping effects, additional energy addedto the system by the compressible gaseous steamphase, and a possible reduction in trapping effects dueto the transition from a water wet to oil wet media 15.

Experimental Data

Table 4 compares the water and oil phaseendpoint relative permeability data and Table 5provides the residual saturation data as a function oftemperature for the three tests. Figure 6 provides acomparison of the oil-water relative permeability datagenerated using the implicit history matchingtechnique'4 at 3~C and 7500 kPag (1090 psig) foreach of the three samples. Examination of this dataindicates very comparable water-oil relative permeabilitycharacteristics between the three samples. Theconfiguration of the relative permeability curves wouldsuggest that the three samples likely exhibit neutral toslightly water-wet initial wettability.

The fact that a wettability alteration has occurredis readily apparent from the data of Table 4 andFigure 7. Although one would expect the reduction inresidual oil saturation to cause an increase in waterpermeability, permeabilities to water increased by162%, 1503% and 880% for samples A, Band Crespectively. This is a much greater increase thanwould normally be associated with the reduction insaturation (based upon extrapolation of theconfiguration of the initial oil-water relative permeabilitycurves). Expulsion of bridging fines and particulatesduring the steamflood process can in some casescause large permeability increases similar to this. Boththin section and XRD analysis of the pre and post testcore samples indicated no evidence of this type ofmechanism, further substantiating the mechanism ofwettability alteration for the permeability increase.

The water relative permeability data of Table 4has been plotted and appears as Figure 7. This clearlyillustrates how the water phase permeability in eachtest declined dramatically with temperature.Substantive reductions in the residual oil saturation(Table 5) were occurring as temperature increasedcontributing to a higher water saturation which should,In theory, have caused an increase In water phaserelative permeability.

Post Test Mlneraloav

No substantive difference in the rock fabric anddiagenetic mineral suite was seen in thin sections;however, smectitic swelling clays were identified in posttest SEM and XRD samples analyses which werepreviously absent. The percentage of quartz andkaolinite had been reduced in these cases and thepercentage of smectite increased. Samples of verysmall «5) microns of poorly crystallized silicaprecipitates were observed in the pore system(particularly sample C) possibly contributing to theobserved permeability reduction by blockage of somepore throats. Pre and post test clay mineralogy data issummarized in Table 6.

The primary cause for the reduction inpermeability to water in the 32 to 175°C (90 to 348°F)range is likely primarily attributable to wettability shiftsto a more water wet condition. Above 175°C (34~F)the permeability decline with temperature becomesmore pronounced and is likely motivated by theadditional effect of mineral transformations anddissolution phenomena, coupled with continuedwettability alteration effects. Table 6 documents thespecific clay fraction composition of each of the coreson a pre and post test basis. The XRD results indicatedefinitively for samples. A. and .C. a substantivereduction in the concentration of kaolinite clay and anincrease in smectitic clay concentration.

The residual saturation data of Table 5 havebeen plotted and appear as Figure 8. Examination ofthis data indicates that residual oil saturation was ingeneral steadily reduced with temperature. Core .C.,which was very heterogeneous and penneable. had the

CONCLUSIONS 2. Bennion, D.B., Thomas, F .B. and Crowell, E.C.:"Laboratory Tests to Evaluate and MinimizeDamage in Horizontal and Vertical Wells", PaperPresented at the 30th Annual Conference of theOntario Petroleum Institute, London, Ontario (Oct.9-11, 1991).

. Yang, Joseph, PhD Thesis, University of Calgary,1979.

.. Scheuerman, Ronald F., and Bergersen, BarbaraM., "Injection-Water Salinity, FormationPretreatment, and Well-Operations Flukj-SelectionGuidelines", fl, (July 1990).

'. Gruesbeck, C., and Collins, R.E., "Entrainment andDeposition of Fine Particles In Porous Media",~ (1979) 846-56.

~. Hutcheon, I., Abercrombie, H.J., Shevalier, M., andNahnybida, C.: "A Comparison of FormationReactivity in Quartz-Rich and Quartz-PoorReservoirs During Steam Assisted ThermalRecovery", In, R.F. Meyer and E.J. Wiggins (eds.),The Fourth UNITAR/UNDP InternationalConference on Heavy Crude and Tar Sands,Volume 2, Paper No. 235, (1989) pp. 747-757.

. . Abercrombie, H.J.: "Water-Rock Interaction DuringDiagenesis and Thermal Recovery, Cold Lake,Alberta". An unpublished University of CalgaryPhD Thesis.

~. Perry, C., and Gillott, J.E.: "The Formation andBehaviour of Montmorillonite During the Use ofWet Forward Combustion in the Alberta Oil SandDeposits", Bulletin of Canadian PetroleumGeology, v.27, No.3, pp 314-325.

- . Sedimentology Research Group, "The Effects ofIn-Situ Steam Injection on Cold Lake Oil Sands,"Bulletin of Canadian Petroleum Geology, v.29,No.4, pp 447-478.

10. Main!, B.B. and Okazawa, T., "Effects ofTemperature on Heavy Oil-Water RelativePermeability of Sand," gr, May 1987.

11. Polikar, M., Ali, S.M.F., Puttagunta, V.R.: "HighTemperature Relative Permeabilities for AthabascaOil Sands," SPE Res. Ena. (Feb. 1990).

12. Treiber, L.E., Archer, D.L. and Owens, W.W., "ALaboratory Evaluation of the Wettability of Fifty OilProducing Reservoirs," §f.5a...Vol. 13 (4) (1973) P221.

13. Craig Jr., F.F.: "The Reservoir EngineeringAspects of Waterflooding," SPE MonoaraDh Series.(1971 ).

3

4

The test results illustrate three of the classicfonns of formation damage potentially associated withthermal recovery projects, these being:

1. The transformation of kaolinite clay to swellingsmectitic clay.

2. Mineral dissolution and re-precipitation.

3. Wettability alteration.

The test results indicate that formationpermeability could be reduced by up to 90% by acombination of these factors. The formation of in-situemulsions can also occur, but was not observed to bea problem in these tests, possibly due to the highergravity crude oil utilized in this case in comparison tomany hot-water and steamflood projects.

5

6

The test program also illustrated that residual oilsaturation was a function of te"",erature and wasreduced by increasing the temperature. Steamfloodingat 265°C (SogoF) was found to mobilize substantial (upto 20% of the total pore volume) additional oil resultingin residual oil saturations as low as 8%. Wettabilityalterations to a more oil-wet state were observed whenstearnflooding which substantially increased the relativepermeability to water. This illustrates thatconsiderations of the viability of recovering the extra oilmobilized by stearnfloodlng need to be balancedagainst the potential creation of a more adversemobility ratio.

i

B

The use of laboratory displacement tests wereillustrated as an effective means of screening andpredicting reservoir performance and defining potentialthermal sensitivity problems prior to the capital cost ofimplementation in the reservoir.

9

ACKNOWLEDGEMENTS

The authors wish to express appreciation to theManagement of Sceptre Resources for their permissionto publish this data.

REFERENCES

Bennion, D.B. and Thomas, F .B.: -rhe Design ofEffective laboratory Coreflood Tests to Evaluateand Minimize Formation Damage in HorizontalWells., Paper Presented at the Third InternationalConference on Horizontal Well Technology,Houston, Texas (Nov. 12-14, 1991).

1

14. Bennion, D.B., Bennion, D.W., Thomas, F.B.,"Recent Improvements in Experimental andAnalytical Techniques for the Determination ofRelative Permeability from Unsteady State FlowExperiments," presented at the SPE 10thTechnical Conference and Exposition held in Portof Spain, Trinidad (June 26-28, 1991).

15. Wardlaw, N.C.: "The Effects of Geometry,Wettability, Viscosity and Interfacial Tension onTrapping in Single Pore Throat Pairs," ~ (May1982).

TABLE 1INITIAL CORE PARAMETERS

Core Property Core A Core B Core C

10.2011.2824.227.840.1210.907

9.4111.3224.225.80

0.1480.917

8.8811.4726.026.450.1340.755

Length (a11)Area (cm~Porosity (%)Pore Volume (cm3)Initial Water SaturationIFinal Water Saturation

BackpressurekPapsi

75001090

75001090

75001090rerbUrden Pressure

kPapsi

168902450

168902450

168902450

Final Avg. Post Test AirPermeability

(Jlm)2 x 103mD

473.3 479.5 530.5537.5

Plugs crumbled during post test extraction, permeability was extremely high

TABLE 2OIL AND BRINE VISCOSITY MEASUREMENTS

@ 7500 kPa

Uve Oil Viscosity(mPa.s)

[cP]

Water Viscosity(mPa.s)

[cP]

Temperature(OC)

32100175220265

6.941.460.5780.3900.298

0.70.20.10.10.1

'92

95

65

31

09

TABLE 3INITIAL SAMPLE

COMPOSITIONAL DATA VIA XRD ANALYSIS

TABLE 4COMPARATIVE RELATIVE PERMEABILITY DATA AS A

FUNCTION OF TEMPERATURE FOR CORES A. B. AND C

R~ative Pe~eabilityTemperatureFluid

1==::J=:==32 (90) I

32 (90)100(212)175 (347)220 (428)265 (509)265 (509)265 (509)

I Core A

I *0.8000I 0:2024

0.17420.12360.10410.0794

Core C

.0.80000.1829O. 11980.05280.03430.0116

0.1137

Core B

.0.80000.16000.10120.06320.04680.0114

Live OilWaterWaterWaterWater\water Steam

Water 0.2086 0.182&

k... to fluid(,tnn2x10-:1)[mD]

207.9[219.7]

368.8[373.71

944.5[956.9]

INote: Absolute permeability to fluid estimated for each preserved coreassuring ko = 0.80 abs.

TABLE 5COMPARISON OF RESIDUAL

OIL SATURATION TO WATERFLOOD/STEAMFLOODAS A FUNCTION OF TEMPERATURE FOR CORES A. BAND C

TABLE 6ILLUSTRATION OF CHANGE IN CLAY COMPOSITION

BETWEEN PRE- AND POST-TEST SAMPLES OF CORES A. BAND C

wt?<C

~~~

z-O~

~j::-J

w<

C°

~~

(/)=

>~

~t?O

Cii:I.L-J

I.L~O

ww

z-J-a.~~~w

FIGURE 2

INFLUENCE OF TEMPERATURE ON

RELATIVE PERMEABILITY/WETTABILITY

(Illustrative Example)

Kro,Krw

@ 2Q.C

eKro,Krw

@ 100.C

-0-Kro,Krw

@ 200.C

-.-

Kro,Krw

@ 3OO"C

-8-

>.='=

.ccoQ)

E'-Q)

a..

Q)>

~coQ)

ct:

Water Saturation

z0~w~«~~5

~O

(Y)-om

-J~

~LL

::>I-~

~W

«-~

WLL

l-LL(/)

0:1:Z

I-0--~~l-(/)::>-J-J-

"(ij~"tJ-

'~i5

~

'-Q)

~ES(/) Ejcn

-~"8~~'0:I:

u-ilVQ)

~~-u-ico~C

J)

FIGURE 4IllUSTRATION OF CHANGE IN RELATIVE PERMEABiliTY

CHARACTERISTICS DUE TO WETTABlllTY ALTERATIONS DUE TOSTEAMFlOODING

Kro,Krw Pre-Steamflood Kro,Krw Post-Stearnflood

(Water-Wet) (Oil-Wet)

FIGURE 5HIGH TEMPERATURE RELATIVE PERMEABILITY &

FLUID SENSITIVITY APPARATUS

Annular Pressure'

(Thick Lines Represent Heat Traced Flow Tubing)

FIGURE 6COMPARISON OF WATER-OIL RELATIVE PERMEABIL

@ 32°C FOR CORES A, B & CTV DATA

1.0

~\0.8

~~~\\ t::.:t.

~-:=::cco 0 6Q) .

E~Q)

a..

Q).~ 0.4-CO

'"Q)~

~~ \~~ ,~. ,,,

a-8~I ~a

0.00.0 0.1 0.2 0.3 0.4 0.5 0.8

Water Saturation

~0.2

Kro,KroCoreAe---

Kro,Kro

Coree

--8--

Kro,Kro

CoreC

-0-

FIGURE 7COMPARISON OF HIGH TEMPERATURE WATER ENDPOINT

RELATIVE PERMEABILITY DATA FOR CORES A, B & C

Core A Core B Core C- 0- - --rl -

FIGURE 8COMPARISON OF HIGH TEMPERATURE RESIDUAL SATURATION DATA

FOR CORES A, B & C

Core A Core B Core C--e- - - 8-- -0-