..

SPESPE 12927

How To Stabilize Clays and Improve Injectivity~~EI.F.Sloatand Dan Larsen, T/ORCO Inc.

Members SPE-AIME

Copyright1984SocietyofPeVoleum EngineersofAIME

Thispaperwas presentedatthe1984RockyMountainReg!onalMeetingheldinCasper,WY, May 21-23,1984.The materialISsubjecl10COIrecmonbytheauthor.Permissiontocopyisreatrmtedtoanabstraclofnotmorethan300words WriteSPE,6200NorthCentralExpressway.Drawe!64706 Dallas,Texas75206USA. Telex730989SPEDAL.

ABSTRACT CLAY CONTROL HISTORY

New technology based on the use of potassium hy- Recognition of waterflood clay problems datesdroxide to permanently fix clays in the near well- back to the 1950s, Early efforts to control thebore area is taken from the laboratory development condition were developed during that era with one ofstatus to the field. Injection well treatments using the first attempts in the Rockies, application of aKOH are compared with the normal soak (potassium cationic amine type inhibitor at Patrick Drawl Inchloride) and coat (cationic polymer) approach in the 1965, potassium chloride was selected to stabilize ansame reservoir. extremely water sensitive Navarro sand southwest of

San Antonio, Texas. Potassium chloride has remainedINTRODUCTION 4-- ~tab~~~~~flgclays on a tempo-in use ever SiilC~ IUI

rary basis during drilling operations and as the soakClays have the potential to completely sabotage solution in a standard injection well treatment se-

a waterflood. The main reason they become a problem quence that is now followed by the addition of ais a mineral composition change in the water that cationic polyacrylamide.contacts the formation during injection. The changecan be in the form of a reduction in total dissolved Techniques based on the use of hydroxy aluminumsolids or a shift in the ratio of divalent ions. The solutions came into the picture during the earlyresult of ignoring this condition is shown graphical-ly in Figure 1.

1970s, along with a process to reverse nettabilityLiquid to air permeability ratios, and form an oil coating on the exposed clay mineral

which remain constant or increase when Sussex forma- surfaces. For those interested in digging into thetion water is put through these cores, quickly drops details of these processes the literature referenceswhen fresh Fox Hills water makes an appearance.While this in itself is bad enough, the effect is

in SPE 11721 are recommended. Stabilizing ClaysWith Potassium Hydroxideg, is actually a summary of

magnified by the fact that damage in the low perme- the laboratory studies on which much of the fieldability core is far greater than the damage in the test work in this paper is based.highest permeability one. Table 1 summarizes thiseffect in tabular form. The final column shows the During most of the sixties, the United Statesliquid permeability contrast remaining stable in the Bureau of Mines Petroleum Experiment Station inrange of 4.5 to 5.5 while Sussex formation water is Laramie, Wyomingz made regular and important contri-flowing through the samples. The contrast then in- butions toward diagnosing and defining clay mineralscreases sharply to a level of 14 as fresh Fox Hills in a number of Powder River Basin formations. Thesupply water enters the system. It is this latter Petroleum Experiment Station in Bartlesville, Oklahomaeffect which severely penalizes reservoir volumetric was also very active in efforts to improve or maintainsweep and in turn leads to much lower than projected injectivity on waterfloods. Bob Johansen and Jackwaterflood oil recovery. Powe112 studied the effects of nettability alteration

Table 2 takes the need for stabilizing clays in-and summarized their results in a series of reportsthat have proven to be very valuable over the years

to the field. Compared are water injection rates fortwo Powder River Basin reservoirs of similar age and

as efforts intensify to get water into tight forma-

depositional type each containing significant amountstion rock and still stay under formation partingpressures.

of clay minerals. On a porosity x foot basis, effec-tive clay stabilization results in a three-fold in- HALL PLOTScrease in injection rates.

Hall Plots --- a convenient way to graphically

References and illustrations at end of paper. present the quality and history of an injectionwell --- also appeared in the early 1960s.4 The

321

2 HOW TO STABILIZE CLAYS

most recent SPE Monograph #5 contains a very conciseascription of Hall Plots and how they can be used totrack changes in injectivity.

In its simplest form, a Hall Plot consists of acumulative pressure term plotted against cumulativeinjection volume, which is usually along the X axis.The slope of this ~~~ve is proportional to the perlne-ability to water ( ). Any increase in slope is adecrease in permeab~lity to water. Any break to theright, or reduction in slope, signals a pressure part-ing condition, water breakthrough to a producing wellor the results of acidizing that in the case of aninjection well allowed more water to move more quick-ly to a nearby producer. In addition to the simpli-city of being on rectangular coordinate paper, HallPlots have as their basis the standard rate andnr-r;7nrl jn ~~~]e 4,rocK aliaTIUIU pr-uPelG[c2 la =LIIII{IUI,-.Like other Almy sand reservoirs in this area, theformation is sensitive to fresh water and the crudeoil is quite reactive with alkaline agents. Table 5lists the effect of different alkaline agents on theinterracial tension of crude oil from Ruben Unit #6.Although soda ash (Na2C03) shows good reactivity at2 weight percent, potassium hydroxide brings the IFTdown to the same level at 0.2 weight percent. Pre-vious core tests have shown that in the Almy sand aninterracial tension reduction of 100-fold, or in this

r -- 91 1 +a i..case Irulll~l.l ~u lea= than .31 dyneslcn?j correlatesvery well with core flood results that mobilize atleast 3% pore volume residual oil saturation.

As a result of the need to permanently stabilizeclays and to mobilize as much residual oil as possi-ble, Ruben Unit #8 was selected for a special pump-inpump-out test. The test design is detailed inAppendix A and consisted of four basic steps.

First, was the addition of potassium chloridepre-soak in such a way that step-rate data could bedeveloped regardless of whether the well was onpressure at the surface. After this a fall-off testwas run --- again with bottom hole pressure measure-ment equipment in place.

Next was the addition of 300 88LS of 15% potassiurhydroxide at the same 400 barrel/day rate held for thefinal step of the potassium chloride addition. Thewell was again shut-in for a six day pressure test.

The third step consisted of pumping in a 900 B8Lfresh water buffer that contained cationic polymer ata concentration of 0.3 LBS/BBL.

Figure 3 is the BHP in Ruben Unit #8 (-3000Datun)for the first 24 days of pump-in work on this well.The shape of the second fall-off curve shows improvedpermeability. Significant aiso is the point that atthe same 400 BWPD rate, pressure during the additionof the first 300 barrels of buffer (cationic polymer i]fresh water) was 300 PSI less than at the end of the300 barrel 15% KOH addititi

Figure 4 is the injectivity index plotted againstcumulative volume. Again apparent is the injectivityimprovement during and immediately after the KOHaddition.

322

.CDF 17Q77 B. F. SLOAT & D. LARSEN 3

Step four pumped out of the formation a total of7,519 barrels of fluid (187 BBLS oil) which wassampled three times a day (51 in all), analyzed, and

.....I+.-AF 22 camnlac ~~~gythen compared with the r~sulba WIduring the pump-in portion of the p;o~;~~~ppendix B),Although the complete test was carried out during someof the coldest weather of the year (Big Piney, Wyomingis eight miles to the east), experienced productionpeople at BELCO (now BelNorth) kept it running. As aresult, interpreting the test data is very straightforward. Material balances based on the thiocyanatetracer and confirmed by the chloride ion are detailedin Appendix C. An average dilution factor of 25%wascalculated.

Figure 5 is the pH of all solutions injected andrecovered plotted against cumulative in-put and out-put volumes. The location of the 300 barrel, 15% KOHslug correlates well with the maximum pH during thepump-out cycle and lends strong support to the materi-al balance calculations for hydroxide recovered.Appendix C details these calculations and shows that45.4%of the potassium hydroxide was recovered duringthe 47 day interval required to lift the 7,332 barrelsof water used in the material balance.

POTASSIUM HYDROXIDE CONSUMPTION - 856 L8S/AC-FT

Using the average of the two dilution factorsdeveloped for thiocyanate and chloride results in atotal water volume of 2,850 barrels divided by .25,or 11,400 barrels. Under residual oil saturationconditions in the near-well bore area of Ruben Unit#~, this Jtiater~o~ume made Up 80% of the total pore

volume which including the oil amounts to 14,250 BBLS.A porosity value of 14.4%or 1,117 barrels/ac-ft isreasonable for this area of the field, and as a re-sult a total contacted acre-footage of 12.75 is thebasis for the KGiiconsumption value. ,111.-Th+. rd~~~~atedvalue of 856 LBS/AF is probably on the high sidesince it is based on recovery of all of the potassiumhydroxide in the pump-out volume of 7,332 barrels.Actually, the pH was still fluctuating slightly duringthe last 20 days with a value of 11.6 recorded forJanuary 2nd even though four earlier tests were belowthis level, as were the final samples taken onJanuary 12th and January 22nd.

Figure 6 is a plot of alkalinity versus cumula-tive water production with additional curves for thealuminum and silica values as measured in every thirdsample (Appendix D). Here again, recovery of thesematerials which were put in solution as a result ofcontact with the 15% potassium hydroxide appears tobe complete. The values correlate quite well with thealkalinity and earlier pH measurements and confirm thefact that the mechanism of this process for stabiliz-ing clays and improving injectivity is aided in partby the dissolving action of the potassium hydroxide.

MOBILIZATION OF RESIDUAL OIL

Measureable oil production first showed up onthe fourth day of pump-out and gradually increased toa peak of 13 BOPD at a cumulative recovery of 1,721barreis. L----=*-- +L- 1-..-.1,+tiIinnd ~n~ r~~ch~dlneredT~er, bilet=~=t WCC, ,tl-O again on December 16th at 3,230 barrels of recovery,when the rods parted and ended the sustained pump-outportion of the test.

Since no oil was produced for the first threedays and none on the last day, and with good pHcorrelation during this interval --- from 9.8 back to9.8 (Figure 5) --- 93 barrels of oil produced fromDecember 2nd thru December 15th can be considered asmobilized residual oil. The water volume liftedduring this period totaled 2,480 barrels giving acumulative WOR of 26.7. Assigning this oil to a cer-tain acre-footage requires some assumptions in cal-culating displaceable pore volume (Pvd). One approachis to use [1 - (S +S .)] = 0.615 and come up with aPvd = 1,117x .38grorw~30 BAF. The result is 5.8AFor mobilized oil of 16 BAF (1.4% PV). This valuemay be conservative on the theory that the near-wellbore area was below the normal S level due to thepassage of the 300 barrel 15% KO~rsolution chased bythe 900 barrel fresh water buffer. Oil flow backthrough this same pore system first resulted in satis-fying the S demand and then what was left was mea-sured in th~rtank. In any event incremental oil wasproduced and its presence in the recovery fluidcorrelated very well with pH and alkalinity levels.

PHYSICAL AND CHEMICAL PROPERTIES OF KOH

Rocky Mountain weather is hard on most liquidproducts eight months of the year. Potassium hydroxidis a notable exception as shown by the phase diagramin Figure 7. The product as shipped is a 45 weightpercent solution that is stable to -22F. Diluted onsite to 30 weight percent brings the freezing pointdown to below -80F. Even the 15% use solution isstable to +5F. Bare steel is the preferred metal tohave in contact with KOH solutions of any strength,Safety and handling precautions are the same as foracids, which are on the opposite side of the ph scale.Aluminum, brass and bronze will corrode in a matterof hours. When dry KOH is added to water (casehj~t~r~ #2) the heat of the solution will rapidly in-crease temperatures to 150F or more. The resultingequipment stress, particularly for storage tanks andtransports, adds to the potential for leaks and spills

ECONOMICS

There are two ways to pay out clay stabilizationtreatments and with certain crude oils a third orbonus benefit results from mobilizing residual oil.

The first pay out is to increase water injectionat constant pressure. More water in means more oilout and better present worth values for the project.

A second and potentially much greater pay outtakes the form of a true increase in reservoir volu-metric sweep. By allowing water to enter the tighterzones that normally would be blocked by swelling ormigrating fines, clay stabilization compliments manyof the polymer augmented processes that are designed

mfiI.I+~vn[,mh hioh Permeability streakst~ reduce:tiater,,ww .,,WW=,....=..~-An effective and permanent clay stabilization programapplied to both injectors and producers can improveoil recovery efficiency by at least 3%. The RubenUnit is a good example --- recovery efficiency is nowat 42.6% with field-wide WOR still below 0.8. Claycontrol measures have been in effect from the startof water injection in December, 1970.

Mobilizing residual oil in the near-well borearea --- besides the beneficial effect on injectiondue to increasing the relative permeability to water -

.X.3

4 HOW TO STABILIZE CLAYS

in practice allows more oil to be recovered at theproducers. If Ruben #8 is representative then the16 BAF of incremental oil helps offset the cost of the--p ,nc JRC ..-......nl-.+

.APPENDIX A

RUBEN UNIT #f3 PIIMP-lNJPUNP-(IUT TEST L)ES[GN S-4 ZONE

TIME_Q!wJlSTAGE

VOLUME(BDLS)

RATE(BWPD)

.

PRESSURE SOLUTION - BASE ADDITIVES(PslG). .- JCONC . ) (pl~ODUCT) (CONC.) (PRODUCT)

50

100200300400500

50100200300

Date

11/29

11/30

12/01

12/02

12/03

12/04

12/05

12/06

SampleNo.

123123123123123123

123

SUB TOTALS

SampleDate No..-

12/07 123

12/08 123

12/09 123

12/10 123

12/11 1

:

12/12;3

12/13 123

12/14 123

12/15 123

SU8 TOTALS

APPENDIX C

RUBEN UNIT #8 PUMP-OUT SAMPLE LOG, ANALYSES &MATERIAL BALANCE CALCULATIONSFOR THIOCYANATE, CHLORIOC, PH AND ALKALINITY

VOLUME - BBLSWater Oil L Fluid

636363

808181

777777

797979

717272

737474

616161

0 189

0 431

0 662

5 904

3 1,122

2 1,345

12 1,540666667 13 la

1,717 35 1,752

VOLUME - BBLSWater Oil .g Fluid

656566 8 1,956595959 5 2,138565757 7 2,315525353 5 2,47851

:; 10 2,641484849 6 2,792464646 6 2,936515152 3 3,093424243 8 3,228

1,418 58 3,228

THIOCYANATE~ m@ x BBL5

32.5 2,04742.1 2,65242.1 2,652

50.6 4,04852.6 4,26053 4,293

64.6 4,97465.4 5,03574.8 5,760

82.5 6,51782.5 6,51773.2 5,783

74.2 5,26874.8 5,38677.6 5,587

80 5,84077.6 5,74277.2 5,713

81.6 4,97877.6 4,73479.4 4,843

83.4 5,50482.6 5,45280 5,360

118,945

CHLORIDEmcJ/l_ mg/1 x BBLS

1,600 100,8001,720 108,3601,720 108,360

2,040 163,2002,100 170,1002,130 172,530

2,380 183;2602,430 187,1002,410 185,570

2,610 ~~~,~cjo

2,660 210,1402,690 212,510

2,720 193,1202,700 194,4002,810 202,320

2,920 213,1602,960 219,0402,980 220,520

3,100 189,1003,110 189,7103,120 190,320

3,320 219,1203,320 219,1203,300 221,100

4,278,862

APPENDIX C - Continued

THIOCYANATEInn/ I

77.679.48058.86560.563.867.563.864.164,160.662,159.862.160.662.156.859.858.956.456.458.958.956.456,457.5

.. @ x 8BLS

5,0445,1615,2803,4693,8353,5703,5733,8473,6373,3333,3973,2123,1673,0503,1672,9092,9812,7832,7512,7092,5942,8763,0043,0632,3672,3672,472

89,618

CHLORIOEmm

3,4003,5003,4003,5903,5003,5003,6203,6003,6203,6203,7003,7003,7203,7503,7003,7003,7003,7003,6003,7003,7003,7203,7003,8003,6503,6003,600

y/1 x HBL3 ..

221,000227,500224,400218,810206,500206,500202,720205,200206,340188,240196,100196,100189,720191,250188,700177,600177,600181,300165,600170,200170,200189,720188,700197,600153,300151,200154,800

5,146,900

.-F!!!-11.911.611.6512.112.312.412.4512.812.5~~.g~12.912.913.45

;:.113.3513.4512.7

11.912.812.3512.411.7511.75

_P!-1212.412.7512.612.212.412.311.B11.5511.610.911.3511.i10.310.011.7510.011.212.310.710.111.311.812.211.2

9.710.1

ALKALINITYmg/1 mg/1 x BBLS

1,4801,8601,820

3,2003,2403,340

4,0004,4004,320

5,3005,6205,840

7,9601,9867,240

8,2008,2008,200

8,2408,4008,460

8,4008,1807,860

93,240117,180114,660256,000262,440270,540308,000338,800332,640418,700443,980461,360565,160502,560521,280598,600606,800606,800502,640512,400516,060554,400539,880526,620

8,963,460

ALKALINITY!!SL!l y@l x BBLS

7,8007,5007,180

7,0006,6406,240

6,0005,6405,840

5,0405,2005,240

4,6804,6004,520

4,3003,6403,800

3,2003,0403,000

2,6002,8002,800

2,4002,4002,000

507,000487,500473,880413,000391,760368,160336,000321,480332,880262,080275,600277,720238,680234,600230,520206,400174,720186,200147,200139,840138,000132,600142,800145,600100,800100,800

86,0006,851,820

SPE12927

APPENDIX C - ContinuPd. . . . . ----- .. . ... . .

THIOCYANATE~ mg/1 x BBLS

CHLORIDEm mg/1 x BBLS

ALKALINITY

-@_ !!!@_. mgtl x BLSSample

Date No.

SUB TOTALS

11/29 thru 12/06

12/07thru 12/15* Rod Part 12/16

12/21 thru 12/28

12/29 thru 01/02

01/03 thruO1/20

VOLUME - BBLSMater Oil f Fluid .

1,717 35 1,752 i18,945

89,6185;.5 5,175

31 54,064

55.4 50,137

32.5 47,385

4,~75,g&

5,146,9003,600 324,000

1,800 3,139,200

3,250 2,941,250

1,820 2,653,560

8,963,460

6,851,82010.1 2,000 180,000

9 180 313,920

11.6 1,300 1,176,500

8.5 140 204,120

1,418 58 3,22890 0 3,318

1,744 56 5,118

905 20 6,043

1,458 18 7,519

I%Lw?.772-, --- , . . -

1,250 9,165,000

9,318,772

31,634,500

0.295

17,689,820TOTAL PUMP-OUT

LESS BACKGROUND

ADJ. PUMP-OUT

TOTAL PUMP-IN

RECOVERY FACTOR

7,332 187 7,5i9 365,324

7,332

7,332 187 7,519 365,324

1,756,130

0.208

38,961,660

0.454

2,850 - 2,850

APPENDIX D

RUBEN UNIT #8 PUMP-OUT SAMPLE LOGcnD hlUMINUN. STIICA AND CATIONIC POLYMER,,,L , ------

ALUMINUM (Al+++) SILICA (Si02) CATIONIC POLYMER

!!!$w mg/1 x BBLS ~ mg/1 x BBLS R@_ mq/1 x BBLSSample VOLUMES

Date No. Water ~ Total Flui~.

11/2911/30

2512

1,5751,512

2,4202,079

9481,6802,1301,2111,5933,5422,8142,6842,2661,9531,6941,3641,512

27,048

16,296

18,046

63189

431662904

1,1221,3451,540i,?~~1,9562,1382,3152,4782,6412,7922,9363,093

5,11B

6,043

7,519

il.938.8

13.82225.737.84041.534,33027.12220.415.413.31511.4

0

5.7

0

0

rn

1,1;;

3,3405,0826,0917,9388,5207,1796,0714,8303,6312,6842,1011,4321,024930821

0

4,423

0

0

i ~o185

203206258263291271257252163211175158146133120

37

85

31

28*

7 win, ,---23,310

49,12647,58661,14655,23061,98346,88345,48940,57221,84225,74218,02514,69411,2428,2468,640

71,484

65,960

39,959

12/0112/0212/0312/0412/0512/06i2/G712/0812/0912/1012/1112/1212/1312/1412/15

242 0231 0237210 :213 2173 12i77 12

161 ;134 5122 710393 1:

:; :72 3

10

:*

810

;2221222221222221

12/28

01/02

1,932 8

776 56

14

21

1401/11 1,289 38

01/22 1 Commingled S-3 &S-4

TOTALS 21 7,332 187 7,519

* Less Base Level 7,332

9

67,265

67,265

724,719

205,296

519,423

94,367

29,328

65,039

21.7 LBS

28 4

173 LBSExpressed in Pounds (1 LB = 3,000mg/1 x BBL).......22.4 LBS

sPE1292?

TABLE 1

THE EFFECTOF A CHANGE IN WATER COMPOSITIONON PERMEABILITYCONTRAST*

Air Permeability- E!

Liquid to Air Perrn.Ratio -Initial

Sussex -2 Pv

Formation -20 Pv

Water -Final

Fresh -2 Pv

Fox Hills -20 Pv

supply -Final

Core #1 Core #2 Core #3 .

21 0.63 8.4

0.45 0.30 0.10

0.4;5 0.33 0.10

0.55 0.33 0.11

0.67 (216 PV) 0.32 (48 PV) 0.12 (26 PV)

0.61 0.26 0.10

0.455 0.18 0.035

0.43 (61 Pi) ~,~~ (~fiDv1.!. , !3.lJ~ (31 Pv)

Permeabi11tycontrast

_(&Q!?l.

33.3

4.5

4.75

5.0

5.5

6.1

13.0

14.3

l Oata from State #16-1 TriangleU Unit - SussexSand

TABLE 2

A COMPARISONOF INJECTIONRATESIN SIMILAR*RESERVOIRSWITH ANO WITHOUT

CLAY STABILIZATION

InjectionOata Trian~!!S@S!SL@?!l

Start - Fox Hills Water August, 1981 March, 19B1

Well No-

Z1-aoz

31-302

41-5

&y

Gallivan#l!

21-30

31-30

41-5

3-9

CurrentRate - BUPM 558,000

CurrentPressure- PSIG 2,300Numberof Wel1s 51~ve~ag~g~& per gel~ - ~wp~ 360Total Porosityx Feet - Porosity-Foot 117.9AveragePorosity-Feetper Wel1 - Porosity-Foot 2.3AverageRate per Porosity-Foot- BWPO/Porosity-Foot 156

J No field-wideeffort to stabilize clays.

2 All injectorssoakedwith KC1 and coatedwith cationicpolymer.

l Of similarage and depositionaltype with comparableamountsofmontmorillonite,illite,chloriteand calcite. All wells setthru and given large hydraulicfracs.

TA8LE 3

TR[ANGLEU UNITINJECTIONWELL PERFORMANCESU1444RY

QE.!w30

31

31

30

3n

29

29

31

31

Hal 1 Slope

10.0110.03

5.75

8.48

9.66

11.8

13

14.8

18.35

InjectionPressure

2,700

2,750

2,600

2,600

2,200

2,900

2,700

3,000

2,700

MonthlyPs1

81,000

85,250

80,600

7B,000

66,000

84,100

7B,300

93,000

83.700

CumulativePs1

193,850

189,750

161,600

176,800

136,400

2,693,350

545,600

2,772,400

2,730,600

30,000

2,700

3

330

2

0.67

492

MonthlyInjection

8,090

8,500

14,007

9,201

6,830

7,130

6,020

6,290

4,560

L Al 1 wel1s treatedwith a KCI soak.

2 Receivedcationicpolymercoats rangingfrom 1,600LBS to 4,250 LBSeach at an averageconcentrateion of 180 mg/1.

3 Treatedwith 28,200L8S of KOH in 500 B8LS on 1O-31-B3.

NOTE: Al1 5 wel1s now on long-termwettabi1ity adjustment- averageconcentration= 64 mg/1.

CumulativeInjection

21,596

19,775 F!RsT

35,054 TWO

37,530 MONTHS

13,050

323,108

54,230 CURRENT

391,550 sTATuS

233,593

SP E12927

TABLE 4

RIJBENuNIT - S-4 ZONEPERTINENTROCK and FLUID PROPERTIES

Formation

Depth

Thi~kneSS (Oil column)

Porosity

permeabi1itY

Shaliness

Temperature

Q!l Gravity

oil ViscOsitY

Connate Water

ReSjdMSlOil

Almy (TertiarY)3,500 Feet

17.3 Feet

14.4%4-33md V= O.55

10% (estimated)

95F

43 API- . .... 0.,.+0.9 ~ps v MJDDI. ru,,~.

41.5 % Pv

20 %

Ht. % Alkali

o

0.1

0.2

0.4

0.6

u.a

1.0

1.5

2.3

3.0

4.0

TABLE 5

EFFECT OF ALKALINEAGENTSON UNTREATEDALMY SANO CRUDE OIL

FROM RUBEN UNIT #6 - S-4 ZONE

InterracialTef!sionin Oynes/cm2

PotassiumHydroxide

31.1

6.1

0.2

0.1

0.1

0.2

0.2

0.1

C.2

SodaAsh

31.1

19.7

16.7

10.7

7.0

6.0

4.8

1.9

0.2~.z 0.2

0.3 0.1

F@. I-(kmflood date for Suesex sand whh forrnatkm watOr and **h FOX HillssuF@Y

SodiumOrtho Silicate

31.1

23.6

9.0

~.~

0.2

0.1

SP E12927

E WATER INJECTION IN THOUSANDS OF BARRELSFig. 2-San Miguelsand unitHall plots forinjetilonWells32,85,86,and 91.

SP E12927

INJECTIVITY INDEX IN BA~ELS PER PSI0 0

BOTTOMHOLE PRESSURE (-3,000ft. Oatum)

%2 _

/.-

:,. 4

/(.1.

14

STARTPUMP-IN

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