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SPE 22782

S

sc—3LJfJfPetmf?mmmeere3

Analysis of and Solutions to the CaC03 and CaS04 Scaling

Problems Encountered in Wells Offshore Indonesia

J,E, Oddo, .Rice U.; J.P. Smith, MAXUS Southeast Sumatra Inc.; and M.B. Tomson, Rice U.

SPEMembere

H

Copyr ight 1991, soc ie ty o f Pet ro leum Eng inee rs Inc .

This paper was prepared for presemati on at the 66 1h Annual Te chnica l Conference a nd Exhibition of t he Society of Petrol eum Engineera h eld in Dal las, TX, October 6-9, 199 1.

This paper was sel ected for pres entation by an SPE Program Committ ee following rewew of reformation contai ned in an abstr act s ubmdted by the author(s). Contents of the paper,

aa pr esented, hav e not bee n reviewed by t he Soci ety of Pet roleum Engineers a nd are suuecl to correction by the author(s). The mat erial. a s pres ented, does nfil ne cessar ily raflect

any pos it ion o f the soc ie ty o f Pet ro leum Eng inee rs , i fs o ff icers, o r members . Papers p resented a l SPE mee tings a re sub ject to pub li ca tion rev iew by Ednor ia l Commi tt ees o f Ihe Soc ie ty

ofPetroleum Engineers. Permission toCOPYis restr ic ted to an abstract ofnot more Ihan 200 words. I llustrat ions may not ba copied. The abstract should conta in conspicuous acknowledgment

of where a nd by whom the pspe r is pr esented. Wri te Pu blicali one Mansger. SPE, P.(.I Box S33 836, Richardson, TX 7506 3-3 636 U.S.A. Tel ex, 730 989 SPEDAL.

Pertamina/MAXUS Southeast Sumatra Petroleum, Inc. is

the largest offshore oil producer in Indonesia. CSC03 and CSS04

scaling in and around the submersible pumps of

peltamin~ $’ Farida/ZeldamSelVOirWdk kd to ~-riliitUIE

pump failures and costly workovers to bring the wells back into

production. Twenty-four well brines were analyzed on-site to

accurately determine brine chemistries and scale samples were

analyzed to “determineexact composition. Well histories were

studied to find correlations of procedures which led to scaling

problems. Saturation Indices, developed at Rice University and

presented in the paper,wereapplii to the probkms to give insight

into the causes of the intermittent, but costly scale formation.

Discussions were held with a submersible pump consultant and

pumps were examined to provide additional data for the analysis.

Thiieen scale inhibitorswere cvaluattxiat 225 F (107 C) and 300

psia (2.07 IMPa)in a 1.1%Q atmosphereusing a flow simulator

developed at Rtce University to firtd the most effective scale

most effective scale inhibhors in flow through testing and were

effective at 1.5ppm. Since the specialtychemical hadprecipitated

in thecontainer,ATMP wasrecommended.

The wells of Pertamina/MAXUS, particularly the Farida

and Zelda fields, in Indonesia have a tendency to scale in and

around the submersible pumps. The type of wale is primarily

calcium carbonate, but some calcium sulfate scale has been

identified. The latter occurs to a large extent after acid stimulation

treatments. Scale formation in thepumps cancause significantand

serious damage to the pumpcomponents and results inshort pump

runs which heavily impacts field economics. Although scale has

been reported p@rtaril@orn the Faridaand Zelda fields, scalewas

observed on or K the pumps from the Cln% Yvonne, Rama and

Intan fields (see Table 1).

A review of carbonatechemistry reveals the basic reasons

for the formation of scale in and around the submersible ~umps.



x,

ENCOUNTEREDINWELI& O~”SHO~ ~NESIA

SPE 22782

seawatersolution to displacethe acidduringan acidstimulationand

seawater kill fluids used in conjunction with the well workovers

was no doubt responsible for the precipitation CaS04 scale in and

sround the pumps. CaS04 scale is not predicted (see below) to

form from the produced water at bottomhole or wellhead

conditions. The addition of seawater to the system increases the

sulfateconcentrationfrom thenominalaverageof about20-40md

to the seawateraverageof 2650mg/LCalciumions liberated in the

fluids due to the dissolution of CaC03 by the acid unite with the

sulfate ions in the seawateroverflushand kill fluidsto form CaS04

scale.If the pumps do not fail due to the scale build-up, the scale

will probablyredissolvem the formationwateris producedpast the

CaS04 scale. However, if calcium carbonate wale then begins to

form due to the production parameters, the CaS04 scale maybe

trappedunder a layerof CSC03 scaleandnot redissolve,Anhydrite

is the predicted form of CaS04 scale to form at the temperatures

and ionic strengths of the MAXUS’wells. (For a discussion of

calciumsulfate scaling tendencies, seez”4’” 6.)

The inhibitor squeezes procedures recommended are being

initiated. Preliminary results of theprocedures shouldbe available

forthe convention in Dallas.

CA~

TION OFTHE SATURATIONIND CES FORCaSO~

~

The saturation index is a measure of the tendency of the

precipitatein question to form. Mathematicallystatedthe saturation

index isdefiied as the:

Cation]{Anion

sx=log~ ~ L....................(1)

where S1 = the SaturationIndexof thespeciesin question

[Cation] = theconcentrationof thecation in solution(M)

[Anion]

= theconcentrationof the anionin solution(M)

~ = the COIIdlhOIKdolubilityof the saltin question.

The conditional volubility is the volubility under the

conditions of temperature, pressure and ionic strength of the

solution in question. It is then possible to calculate the scaling

tendency of the water at any place in the production system.

Algorithms have been developed at Rice University to determine

the saturation indices for the sulfate scales including calcium

(gypsum, hemihydrate and anhyfirite), barium and strontium

sulfatebas well as for calcium c

nate,l, 3 The *uations needed

With a seawater sulfate concentration (2650 m~) and increr “ng

calciumconcentrationsdue to the acidstimulationtreatments, there

is an increasingtendency to form anhydritescale.

The calciumsulfate scalingproblemwasa resultof the a$id

stimulation treahiients performed on thewells in conjunction * hh

seawater kill fluids and overflush solutions. Acid stimulations

performed on the wells can be beneficial if it can be shown that

significant fines or scales are dissolved to increase production.

However, typically acid stimulations in shale formations can

J

issolvethe cementsthat consolidatetherockan liberatesand-size

and smrdkr particleswhich later foul thepumpsand/orperforations

or build-up in the reservoir near the wellboie causing formation

damage andskineffects,The useof ethylencdianiinetetraaceticacid

(EDTA) to dissolve scales which have formed in or near the

wellbore is preferred to acid if similar increasesin production rates

can be obtained.EDTA has thepotential to cause farless formation

damage than the fairly concentrated acids used in the oil field. In

addition, the liberation of cations such as calcium by the acid can

cause later scaling by forming CaS04 scale upon reaction with

sulfate from the seawaterusedin theKC1overflush.

The Pertamina/MAXUS’ wells would not have formed

CaS04 scale without the additionof seawaterwhich increastxi the

sulfate concentration in the system. Calculations of S1values for

CaS04 scale formation indicated that this scale would not have

been expected in the wells under any production scenario. S1

values are typically of the order of -1.5 to -2.5 based on the water

analyses. However, the ZEB-1 well CaS04 S1value for anhydrite

was up to -0.8 due to $e high sulfate concentration,This well had

recently been worked over and illustrates how CaS04 scale was

probably formed by seawater KC1solutions and kill fluids where

solutions with sulfate concentrations excdlng 2600 mg/1nxcted

with calcium ions from the dissolved CaC03 scale and in the

reservoir fluids.

If it is determined in the production history that

~ acid stimulation treatments are n~essary to maintain

production levels, the KC1overflush and acid solutions will be

mixed using freshwaterrelatively low in,sulfate.It qay be possible

to put a sufficientlylargeplug of fish water Kcl betwam the acid

and the seawater KCI solution to eiiminate the CaS04 scaling

problem if the expense of transportation of large amounts of

freshwater to the.wells is prohibitive. The required amount of

freshwater plug to.separate the acid from the seawaterwould have

to be determined for each well depending on the volumes of acid,

numberof perfomtedzones,etc. involved.It must be reiteratai that



SPi 22782

J,E. ODDO, J.P.“SMITH,AND M.B.TOMSON

3

temperature{=240 F (116 C)) plus 20 F (11 C) and down to S00

psi (3.45 MPa). It must be cm hasizcd that this point is an

istimation and wells operated at cse temperatures and pmsures

may, in fact, produce scale due to the uncwtainties concerning

localiml temperatures and pressures near the pumps and in the

components.

The operation of a pump motor at a point where the skin

temperature of the pump motor is 100 F (55.5 C )higher than the

mscmmizmaycmteanen

vironmentwhere scalecannot be avoided

with the use of chemical scale inhibitors. S1values in excess of

about 2.3 indicate a situation where scale may not be controllable

with chemicals. These very It@ temperatures should be avoided

with better pump designs. The use of rotuy gas separators also

produced high S1val’Jes(>1.5) dependingon the true efilcicncy of

the separator, These type separatcusshould also be avoided unless

significant increase

sin pumpefficiencycan be shown and the well

is treated fw scale.

As production rates need to be maximized to produce

maximum revenue, it may not be desirable to operate within the

bounds described above. Successful operation will be

accomplishedthroughthe useof thresholdchemicalscale inhibks

to control scale formation in the wells. Threshold inhibitors, such

as the phosphonates, have been used to control wale since 19367,

however, little is known about the actualmechanismsinvolved4*8*

9“1°”11.Tomson has recently developed a mechanism to explain

the inhibition of p&ipitation of sparingly soluble salts12and this

mechanismpruduces theoreticalcalculationswhichagree favorably

withquantitativeexperimentalresults.

Chemical inhibitors can be administered in the wells by

either of twomethodq treat stringsor inhibitorsqueezeprocaiures.

Treat strings are tubing stigs which extend downhole to a depth

where an operat~r feels secure that no deeper scale will form.

lhese de@w areknown by scalingexperienceor calculationusing

S1 C@tihOIIS. Inhibitor, is pumped down the tubing from the

surface and injected at depth directly into the brine stream. The

design of treat strings can vary signflcantly, but most rquire a

surface pump, a measuring or metering device, filters, well head

connections, and a downhole entry into the flow stream with an

optional check valve. Although many operators and chemical

companies claim that treat strings should be made of Inconel or

equivalent alloy due to the corrosive nature of many inhibitors, in

the authors’ experience, 316 stainless steel can be sufficient and

this shouldbe verifiedwith testing.

Precipitation and adsorption are the two mechanisms

generally proposed for the retention and release of the inhibitor in

the ~ese~oir. However, the actual mechanism, whether a

would rquire no calcium overflush, should be cheaper to

perform,and theoretically minimize the chances of formation

damage14*15.The design of the adsorptionsqueezeprocessdiffers

greatly from the design of the precipitation squeeze in that lower

concentrations of inhibitor are pu8hed further back into the

formation to saturate as many sorption sites as possible on the

resemoir rock matrix. More prwise knowledge of the speciation

and volubilityof inliibitora will increase the understandhg of the

squeezeprocess and enhance the effectiveness of squeeze design.

The mechanism for most squeezes, regardle88of how they were

designed, is suggested hereto be adsorption. It can be shown that

it is not possible to differentiate between a precipitation

phenomenon and one of adsorption by monitoring flowback

concentrations of the speciesin question (SCC21,p 122-128, for

a complete discussion). Research to determine methods to

distinguish between adsorption and precipitation retention

mechanisms is currently underway in our laboratories and

preliminaryresults suggesta fomnof adsoqxionas themechanism.

The inhibitor squeeze techniques now employed by

Pertamina/MAXUS are administered at low pH and maximize

inhibitor contact area andcontact time with the reservoir material.

The contact area is maximized with relatively large overtlush

volumes in conjunction with low inhibitor concentrations and tiie

contact timewith at least a 48 hour shut-in period. These variables

have preliminarily been determined to be the most important to

effectiveinhibhor squeezedesign.=

w~~

Pertamina/MAXUS wells are being treated with scale

inhibitor to protect the wells against CaC~ scale formation. T~t

strings are not recommended for the Pertamina/MAXUS’ wells

since a scale forming chemical environment probably extends into

the perforationsand even very shallowinto the adjohing reservoir.

Treat strings will not protect the perforations or the reservoir. In

addition, the placement of the treat strings in the wells would be

problematical since for sufficient mixing to occur before the fluids

enter the pumps, the tmt stings shouldbe placed at somedistance

from the pumps. However, withmultiple zones open to the hole, if

the w strings are placed at some distance from the pump, only

suffkient mixing will probably omur with the fluids coming from

the zonesadjacentto the endof thetreatstrings.

Pertamina/MAXUS engineers have determined that wells

where the pumps are placed near the top of the perforated intervals

scale less ofien than wells where the pumps are placed adjacent to



ANALYSISOF ANDSOLUTIONS7011-iE CaCOaandCaSO~SCALINGPROBLEMS

4

ENCOUNTEREDINWELLS,OFI%$HORENEWA

SPE 22782 “

the squeeze fluids will also produce significant fluids during

reduction. As thismay not be easy to determine and if this cannot

L

determined with any certainty, then the important sands should

be squeezed individually. The inhibitor to be used in such a

squeeze has been determined (see below)with inhibitor evaluation

tests.

Although dilute acid procedures will dissolve calcium

carbonate, thedilute acids that were recommendedfor scale clean-

up will probably do little to “stimulatethe nwxvoirs” in the sense

of a conventionalacid treatment.Ifcmcentrated acid stimulationof

the reservoirs is deemed to be required by Pcrtamina/MAXUS’

engineers, an additional step will be added to the procedures and

will be done with filtered fresh or produced water with scale

inhibitor. Seawater will be avoided to minimize the chances of

calcium sulfate scaleformation. Seawatertreatmentswill not work

with strong acids. It may be stated however, that in some cases

EDTA treatments for scaleremovalhave brought thewells back to

expected production levels and that acid stimulation of the

reservoirs may. not be required and, for reasons discussed

pnwiously,maybe detrimental.

The procedureswere designed in three parts 1)a clean-up

phase using dilute acids or EDTA to remove scale build-up from

the last production rum 2) the inhibitor squeeze phase to place the

inhibitor pill in the mervoic and 3) anoverflushphase to movethe

inhibitor into the reservoir a designated distance and maximize

contact area. The procedures were designed to remcwescale and

present an environment conducive for inhibitor retention in the

rescuvoirs and slow release during production. The inhibitor

squeezes are now being performed with low inhibitor

concentrations in a low pH environmentwith longer contact times

(48hours)and largerovertlush volumes.

Two general procedures were discussed with

Pertamina/MAXUS for the inhibitor squeeze along with their

advantages anddisadvantages. In addition, the general ptiedures

were alte]ti to accommodatethe use of tlesh or producedwater or

seawater as the basic solvent. All solutions used in the procedures

are filtered before use in the wells to minimize the chances of

plugging on the formation face. This is important because some

Pertamina/MAXUS’ produced brines will precipitate calcium

c@onate upon standing and produced water must be filtered. All

seawater used as kill fluids contains 10ppmactive scale inhibitor.

This is extremely importantand should not be minimized since

calcium sulfate scale may formin the well as a result of not adding

inhibitor to the kill fluids if seawater is used. After the inhibitor

squeeze is administered, the useof further kill fluids or any other

kind of solution into the zones squeezed or the wells after the

overflush solution is displaced by one well volume should be

strictlyavoidedsinceLhiswill alter the squeezeprocedure.

to simulate the downholc production parameters andmaintain 3(NI

psi (2.07 M.Pa),225 F (107C) and do the experiment with a 1.1%

C02 in helium atmosphere. Note, helium is used instead of air so

that thepump does notdevelopgasbubbles in thepistonchambers.

The syntheticbrine will notprecipitateCaC03 at room temperature

and pressurein a 1.1% CQ atmosphere.

The evaluation is accomplishedby starting the experiment

with two brine containers. One has scale inhibitor at 10mg/1and

theother hasno inhibitor.The ratioof inhibitedbrine to uninhibited

brine is decreased until precipitation of CaC03 is detected in the

system. Recipitation was detected in the system by in-line pH

measurement. Since the evaluation required a 1.1% C02

atmosphtneand 300psi (2.07MPa), theevaluationscould nothave

been done in a P-Mac machine. The mixing pump is capable of

4500 psia and can mix the two brines accurately to less than 1%.

The pump contains no metallic surfaces that contact the brine so

that no adsorptionof inhibitoronto a metal surface is possible.The

tubingis madeof PEEKmaterial.

The results of the evaluations can also be seen in Table 4.

The minimum amount of inhibitor to successfully inhibit

precipitation of CaC03 is shown in the table and the inhibitorsare

ranked from the most effective inhibitor at the top of the table and

the least effective at the bottom. The proprietary A sample had a

precipitate in the bottom of the bottle which failed to rcdkolve

upon stirring or heating of the sample. Should the product contain

precipitatesin the field squeeze,these solidscan plug the formation

face and therefore, the product would need to be filtered before

use. Aminotri-(methylene phosphoric) acid (ATMP) is a generic

productwith a proventrackrecordwith CaC03 scale.

~

Phosphonate residuals were measured in the laboratory

using the extraction techniquedeveloped specifically for brines at

Rice University”. l’lte results of the analyses arc shown iti Table

5.The wells with EDTAclean-upsand phosphonateresidualshave

had a factor of three longer pump runs than the average. This

verifies the conclusiorrs reached by calculation and laboratory

simulation. The data indicate that the wells can be treated by

squeeze treatments properly applied and pump runs can be

significantlyincreased.

~

Five inhibitor squeeze applications are planned for :he

_Pertamirra/MAXUS’wells in Indonesia sing the techniques

described @ this paper. Results from the”inhibitor squeeze



SPE 22782

J.E. ODDO, J.P. SMITH,AND M.B.TOMSON

5

.

5.

6.

7.

8.

9.

10.

Although the zones to be packedoff and squeezed together in

any particular well need to be detegrninedwith the input of

Pertamina/MAXUS petroleum and reservoir engineers, two

basic clean-up and squeezeprocedureswere recommended as

guides to performing scale clean-up and inhibitor squeezesin

the PertarninalMAXUS’wells.

Thirteen scale inhibitorshavebeenevaluatedpreviouslyat 225

F (107 C) and 300 psi (2.07 MPa) under 1.1% C02 to

simulate the Pertamina/MAXUS’production. The two most

effective inhibitors were found to be Proprietary chemical A

and aminotri(methylene phosphoric) acid (Dequest 2000)

(ATMP).

Since the squeeze procedures are suggested to be

performed in a low pH environment, the acid form of the

inhibitor is suggested to be purchased.The ATMP acid form

shouldalsobe thecheapestand most concentmted(50%active

concentration).

CSS04 scaleprobably forms as a resultof the overflqsh of the

seawaterKC1solutionafteran acid stimulationtreatment.Acid

treatments were being performedwith acid concentrations far

in excess of what is neededfor simplescale clean-up.Calcium

concentrations are controlled and calcium sulfate scale

formationeliminatedor minimizedwith the useof more dilute

acid solutions (0.3% - 0.5%) and inhibitor in the kill fluids

and other fluidsput intothe wells asdescribed in the text.

CaCQ scale formsdue to the increasedtemperatureand/or the

decreased pressure and gas separation in or near the

submersiblepumps.

As a general gui&line, the outside skintemperature of a pump

motor should not be allowed to exceed 20 F (11.1 C) above

the ambient reservoir temperature at 500 psi without the

wkiitionof scaleinhibitor.

Excessively hotmotors or very eff:cient rotary gas separators

maycnxe an environmentwherescalecannotbe controlledby

threshold chemical scale inhibitors In addition, scale formed

on pump motors will insulate the pump and cause premature

pump failures. It is strongly recommended that rotary gas

separators not be used in the wells unless significant

production increases can be demonstrated. The scaling

environment produced by the may gas separators should be

evaluated in the laboratory to determine the amount of

supersaturationin the separatorif *ey are used.

It was noted by Pertamina/MAXUS’ engineers that longer

1.

2.

3.

4.

5.

6.

7.

8.

9.

10.

11.

12.

13.

14.

15.

16.

17.

18.

Tomson, M.B. and Oddo, J.E.: “A New Saturation Index

Equation to Predict Calcite Formation in Gas and Oil

production: SPE Joum. of Petri. Tech. (1990) Sub. 10,1990

Stumm, W. and Morgan, J.J.: Aquatic Chemistry, Wiley-

InterScience,NewYork, NY (1981)780p.

Oddo, J.E, and Tomson, M.B,: “Simplfied Calculation of

CaC03 Saturation at High Temperatures and Pressures in

Brine Solutions: J. Pet. Tech. (1982)34 pp. 1583-1590.

Cowan,’ J.C. and Weintritt, D.J.: Water Formed Scale

Deposits,

Gulf PublishingCo., Houston, Tx (1976) 586p.

Carlberg, B.L. and Matthews, R.R,: “Volubilityof Calcium

Sulfate in Brine,” SPE AIME 4353 (1973)pp. 69-78.

Oddo, J.E. and Tomson, M.B.: “WhyScale Forms in the Oil

Field and Methods to Predict It,” SPE Prod. Oper. Sym.,

OklahomaCity,OK, SPE 21710 (1991)

Rosenstein, L.: “Process for Treating Water, U.S. Patent

2.038.416.” (1936)

. -.,

Patton, C.&:’Appl~ed Water Technology, Cambell Petroleum

Series, NormanOK, Norman, OK (1986) 364p.

Matty,J. and Tomson, M.B.: “Effectof Multiple Pnxipitation

Inhibitorson CalciumCarbonateNucleation: App. Geochem.

(1988) 3 pp. 549-556.

. .

Vetter, O.J.: “An Evaluation of Scale Inhibitors,” J. Petri.

Tech. (1972) 24 pp. 997-1006.

Walton. A.G.: The Formation and Properties of Precipitates,

Wiley-I’nterscience,New Yodc,NY (1967) - -

Tomson, M.B.: “Effectof Precipitation Inhibitors on Calcium

Carbonate Scale Formation,” J. tlstl. Growth (1983)62 pp.

lo&l 12.

Vetter, O.: “The Chemical Squeeze Process-Some New

Information on Some Old Misconceptions,”J. of Petri. Tech.

(1973) March pp. 339-353.

Oddo, J.E. and Tomson, M.B.:

“The Volubility and

Stoichiometryof Calcium- Diethylenetriaminepenta(Methylene

Phosphonale:)

at

70 Deg C in Brine Solutions at 4.7 and 5.0

pH,” App. Geodmm. (1989)5 pp. 527-532.

Hong, S.A. and Xwer, P.J.:

“A Mathematical Model for the

Scale Inhibitor Squeeze Process,” SPE Int’1Sym. on Oilfield

Chern., SanAntonio, Texas, SPE 16263(1987)

Tomson, M.B., et

al.:

“Useof Inhibitors for Scale Control in

Brine-producing C3asand Oil Wells,” SPE 61st Ann. Conf.,

New Orleans, La, WE 15457 (1986)

Rogers, L.A., et aL:

“Use of Inhibitors for Scale Control in

Brine-Producing Gas and 011 Wells,” SPE Prod. Eng. J.

(1990) pp. 77-82.

Shuler, P.J., Freitas, E.A. and Bowker, K.A.: “Selection and

Abdication of Barium Sulfate Scale Inhibitors for a Carbon



ZEA-1

ZEA-2

ZEA-4

ZEA-5

ZEB-1

ZEB-2

ZEB-3

ZEB-4

ZEB-8

ZEB-9

ZEC-2

ZEC-5

ZEC-6

ZEC-8

ZEC-9

ZEC-12

ZED3

ZED4

ZED-5

12/8@301

09/87/333

11/75/107

09n7t93

lon8/69

02J83129

Of- 87145

08f87122

());:&m

12/88/31

01/89/9

031’87138*

0518W12

0418W184

11/81/120

09/87/10

08/87126S*

05/88/33

03/89/170

04187157

lofliiw

03188MP

10/90

07187117*

09i83/184

03/88/68

08188198*

10/89/112

())$;1

10/88/141

03t89/192

1lj89]165

09/83/63

08/87/50

10/90

06/87/66

08187f10

11/87/103

02488/107

06188J19*

0319W9

ZEE-1

2333-8

ZEE-9

FAA-1

FAA-2st

FAA-3

FAA-4

FAA-5st

FIM4-6

FM-7

FAA-8

FAB-1

FAB-3

FAB-5

FAB-6

FAB-7

10/87/92

03/89/36

03/88/71*

09/87/362

08/8?/178

06/88/259

05/82/520

07186/203

07/88/40

09/88/205

03/90/19”

07182164

09/89/113

c3/83/146

05/83/90

09/84/184

09/84/102

08/84/64

0918314

11/88/17

09/89/115

1lj83/54

07/84/52

09~;565

08/88/110

12/88/298

09189i298

12486*

01/83/97

08/83/48

10/83nl

01/85/207

02j861697

0MUM253

01PNW2

071841188

0318511

0718W

03189174

081891150

04i85147

10EW14*

Table 1 (con’t)

WellName

DateReported

WellName

DateReported

Mo/Yr/RunTu

Mo/Yr/RunTim

ZED-6

Wsfl

FAB-7

04/87/195

12/87/27

FAC-1

04/89f260

10M

FAC-3

07/87/38

z-;

10/90

INB-5

10/89/161

10/90

FAC-4

09/87/128

10/90

07/89/81

ED-;

11/86/9

RAF-3

03/90/125

11/87167

n~-1

02/90/584

08/88/155

0@9 4

10/90

s?

10/90

CID-6

04W5

CID-8

03@0/318

* Scalenot reported,but EDTAand/orscale inhibitorduringworkoverindicatingscale

formationat some time in thepast.

The list is probablyincompletedueto scalenot beiig reportedin well historie$ e.g.

scaleinhibitorsqueezejob beingdonewithno mentionof scaleindicatesotherwells

probablyhave experienceda scaleproblemwithoutmentionin thewellhistories.



2 Recommended equations to calculate calcite Saturation Index (SI

) and to calculate pH f

or od and gas wells.

convenience, the units on VBrl,e and Voll are

BPD and ntot is MMCF at STP

per day (see note at bottom of table).

Note:

: Cr. = Ca2+

= Total Calcium

H

C +)(l-my

: log

+ 5.85+ 15.19X 10JT - 1.64X 106T2 - 5.27X 10SP - 3.334(1.S.)1~ + 1.431(1.S.)

(-H

~y ~:2

\

/

[

)“

-Iwo;)

log

+ 8.60+ 5.31 X 1O-3T2.253 x1o-STZ-2.237 X l@P -0.990(1S.)1~ + 0.658(1.S.)

m

~;02 *:02

(

C02=

(

$~2(5.0VBnne + 1 ).OVOil)l )-Sp

c~/

1.0+

)

~c~ =~xp P(2.84

X

10-4 - ~0~2~~~) and Yg Yml

8

nLOt(T+ 460)

[)

Caz+)(HCO~)z

= log

+ 3.63+ 8.68X 10-3T+ 8.55 X 10-~ - 6.56X 1 I SP- 3.42(1S.)1~+ 1.373(1.S.)

m

C:oz

l’)

HCO~)

log

— + 6.39- 1.198X 1O-3T+ 7.94 X 10-6T2 - 3.53X 10-5P- 1.067(1.S.)~~+ 0.599(1. S.)

02

(T4

or -

.

( )

:log

(Ca2+)(HCO~) + pH -

2.76+ 9.88x

103T + 0.61 x 10f’T2- 3.03x 1O-SP2.348 (1.S~)l~+ 0.770 (1.S.)

(T5

e: Ca2+=Total calcium(M=mg/1+ 40,000} (HCO~)=Bicarbonate~alinity (M= mgil + 61,000);P =Total absolutepresstue(psia);

Cw =Fugacitycoefflcentof C~ gas asa minor

= Temperature(“F); 1.S.=’Ionicstr@th (M= mg/1TDS+ 58,400sing/1 Cl-+ 35,450} @g

~ a Moieor volumefraction

%= Moleorvolumefractionof Q inthe gasphaseatthe specifiedT and ~ yrot

pecies in CH4+ Q g=, yg

of CX12onsideringgasplus oil plusbrine--thisisessentiallythe fractionQ inthe gas atthe surfae, n“mtTotalnumberofMMCFof gas at

STPproducedper day;VB~ ~ Barrels of brineproducedper day VoiI~ Barrelsof oilproducedper day;

C 2

c .

MMCFof Q per d ay a t

STP= XYmt.

c02 = ncoz x 1.38x 10?l(V~ + 3.04VOitknlw

4

10I

u)

u

m

N

n)

v

al

N



SPE 8

‘able 3.

Equations to calculate the change in PH. APH,nd the change

in

saturation with respect to calcite, AS

J., for o

and

M wells. Sea

the bsrttom of the fxble for units 10 be uwd.

[)

Plop )I(y%

M.= log

+

15.19 x 10_3AT - 1.64X l116A@) -5.27 X 10%AP

P2(yp)2(@;03)2

(I-2.1

[1

PYyf

,PH= log

+

5.31 X lWAT2.253x06A(7) -2.237 x K@Ap

(T2.2

(PY;%;%z

“ L@_____J

c02

(5.0v ine10.OVO,I)

O$P

(

$cQ=,Xp P(2,84 X 104- ~~) Mld~=

K

E

[

@~(5.OVB,i.. + 10.OVO,I)IOSP

1.0+

0’+

460)

)

1

.

AS.I. = 8.68

X l&3AT - 1.64X

l&6A@) - 6 .56X 1O$AP

(T2.3

APH = - 1.198X

1&3A’ f +

7.94

X

10~A(T2) - 3.53X 10’5&

(T2.4

@ * f7uga~i~y~ff it icn t OfCo2

gi3SaS a minOr sties ‘n c m + ~ g~

Vhcrc:

P= Total

absolurc PS’CSSW

fpsia); T = Temperature (OS%$g

w * &fok ~ “Oluw -on of @ in AISg= pIM.Wat r hc spccificd T and P , nW = T otaf nUMk of ~ ~ of gas a I SW produc~ ~r

Yu

d.ly, %nc = Ba2’rdsof kit3e f31WhKd

pe r dafi VrM=Bards o foil pmdtsccd psr day.

.

%ble

4 .

Recommended

$slurati ors I r rdcx Equations for Comnrmc Sulfat e M.

mcrals.

Al

I terms needed for the

catcthtiosrs

re stetkd at the WtOcn of the tafrte. Ttsc term,

[S042.]

r f m to the -centration of imcomplexcd

or free sulfate. If the concentration of

CM* is zero, or negligible, [S042-] = CS04.

PK’

=

+1.86 +

4.5xl&3T - 1.2x K HT7 + 10.7x103P - 2.38W + 0.581- L3x10_311~)

For gypsurnj hemihydrate and anhydrite: ,

[Sofl = [CSO, - %g - @K + [(%04 - CMg - @K )2 + 4“@’K CS041’nl~



Species

Calcium

?+ nedum

Bicmbon@

sulfate

m

ReseIvoirTemp.

Reservoir Press.

MM(ID gas

230mfl

20mg/1

0.5mg/1

976mg/1

25m l

0.081MoleFraction

240 F(116C)

2800 psi (19.3 MPa)

0.3 (8495 m3/d)

BOPD -

250 (39.8

m3/d)

BWPD ..

250 (39.8 m3/d)

.

I

l dc i um c ar bo na te

Temperature Ressure

F (C)

240

ps;8y)

500

:%

500

180 500

180 300

hlcium Sulfate

TT ~ssure

p$8y)

240

240 2800

SI pH

0.00 5.44

0.68 6.05

0.11 5.89

-0.18 5.80

0.03 6.00

Cakium su l fa te

S1

mgll

mgtl

-1.86

:: 26: 0.16

2ti 2800 lti

26S6 0.79

. .

e7.

lle~

Inhibitor

Minimum EffectiveDose

(mgll) as suppliedproduct

ChemicalAl

1.5

~&ue~2~ (ATMP)2

:::

chemical c

2.0

De esJ2Dw (DTPMPy

2.0

2.5

ChemicalE

5.0

ChemicalF 5.0

ChemicalG

7.0

ChemicalH

8.0

ChemicalI

chemical J

;::

chemical K4

>10.0

nhibitorsamplehad a precipitateinthe bottomof the samplebottlewhichwould

tissolve upon heatingand stirringwithina reasonabletime. The samplemay

mm supersaturatedwith respect to the inhibkor. Thisprecipitatemay cause

lngof thereservoirfaceduring a squeeze.

IPis aminotri(methylenephosphoric) acidwhichwas suppliedby the Monsanto

anyand can.bepurchasedfrommany manufactumrs.

klP is diethylenetriaminepenta(methylenephosphoric) acidwhichwas supplied

MonsantoCompanyand can be purchasedfrommanymanufacturers.

tilbition tendencywas seenusingthischemicalat 10.0mg/1. Theevaluationwas

wice toverifv theresult.



WCU Name Rcsd&hookMte

Iman

CcqOsite

FAB-3

FAB-4

FAB.7

FAC-4

-ZEB-8

g:

ZEB-2

ZES-5

ZEW9

ZEC-2

m-s

ZEC-9

ZED-6

23Z&9

DrillWaul

2.0

N.D.*

N.D.

N.D.

0.5 . 0 .s

1.0

N.D.

5.5 , 5 .4

X.D.

N.D.

0.5

0.4

N.D.

0.7

0.7 , 0 .6

N.D. , N.D.

0.3 . 0 .6

N.D.

‘N.D. - None Dcmcwd; below thede tect ion l imit o f 0 .3 m&v l

Inhibited

Uninhibited

Brine

Brine

I

I

I

I

Oil Bath

Totally Inert

Mixing Pump

225 F

Ionic Strength M

Figure

1.The negative logof thecalcite mnditionsl volubility (pKc) vs.Temperature (F)

nd Ionk Strength M

Drain

EllEl

Figure2. Sohematic diagramof the inhibitorevaluation apparatusconfigured

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