Maxus Scale
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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.
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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
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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
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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
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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
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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.
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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=
(
$~2(5.0VBnne + 1 ).OVOil)l )-Sp
c~/
1.0+
)
~c~ =~xp P(2.84
X
10-4 - ~0~2~~~) and Yg Yml
8
nLOt(T+ 460)
[)
Caz+)(HCO~)z
= log
+ 3.63+ 8.68X 10-3T+ 8.55 X 10-~ - 6.56X 1 I SP- 3.42(1S.)1~+ 1.373(1.S.)
m
C:oz
l’)
HCO~)
log
— + 6.39- 1.198X 1O-3T+ 7.94 X 10-6T2 - 3.53X 10-5P- 1.067(1.S.)~~+ 0.599(1. S.)
02
(T4
or -
.
( )
:log
(Ca2+)(HCO~) + pH -
2.76+ 9.88x
103T + 0.61 x 10f’T2- 3.03x 1O-SP2.348 (1.S~)l~+ 0.770 (1.S.)
(T5
e: Ca2+=Total calcium(M=mg/1+ 40,000} (HCO~)=Bicarbonate~alinity (M= mgil + 61,000);P =Total absolutepresstue(psia);
Cw =Fugacitycoefflcentof C~ gas asa minor
= Temperature(“F); 1.S.=’Ionicstr@th (M= mg/1TDS+ 58,400sing/1 Cl-+ 35,450} @g
~ a Moieor volumefraction
%= Moleorvolumefractionof Q inthe gasphaseatthe specifiedT and ~ yrot
pecies in CH4+ Q g=, yg
of CX12onsideringgasplus oil plusbrine--thisisessentiallythe fractionQ inthe gas atthe surfae, n“mtTotalnumberofMMCFof gas at
STPproducedper day;VB~ ~ Barrels of brineproducedper day VoiI~ Barrelsof oilproducedper day;
C 2
c .
MMCFof Q per d ay a t
STP= XYmt.
c02 = ncoz x 1.38x 10?l(V~ + 3.04VOitknlw
4
10I
u)
u
m
N
n)
v
al
N
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SPE 8
‘able 3.
Equations to calculate the change in PH. APH,nd the change
in
saturation with respect to calcite, AS
J., for o
and
M wells. Sea
the bsrttom of the fxble for units 10 be uwd.
[)
Plop )I(y%
M.= log
+
15.19 x 10_3AT - 1.64X l116A@) -5.27 X 10%AP
P2(yp)2(@;03)2
(I-2.1
[1
PYyf
,PH= log
+
5.31 X lWAT2.253x06A(7) -2.237 x K@Ap
(T2.2
(PY;%;%z
“ L@_____J
c02
(5.0v ine10.OVO,I)
O$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~
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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.
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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
<