Method for metal sulfate scale control in harsh oilfield conditions

A method for inhibiting barium sulfate precipitation in low pH aqueous fluids of underground petroleum-bearing formations by adding to such systems an effective amount of low molecular weight water-soluble polymer containing 5-35 weight percent sulfonic acid monomer units and 65-95 weight percent carboxylic acid monomer units, is provided. Polymer compositions based on 10-15 weight percent 2-acrylamido-2-methyl-1-propanesulfonic acid, 15-65 weight percent acrylic acid and 25-70 weight percent maleic acid are particularly preferred for use at very low pH conditions, e.g., 5.5 or less in the presence of high sulfate ion and barium ion concentrations.

This application claims priority to Provisional Application No. 60/012,656 
filed Mar. 1, 1996. 
BACKGROUND 
This invention relates to an improved process for preventing scale 
formation in aqueous systems found in underground petroleum-bearing 
formations having low pH and high salt content by the addition of certain 
low molecular weight, water-soluble polymers. More particularly the 
invention relates to the selection of certain polymer compositions that 
exhibit unexpectedly improved precipitation inhibition, especially for 
inhibiting the precipitation of barium sulfate under conditions where 
conventional scale-inhibiting polymers are ineffective. 
Precipitation of inorganic salts, such as calcium carbonate and calcium, 
barium and strontium sulfate, as scale deposits is a common problem in oil 
field operations for the recovery of petroleum products from underground 
petroleum-bearing formations. The mixing of incompatible aqueous fluids 
during field operations, especially enhanced oil recovery activities 
involving a waterflood or water drive, encourages inorganic salt scale 
formation and deposition in the formation as well as in appurtenant 
production equipment and transfer lines. Incompatibility occurs when two 
or more aqueous fluids are mixed and each contains distinct ions that are 
capable of combining to form precipitates that deposit as scale. Typically 
the formation water or brine present in a reservoir will contain barium, 
calcium and possibly strontium ions and the injection water used during 
enhanced oil recovery operations will contain sulfate ions. An example is 
illustrated by offshore oilfield procedures where large volumes of sea 
water containing high concentrations of sulfate ion are used as injection 
water for underground petroleum-bearing formations containing brine with 
high concentrations of calcium, barium and strontium. Upon mixing of the 
injection and formation fluids, precipitation of barium, calcium or 
strontium sulfate will occur within the formation itself and in surface 
production equipment and transfer lines; a typical mixing point for the 
two fluids is in the near production well bore area of the underground 
petroleum-bearing formations. 
Cleaning and removal of scale deposits within underground petroleum-bearing 
formations and from the associated surface production equipment and 
transfer lines is expensive, time-consuming and relatively ineffective and 
conventionally involves the use of mechanical methods, such as impact or 
cavitation jets. A method that is more preferable to the frequent physical 
cleaning of scale deposits is the use of scale inhibitors to minimize the 
formation of scale deposits and thus reduce the frequency of physical 
cleaning. Conventional scale inhibitors, primarily polyelectrolytes such 
as phosphonates and low molecular weight carboxylate polymers, while 
generally satisfactory for inhibiting scale formation over a range of 
oilfield conditions, have been ineffective at the low pH conditions, i.e., 
less than about 6, encountered in certain underground petroleum-bearing 
formations. The lack of scale-inhibiting effectiveness of conventional 
scale inhibitors increases as the pH of the formation water decreases. 
An approach to solving the scale formation problem at low pH conditions 
involves the use of polyvinyl sulfonate polymers as scale inhibitors. For 
example, U.S. Pat. No. 4,710,303 and U.S. Pat. No. 5,092,404 disclose the 
use of low and high molecular weight polyvinyl sulfonate polymers, 
respectively, for the inhibition of barium sulfate precipitation in low pH 
waters found in underground petroleum-bearing formations. While somewhat 
effective as scale inhibitors, the use of polyvinyl sulfonate polymers 
does not address additional requirements of effective scale inhibitors 
used in these applications. For example, adsorption characteristics of the 
scale inhibitor on the subterranean formation surfaces is an important 
feature that allows extended time periods before additional treatments of 
scale inhibitor are required. The use of polyvinyl sulfonate polymers in 
oilfield applications does not satisfy this requirement. 
The process of the present invention overcomes the deficiencies of prior 
methods used to inhibit scale formation at low pH conditions in 
underground petroleum-bearing formations and provides a process that 
inhibits scale formation, especially barium sulfate, for extended periods 
of time and allows for low use levels of the scale inhibitors. 
STATEMENT OF INVENTION 
The present invention provides a method for inhibiting metal sulfate salt 
scale formation in an aqueous fluid being present in or produced from an 
underground petroleum-bearing formation, comprising contacting the aqueous 
fluid with an effective amount of a water-soluble polymer comprising 
monomer units of (a) from 5 to 35 percent by weight of unsaturated 
sulfonic acid monomer selected from one or more of 
2-acrylamido-2-methyl-1-propanesulfonic acid, 
2-methacrylamido-2-methyl-1-propanesulfonic acid, 
3-methacrylamido-2-hydroxy-1-propanesulfonic acid, allyl-sulfonic acid, 
allyloxybenzenesulfonic acid, 2-hydroxy-3-(2-propenyloxy)propane-sulfonic 
acid, 2-methyl-2-propene-1-sulfonic acid, styrene sulfonic acid, vinyl 
sulfonic acid, 3-sulfopropyl acrylate, 3-sulfopropyl methacrylate and 
water-soluble salts thereof; (b) from 0 to 85 percent by weight of 
unsaturated monocarboxylic acid monomer selected from one or more of 
acrylic acid, methacrylic acid, crotonic acid, vinylacetic acid and 
water-soluble salts thereof; (c) from 0 to 80 percent by weight of 
unsaturated dicarboxylic acid monomer selected from one or more of maleic 
acid, maleic anhydride, fumaric acid, itaconic acid, citraconic acid, 
mesaconic acid, cyclohexenedicarboxylic acid, 
cis-1,2,3,6-tetrahydrophthalic anhydride, 
3,6-epoxy-1,2,3,6-tetrahydrophthalic anhydride and water-soluble salts 
thereof; and (d) from 0 to 20 percent by weight of unsaturated 
non-ionizable monomer; wherein the polymer has a weight average molecular 
weight of 1,000 to 20,000; wherein the aqueous fluid comprises inorganic 
ions selected from one or more of calcium, barium, strontium and sulfate 
ions; and wherein the aqueous fluid has a pH of 7.0 or less. 
In another aspect the present invention provides a method for inhibiting 
metal sulfate salt scale formation in an aqueous fluid according to the 
aforementioned method further comprising injecting an aqueous solution of 
the water-soluble polymer into the underground petroleum-bearing 
formations via a well bore in fluid communication with the underground 
petroleum-bearing formations, the water-soluble polymer being adsorbed 
within a matrix of the underground petroleum-bearing formations and then 
desorbed from the matrix into the aqueous fluid. 
In another aspect the present invention provides a method as described 
above further comprising injecting additional aqueous solution of the 
water-soluble polymer into the underground petroleum-bearing formations at 
time intervals selected to provide amounts of the water-soluble polymer 
effective to maintain scale inhibition. 
DETAILED DESCRIPTION 
We have found that certain low molecular weight polymers containing 
selected ratios of sulfonic acid and carboxylic acid monomer units provide 
unexpectedly improved performance in the stabilization of aqueous systems 
found in underground petroleum-bearing formations having low pH and high 
salt content as compared to the stabilization provided by conventional 
polycarboxylate and polyvinyl sulfonate polymers. 
The polymer compositions found to be useful in the present invention 
contain units derived from at least two types of monomers: (1) carboxylic 
acid type and salts thereof, (2) sulfonic acid type and salts thereof and 
optionally (3) a unit derived from certain unsaturated non-ionizable type 
monomers. Water-soluble-salts of the polymer compositions, for example, 
the alkali metal salts (such as sodium or potassium), and the ammonium or 
substituted ammonium salts thereof, can also be used. 
As used herein, the terms "(meth)acrylate" and "(meth)acrylamide" refer to 
either the corresponding acrylate or methacrylate and acrylamide or 
methacrylamide, respectively. Also, as used herein, the term "substituted" 
is used in conjunction with various (meth)acrylamides to indicate that one 
or both hydrogens attached to nitrogen of these compounds has been 
replaced, for example, with (C.sub.1 -C.sub.8)alkyl or hydroxy(C.sub.1 
-C.sub.8)alkyl groups. When the term "substituted" is used in conjunction 
with various alkyl (meth)acrylate esters it indicates that one or more 
hydrogens of the alkyl groups have been replaced, for example, with 
hydroxyl groups. 
As used herein, all percentages referred to will be expressed in weight 
percent (%) unless specified otherwise. The phrase "inhibiting the 
precipitation" means the solubilization of scale-forming salts or 
reduction of the particle size or amount of precipitated scale-forming 
salts. The phrase "scale-forming salt" is meant to include, for example, 
calcium carbonate, calcium sulfate, barium sulfate, strontium sulfate and 
"NORM" scale salts. "NORM" refers to Naturally Occurring Radioactive 
Material; such materials may be hazardous if they are deposited on surface 
equipment. By "stabilization" we mean the combination of preventing 
precipitation of scale-forming salts and maintaining whatever precipitate 
that does form at a sufficiently small particle size (below about 0.45 
microns) such that the precipitate particles do not normally deposit on 
surfaces such as liquid transfer lines or mineral surfaces found in 
reservoir formations. 
The amount of unsaturated sulfonic acid units and salts thereof in the 
polymer composition can vary from 5 to 35%, preferably from 10 to 25% and 
more preferably from 10 to 20%. Unsaturated sulfonic acid monomers useful 
in this invention include, for example, 
2-acrylamido-2-methyl-1-propanesulfonic acid (the acryonym "AMPS" for this 
monomer is a trademark of Lubrizol Corporation, Wickliffe, Ohio, U.S.A.), 
2-methacrylamido-2-methyl-1-propanesulfonic acid, styrene sulfonic acid, 
vinyl sulfonic acid, 3-methacrylamido-2-hydroxy-1-propanesulfonic acid, 
allylsulfonic acid, allyloxybenzenesulfonic acid, 
2-hydroxy-3-(2-propenyloxy)-propanesulfonic acid, 
2-methyl-2-propene-1-sulfonic acid, 3-sulfopropyl acrylate, 3-sulfopropyl 
methacrylate and water-soluble salts thereof. Preferably, the unsaturated 
sulfonic acid units are those of 2-acrylamido-2-methyl-1-propanesulfonic 
acid, styrene sulfonic acid, vinyl sulfonic acid, 
2-hydroxy-3-(2-propenyl-oxy)propanesulfonic acid and 
2-methyl-2-propene-1-sulfonic acid. Preferred salts include, for example, 
sodium, potassium and ammonium salts. 
"Unsaturated carboxylic acid monomer," as used herein, refers to 
unsaturated monocarboxylic acid monomers, unsaturated dicarboxylic acid 
monomers and any unsaturated monomer containing more than two carboxylic 
acid groups, e.g., polyacid. 
"Unsaturated dicarboxylic acid monomer," as used herein, refers to 
unsaturated dicarboxylic acid monomers containing 4 to 10, preferably from 
4 to 6, carbon atoms per molecule and anhydrides of the cis-dicarboxylic 
acids. Suitable unsaturated dicarboxylic acid monomers useful in the 
process of the present invention include, for example, maleic acid, maleic 
anhydride, fumaric acid, itaconic acid, citraconic acid, mesaconic acid, 
cyclohexenedicarboxylic acid, cis-1,2,3,6-tetrahydrophthalic anhydride 
(also known as cis-4-cylcohexene-1,2-dicarboxylic anhydride), 
3,6-epoxy-1,2,3,6-tetrahydrophthalic anhydride and water-soluble salts 
thereof. Preferred unsaturated dicarboxylic acid monomers are maleic acid 
and maleic anhydride. The amount of unsaturated dicarboxylic acid monomer 
units and salts thereof in the polymer composition can vary from 0 to 80%, 
preferably from 10 to 70%, more preferably from 30 to 60% and most 
preferably from 35 to 50%. 
Suitable unsaturated monocarboxylic acid monomers are, for example, acrylic 
acid, oligomeric acrylic acid, methacrylic acid, crotonic acid, 
vinylacetic acid and the water-soluble salts thereof. Preferably, the 
unsaturated carboxylic monomer units are those of acrylic acid or 
methacrylic acid, and more preferably those of acrylic acid. Preferred 
salts include, for example, sodium, potassium and ammonium salts. The 
amount of unsaturated monocarboxylic acid monomer units and salts thereof 
in the polymer composition can vary from 0 to 85%, preferably from 5 to 
70% and more preferably from 20 to 60%. 
When used, the amount of optional unsaturated non-ionizable monomer units 
in the polymer composition can vary from 0 to 20% and more preferably from 
0 to 10%. Optional unsaturated non-ionizable monomers useful in this 
invention include, for example, unsubstituted or substituted 
(meth)acrylamides such as (C.sub.1 -C.sub.8)alkyl or hydroxy(C.sub.1 
-C.sub.8)alkyl methacrylamides and (C.sub.1 -C.sub.8)alkyl or 
hydroxy-(C.sub.1 -C.sub.8)acrylamides; unsubstituted or substituted 
(meth)acrylate esters such as (C.sub.1 -C.sub.8)alkyl or hydroxy(C.sub.1 
-C.sub.8)methacrylates and (C.sub.1 -C.sub.8)alkyl or hydroxy(C.sub.1 
-C.sub.8)-acrylates; vinyl acetate and hydrolyzed vinyl acetate; and 
aromatic hydrocarbon monomers such as styrene and vinyltoluene. 
Preferably, the optional unsaturated non-ionizable monomer units are those 
of one or more of tert-butylacrylamide, acrylamide, vinyl acetate, vinyl 
alcohol, styrene, ethyl acrylate, butyl acrylate, butyl methacrylate, 
hydroxyethyl methacrylate and hydroxypropyl acrylate. 
In a preferred embodiment of the present invention, the water-soluble 
polymer comprises monomer units of 10 to 20% of the unsaturated sulfonic 
acid monomer and from 80 to 90% of one or more of unsaturated 
monocarboxylic acid or dicarboxylic acid monomers. In a more preferred 
embodiment, the water-soluble polymer comprises 10 to 15% of 
2-acrylamido-2-methyl-1-propanesulfonic acid monomer units or salts 
thereof, 15 to 65% of acrylic acid monomer units or salts thereof and 25 
to 70% of maleic acid or maleic anhydride monomer units or salts thereof. 
The polymer compositions useful in the process of the invention, containing 
the selected units in the selected weight ratios, have weight average 
molecular weights (M.sub.w) ranging from about 1,000 to about 20,000, 
preferably from 1,500 to 10,000, and most preferably from 2,000 to 7,000. 
Weight average molecular weights are based on gel permeation 
chromatography (GPC) analysis using known poly(meth)acrylic acid 
standards. 
Water flooding is a commonly used technique in oil recovery operations. 
Water is injected under pressure into the formation water reservoir via 
injection wells; this procedure drives the oil through the mineral 
deposits and rock formations into the production wells. Sea water, readily 
available in offshore operations, and typically used for the injection 
water in the water flooding operation, contains large amounts of dissolved 
salts, such as sulfate. Interaction of the injection water (in the absence 
of effective scale inhibitors) with the formation water in the reservoir 
will produce unwanted inorganic deposits (primarily scale-forming salts of 
calcium sulfate, barium sulfate and strontium sulfate) which ultimately 
block tubing, valves and pumps of the oil recovery process equipment. 
Additional conditions that aggravate the deposition of scale-forming salts 
include low pH, pressure, high temperatures and high concentrations of 
barium, strontium, calcium or iron ions encountered in typical oil 
recovery operations. 
In order to address the scale-formation problem, a "squeeze" process is 
used. Generally, the well is initially preflushed with sea water, then a 
scale inhibitor-containing injection step is performed; this is followed 
by an additional sea water feed (over flush step) to distribute the scale 
inhibitor further into the reservoir to be adsorbed within the mineral 
deposits and rock formations (matrix of the underground petroleum-bearing 
formation). During the squeeze treatment, oil recovery operations are 
curtailed. When oil production operations are resumed, the adsorbed scale 
inhibitor will be slowly released (desorbed or dissolved) from the 
formation matrix and prevent the precipitation of scale-forming salts 
during subsequent oil recovery operations. For oilfields characterized by 
"harsh" conditions (such as high barium levels or low pH), typical time 
periods before additional squeeze treatments are required (squeeze 
lifetime) are 1 to 6 months; desired squeeze lifetimes are 6 to 24 months, 
preferably 12 to 24 months or longer. The harsher the conditions, the 
greater the tendency for metal sulfate scale formation with consequent 
plugging and fouling of the oilfield matrix and oil production equipment. 
An aqueous solution of the scale inhibitor is used in the injection step; 
typically the concentration of scale inhibitor is from 0.5 to 20%, and 
preferably from 2 to 10% by weight of the aqueous solution. When the 
production water from the oilwell begins to show decreased levels of the 
scale inhibitor further squeeze treatments will be required. Generally, 
effective scale inhibition will be maintained at levels of inhibitor above 
about 25 ppm (in the production water or in the formation water). The more 
effective the scale inhibitor, the lower the level can be of scale 
inhibitor in the production water before requiring additional treatment. 
Inhibitors identified for use in the process of the present invention may 
allow the levels to be dropped to 10 to 20 ppm, and more preferably to 5 
to 10 ppm, before additional treatment is required. Use of the 
water-soluble polymers described for use in the process invention allow 
for the lower use levels to be tolerated before repeating the squeeze 
treatment, thus extending the squeeze lifetime beyond that available with 
prior art scale inhibitors. The repeat treatment involves injecting 
additional aqueous solution of the water-soluble polymer into the 
underground petroleum-bearing formations at time intervals selected to 
provide amounts of the water-soluble polymer effective to maintain scale 
inhibition. 
Harsh conditions can be defined in a variety of ways depending upon the 
particular combinations of pH and background cation and anion 
concentrations in the waters being treated with scale inhibitor. In 
general, harsh oilfield conditions refer to waters having a pH from about 
3 to about 7, where the barium, calcium, strontium and sulfate ions are 
present in amounts from 100 to 2000 parts per million (ppm), 300 to 35000 
ppm, 100 to 1000 ppm and 500 to 5000 ppm, respectively, where the amounts 
are ppm by weight of the aqueous fluid. Generally, the harsh oilfield 
conditions will be represented by waters having a pH from about 4 to about 
6, typically of about 5.0 or less, where the barium, calcium, strontium 
and sulfate ions are present in amounts from 300 to 1500 ppm, 1000 to 3000 
ppm, 200 to 500 ppm and 1000 to 3000 ppm, respectively. 
Particularly harsh conditions may be represented by the following examples, 
but are not limited to these particular conditions: 
(a) water having a pH of about 4, with a relatively low barium ion 
concentration of 100-150 ppm and a sulfate ion concentration of about 
1000-1500 ppm. 
(b) water having a pH of about 4, with a relatively high barium ion 
concentration of 500-1000 ppm or more and a relatively low sulfate ion 
concentration of less than about 600 ppm. 
(c) water having a pH of about 5.5, with a relatively high barium ion 
concentration of 500-1000 ppm or more and a sulfate ion concentration of 
greater than 1000 ppm. 
Metal sulfate scale precipitation as a problem in oilfield recovery 
operations is represented by a combination of the different types of metal 
sulfate scale (for example, barium sulfate, calcium sulfate, strontium 
sulfate and NORM scale salts). However, barium sulfate scale represents 
the predominant scale problem in most oilfields and is considered 
representative of the other types of scale in terms of evaluations of 
scale inhibitor systems developed to prevent and minimize scale formation. 
Therefore, laboratory scale inhibition efficiency based on barium sulfate 
inhibition is considered to also address the ability of the scale 
inhibitors to control the other forms of metal sulfate scale. 
Several classes of materials have been used as scale inhibitors for squeeze 
treatments, such as phosphonate compounds, poly(acrylic acid) polymers and 
sulfonated polymers. Each type has been moderately effective at inhibiting 
scale, but no single type satisfies all the desirable characteristics of 
an ideal squeeze treatment scale inhibitor. Three key performance 
properties of a squeeze treatment scale inhibitor are (1) satisfactory 
scale inhibition of sulfate salts of calcium, barium and strontium at low 
use levels of the inhibitor, (2) compatibility with the sea water used in 
the injection step and preferably with the formation water and (3) 
satisfactory adsorption-desorption characteristics within the formation 
matrix that allow slow and homogeneous release into the surrounding water 
at concentrations effective to maintain inhibition of scale formation. 
Commercially available scale inhibitors include: phosphinocarboxylic acid 
polymers based on phosphinate-containing poly(acrylic acid)--mixture of 
dialkyl phosphinate and monoalkyl phosphinate, 
diethylenetriaminepentamethylene-phosphonic acid (DETPMP) as a 
representative phosphonate compound and poly(sodium vinyl sulfonate), or 
P(SVS), as a representative sulfonated polymer. High phosphorus-containing 
scale-inhibitors, such as DETPMP, while generally effective scale 
inhibitors are less desirable in many situations due to the environmental 
problems encountered with their continued use. 
Abbreviations used in the Examples and Tables are listed below with 
corresponding descriptions. 
______________________________________ 
AA Acrylic Acid 
AMPS 2-Acrylamido-2-methyl-1-propanesulfonic Acid 
DETPMP Diethylenetriaminepentamethylenephosphonic acid 
HPOPS 2-Hydroxy-3-(2-propenyloxy)propanesulfonic acid 
MAA Methacrylic Acid 
MALAC Maleic Acid 
SVS Sodium Vinyl Sulfonate 
SSS Sodium Styrene Sulfonate 
______________________________________ 
Table I contains a summary of various types of scale inhibitors. Scale 
inhibitors 1 through 9 are representative of prior art barium sulfate 
scale inhibitors that are used commercially; scale inhibitors 10 through 
18 are representative of polymers useful in the process of the present 
invention. Scale inhibitor 3 is a commercial material (mixture of dialkyl 
and monoalkyl phosphino poly(acrylic acid)), available as Bellasol.TM. S40 
from FMC Corporation. Scale inhibitor 4 is a commercial material, 
available as Dequest.TM.2060 from Monsanto Co. Scale inhibitor 5 is a 
commercial material, available as Scaletreat.TM. 810 obtained from TR Oil 
Services. Scale inhibitor 6 is a commercial material similar to scale 
inhibitor 5. 
TABLE I 
______________________________________ 
Barium Sulfate Scale Inhibitors 
Scale Inhibitor M.sub.w 
______________________________________ 
1 P(AA) 2000 
2 P(AA) 4500 
3 P(AA) 3160 
4 DETPMP 573 
5 P(SVS) 7300 
6 P(SVS) 6680 
7 P(60 AA/40 AMPS) 11000 
8 P(70 AA/30 MAA) 3500 
9 P(MALAC) 1000 
10 P(65 AA/25 MALAC/10 AMPS) 
3500 
11 P(60 AA/30 MALAC/10 AMPS) 
3540 
12 P(50 AA/40 MALAC/10 AMPS) 
6960 
13 P(30 AA/60 MALAC/10 AMPS) 
3970 
14 P(15 AA/70 MALAC/15 AMPS) 
2750 
15 P(30 AA/60 MALAC/10 HPOPS) 
4730 
16 P(40 AA/50 MALAC/10 SVS) 
4710 
17 P(35 AA/60 MALAC/5 SSS) 
5200 
18 P(77 AA/23 AMPS) 4500 
______________________________________ 
These classes of scale inhibitors provide adequate scale inhibition with 
formation waters representing "moderate" conditions, that is, combination 
of a pH of 5.0 to 6.6 with moderate concentrations of calcium, barium and 
strontium ions, as exemplified by "Forties" field water (see Example 2 for 
water compositions). A more stringent evaluation of potential scale 
inhibitors requires determining their performance under harsher conditions 
than those described above for moderate conditions. "Harsh" conditions 
combine a pH below about 5.5 and high levels of barium and sulfate ions in 
the test waters, as exemplified by "Froy" field water (see Example 2 water 
compositions). Test conditions for barium sulfate inhibition (static jar 
test) were: 20/80 and 50/50 synthetic sea water (SSW)/formation water 
("Froy" field water) @95.degree. C./pH 4.2/test duration of 2 and 22 
hours/dosage of 5, 10, 15, 25 ppm scale inhibitor material (active). See 
Examples 3A, 3B and 3C for experimental details. 
TABLE 2 
______________________________________ 
Barium Sulfate Inhibition under Harsh Conditions: 
95.degree. C., pH 4.2, 20/80 SSW/"Froy" Formation Water 
% BaSO.sub.4 inhibition 
(2/22 hours) 
Scale Inhibitor @ 10/15/25 ppm dosage 
______________________________________ 
10 P(65 AA/25 MALAC/10 AMPS) 
33/36 57/59 70/67 
14 P(15 AA/70 MALAC/15 AMPS) 
22/25 44/40 56/53 
3 P(AA) 41/31 54/36 65/34 
5 P(SVS) 30/32 44/44 58/48 
______________________________________ 
TABLE 3 
______________________________________ 
Barium Sulfate Inhibition under Harsh Conditions: 
75.degree. C., pH 4.2, 20/80 SSW/"Froy" Formation Water 
% BaSO.sub.4 inhibition 
(2/22 hours) 
Scale Inhibitor @ 25 ppm dosage 
______________________________________ 
10 P(65 AA/25 MALAC/10 AMPS) 
65/62 
14 P(15 AA/70 MALAC/15 AMPS) 
56/54 
3 P(AA) 66/38 
5 P(SVS) 58/48 
______________________________________ 
TABLE 4 
______________________________________ 
Barium Sulfate Inhibition under Harsh Conditions: 
95.degree. C., pH 4.2, 20/80 SSW/"Froy" Formation Water 
% BaSO.sub.4 inhibition 
(2/22 hours) 
Scale Inhibitor @ 25 ppm dosage 
______________________________________ 
10 P(65 AA/25 MALAC/10 AMPS) 
57/52 
14 P(15 AA/70 MALAC/15 AMPS) 
44/41 
3 P(AA) 55/31 
5 P(SVS) 39/41 
______________________________________ 
TABLE 5 
______________________________________ 
Barium Sulfate Inhibition under Harsh Conditions: 
75.degree. C., pH 4.2, 50/50 SSW/"Froy " Formation Water 
% BaSO.sub.4 inhibition 
(2/22 hours) 
Scale Inhibitor @ 25/50/75 ppm dosage 
______________________________________ 
10 P(65 AA/25 MALAC/10 AMPS) 
14/3 31/5 41/5 
14 P(15 AA/70 MALAC/15 AMPS) 
29/23 52/30 66/32 
3 P(AA) 2/1 2/0 5/0 
5 P(SVS) 23/9 35/9 44/9 
______________________________________ 
TABLE 6 
______________________________________ 
Barium Sulfate Inhibition under Harsh Conditions: 
95.degree. C., pH 4.2, 50/50 SSW/"Froy" Formation Water 
% BaSO.sub.4 inhibition 
(2/22 hours) 
Scale Inhibitor @ 25/50/75 ppm dosage 
______________________________________ 
10 P(65 AA/25 MALAC/10 AMPS) 
18/5 33/8 45/9 
14 P(15 AA/70 MALAC/15 AMPS) 
19/14 41/28 54/30 
3 P(AA) 12/2 20/3 27/5 
5 P(SVS) 15/5 28/7 33/7 
______________________________________ 
TABLE 6A 
______________________________________ 
Barium Sulfate Inhibition under Harsh Conditions: 
90.degree. C., pH 5.5, 50/50 SSW/"Froy" Formation Water 
% BaSO.sub.4 inhibition 
(24 hours) 
Scale Inhibitor @ 300 ppm dosage 
______________________________________ 
15 P(30 AA/60 MALAC/10 HPOPS) 
31 
11 P(60 AA/30 MALAC/10 AMPS) 
58 
6 P(SVS) 46 
______________________________________ 
TABLE 6B 
______________________________________ 
Barium Sulfate Inhibition under Harsh Conditions: 
90.degree. C., pH 4.0, 50/50 SSW/"Forties" Formation Water 
% BaSO.sub.4 inhibition 
(18 hours) 
Scale Inhibitor @ 30 ppm dosage 
______________________________________ 
1 P(AA) 3 
2 P(AA) 17 
13 P(30 AA/60 MALAC/10 AMPS) 
97 
12 P(50 AA/40 MALAC/10 AMPS) 
80 
16 P(40 AA/50 MALAC/10 SVS) 
77 
17 P(35 AA/60 MALAC/5 SSS) 
96 
______________________________________ 
Another aspect of harsh scale inhibition conditions is an evaluation of 
performance under dynamic rather than static conditions, that is, how the 
scale inhibitors perform in preventing blockage of narrow passages due to 
scale deposition, such as would occur in transport lines and tubing. This 
performance characteristic was evaluated via a capillary tube test (see 
Example 3D for description of test and apparatus) at conditions listed in 
Table 7. The better performance under these test condition is represented 
by longer times before plugging. The polymers useful in the process of the 
present invention (10, 14 and 18) provide enhanced scale inhibition under 
these dynamic conditions when compared to other commercially scale 
inhibitors. 
TABLE 7 
______________________________________ 
Barium Sulfate Inhibition under Harsh Conditions: 
Dynamic Capillary Tube Plugging Test @ pressure = 1 bar 
Scale inhibitor dosage = 8 ppm 
90.degree. C., pH 4.0, 50/50 SSW/"PMAC" Formation Water 
Time Before Plugging 
Scale Inhibitor M.sub.w (minutes) 
______________________________________ 
Control (no scale inhibitor) 
-- 60 
9 P(MALAC) 1000 86 
3 P(AA) 3200 120 
4 DETPMP 573 110 
18 P(77 AA/23 AMPS) 
4500 360 
7 P(60 AA/40 AMPS) 
11000 180 
14 P(15 AA/70 MALAC/15 AMPS) 
2750 &gt;480 
10 P(65 AA/25 MALAC/10 AMPS) 
3500 307 
______________________________________ 
Evaluation of adsorption characteristics of the above scale inhibitors was 
conducted in a manner to simulate actual conditions encountered in a 
reservoir. Although actual temperatures may be as high as 120.degree. C. 
in the reservoir, laboratory evaluations used 95.degree. C. for 
operational convenience, with the expectation that adsorption capability 
would be more difficult to achieve at the lower temperature, thus 
amplifying any differences among scale inhibitor candidates. The 
adsorption tests were run under static conditions using stock solutions of 
synthetic sea water containing 2500 ppm of the scale inhibitors, each 
solution adjusted with 10% aqueous HCl or 1N or 10N aqueous NaOH to a pH 
of 3.0, 4.0, 5.0 and 6.0. See Example 4 for experimental conditions. 
Test results are presented in Table 8. As shown in the Table, polymers used 
in the process of the present invention (10 and 14) provide significantly 
enhanced adsorption potential when compared to the commercial poly(SVS) 
scale inhibitor (5). 
TABLE 8 
______________________________________ 
Scale Inhibitor Static Adsorption 
(milligrams adsorbed/gram of rocks) 
Adsorption (mg/g) 
Scale Inhibitor @ pH = 3.0/4.0/5.0/6.0 
______________________________________ 
10 P(65 AA/25 MALAC/10 AMPS) 
2.2 2.2 2.8 2.6 
14 P(15 AA/70 MALAC/15 AMPS) 
4.0 4.0 4.4 4.2 
3 P(AA) 2.4 2.2 2.2 2.2 
5 P(SVS) 0.4 1.0 0.6 0.3 
______________________________________ 
Evaluation of compatibility characteristics of scale inhibitors with 
delivery water (synthetic sea water) indicated that the 
phosphinate-containing poly(acrylic acid) inhibitor, the P(SVS) inhibitor 
and the water-soluble polymers useful in the process of the present 
invention would all perform very similarly regarding compatibility, that 
is, these classes of scale inhibitors would all have satisfactory 
compatibility with typical delivery waters used in the injection step 
("squeeze" process). Compatibility test conditions typically involved 
preparing the test solutions (containing 0.1 to 10% by weight of scale 
inhibitor in the sea water adjusted to pH 3.8) in thick walled glass 
bottles and raising the temperature from ambient temperature to 
100.degree. C. by heated forced air; the temperature at which 
precipitation occurred was then noted. 
Tables 2 through 7 illustrate various "harsh" condition environments and 
the relative performance of the water-soluble polymers useful in the 
present invention. In some cases, the performance of the scale inhibitors 
of the prior art and those of the present invention are similar; however, 
in many cases the more severe conditions indicate the greater degree of 
scale inhibition efficiency obtained with the polymers of the present 
invention. In particular, Tables 5 and 6 illustrate the advantage of the 
present invention over the use of P(AA) materials, especially at extended 
time periods. When the adsorption characteristics of the polymers of the 
present invention (Table 8) are combined with their scale inhibiting 
properties, there is a clear advantage in expected long term performance, 
such as extended squeeze lifetimes, over prior art scale inhibitors 
represented by the poly(sodium vinylsulfonate) type (scale inhibitors 5 
and 6). 
While not wishing to be bound by theory, we believe that the efficacy of 
the water-soluble polymers useful in the process of the present invention 
is due to contributions from each of the functional group types present in 
the polymer. Sulfonic acid units are believed to enhance compatibility of 
the scale inhibitor with seawater due to the high ionization constant of 
the sulfonic acid group; the sulfonic acid group has little affinity for 
metal ions and provides high water solubility. Carboxylic acid units 
contributed by the unsaturated carboxylic acid monomers provide enhanced 
adsorption of the scale inhibitor due to the high affinity of the carboxyl 
group for metal ions (such as those found in the mineral surfaces of oil 
reservoir formations). This last feature also contributes to the scale 
inhibition effectiveness of the water-soluble polymer via attachment to 
metal ions. We also believe that the balance between different types of 
carboxylic acid functional groups (such as acrylic acid and maleic acid 
type) provides the required combination of scale inhibitor adsorption 
(distribution within the formation water matrix) and desorption (release 
to operate over extended periods of time) properties.

Some embodiments of the invention are described in detail in the following 
Examples. All ratios, parts and percentages (%) are expressed by weight 
unless otherwise specified, and all reagents used are of good commercial 
quality unless otherwise specified. 
EXAMPLE 1 
Synthesis of Polymer Compositions 
The polymers useful in the present invention can be made by methods of 
polymerization well known to those skilled in the art. They can be 
prepared by aqueous polymerization, solvent polymerization or bulk 
polymerization. Preferably they are prepared by aqueous polymerization. 
The polymerizations can be conducted as batch, cofeed, heel, 
semi-continuous or continuous processes. Preferably the polymerization is 
conducted as a cofeed or continuous process. 
When the polymers are prepared by a cofeed process, the initiator and 
monomers are generally introduced into the reaction mixture as separate 
streams which are fed linearly, i.e., at constant rates. The streams may 
be staggered so that one or more of the streams are completely fed before 
the others. Also, a portion of the monomers or initiators may be added to 
the reactor before the feeds are begun. The monomers may be fed into the 
reaction mixture as individual streams or combined into one or more 
streams. 
The initiators suitable for making the polymers of the present invention 
are any of the conventional water-soluble free-radical initiators and 
redox couples. Suitable free-radical initiators include, for example, 
peroxides, persulfates, peresters and azo initiators. Mixed initiator 
systems (redox couple) can also be used, such as combination of a free 
radical initiator with a reducing agent. Suitable reducing agents include, 
for example, sodium bisulfite, sodium sulfite, hypophosphite, isoascorbic 
acid and sodium formaldehyde-sulfoxylate. The level of initiator is 
generally 0.1 to 20% based on the total weight of polymerizable monomers. 
Preferably the initiator is present at a level from 1 to 15% and most 
preferably from 2 to 10% based on the total weight of polymerizable 
monomer. 
In addition to the initiator, one or more promoters may also be used. 
Suitable promoters include water-soluble salts of metal ions. Suitable 
metal ions include iron, copper, cobalt, manganese, vanadium and nickel. 
Preferably the promoters are water-soluble salts of iron or copper. When 
used, the promoters are present at levels from about 1 to about 100 ppm 
based on the total amount of polymerizable monomer. Preferably the 
promoters are present at levels from about 3 to about 20 ppm based on the 
total polymerizable monomers. 
It is generally desirable to control the pH of the polymerizing monomer 
mixture, especially when using thermal initiators such as persulfate 
salts. The pH of the polymerizing monomer mixture can be controlled by a 
buffer system or by the addition of a suitable acid or base; the pH of the 
system is maintained from about 3 to about 8, and preferably from about 4 
to about 6.5. Similarly, when redox couples are used there will be an 
optimum pH range in which to conduct the polymerization depending on the 
choice of the components of the redox couple. The pH of the system can be 
adjusted to suit the choice of the redox couple by the addition of an 
effective amount of a suitable acid or base. 
When the polymerization is conducted as a solution polymerization using a 
solvent other than water, the reaction should be conducted at up to about 
70%, preferably from 40 to 60%, by weight of polymerizable monomers based 
on the total reaction mixture. Similarly, when the polymerization is 
conducted as an aqueous polymerization, the reaction should be conducted 
at up to about 70%, preferably from 40 to 60%, by weight of polymerizable 
monomers based on the total reaction mixture. In general it is preferred 
to conduct the polymerizations as aqueous polymerizations. The solvents or 
water, if used, can be introduced into the reaction vessel as a heel 
charge, or can be fed into the reactor either as a separate feed stream or 
as a diluent for one of the other components being fed into the reactor. 
The temperature of the polymerization reaction will depend on the choice of 
initiator, solvent and target molecular weight. Generally the temperature 
of the polymerization is up to the boiling point of the system although 
the polymerization can be conducted under pressure if higher temperatures 
are used. Preferably the temperature of the polymerization is from about 
50.degree. to about 95.degree. C. and most preferably from 60.degree. to 
80.degree. C. 
Chain regulators or chain transfer agents may be employed to assist in 
controlling the molecular weight of the polymers. Any conventional 
water-soluble chain regulator or chain transfer agent can be used. 
Suitable chain regulators include, for example, mercaptans, 
hypophosphites, phosphites, isoascorbic acid, alcohols, aldehydes, 
hydrosulfites and bisulfites. If a chain regulator or chain transfer agent 
is used, preferred mercaptans are 2-mercaptoethanol and 
3-mercaptopropionic acid; a preferred bisulfite is sodium metabisulfite; a 
preferred phosphite is sodium phosphite. 
EXAMPLE 2 
Water Compositions 
Test solutions and makeup waters were prepared by dissolving the 
appropriate metal salts in deionized water and filtering through 0.45 
micron pore size filters prior to use. Final component concentrations of 
the various "waters" are indicated below in Table 9. Synthetic Sea Water 
is meant to correspond to North Sea Brine; four variations of Synthetic 
Sea Water were used. Their use is noted at appropriate locations in 
Example 3. Synthetic "Forties," "Froy" and "Miller." Formation Waters are 
meant to simulate brines from the Forties and Miller Formations of the 
North Sea. The "PMAC" Formation Water is used in Example 3D. 
TABLE 9 
__________________________________________________________________________ 
Water Compositions 
(amounts in ppm (milligrams/liter) based on volume of solution) 
Component 
SSW-1 
SSW-2 
SSW-3 
SSW-4 
"Forties" 
"Froy" 
"Miller" 
"PMAC" 
__________________________________________________________________________ 
Sodium 10890 
10890 
10890 
11035 
29371 36000 
36500 
16100 
Potassium 
462 460 460 397 372 2500 2510 246 
Magnesium 
1368 1368 1368 1330 504 200 212 132 
Calcium 
428 428 428 418 2811 2100 2110 504 
Strontium 
8 -- 8 -- 573 450 453 180 
Barium -- -- -- -- 252 1000 1070 200 
Chloride 
19700 
19766 
19700 
19841 
52369 65000 
65300 
26800 
Sulfate 
2960 2960 2700 2769 11 -- -- -- 
Bicarbonate 
124 -- 124 146 498 -- -- 512 
Acetate 
-- -- -- -- -- -- -- 460 
__________________________________________________________________________ 
Components are listed as the ionic form. 
Synthetic Sea Water designated as SSW 
Formation Water designated as "Forties," "Froy," "Miller," "PMAC 
EXAMPLE 3A 
Test Method for Barium Sulfate Inhibition "Miller" Formation Water 
The polymers prepared by the process of the present invention were tested 
for their ability to inhibit barium sulfate scale formation. The test 
method for measuring inhibition of barium sulfate consisted of the 
following steps: (1) preparation of test solutions containing the polymer 
to be tested, (2) incubation of the test solutions and (3) measurement of 
the amount of barium which did not precipitate in the test solutions. 
Accordingly, in comparing two test solutions, the test solution having the 
higher percent barium sulfate inhibition contains a scale inhibitor which 
is more effective in inhibiting metal sulfate scale formation. 
The test solutions were prepared from a barium-containing solution, a 
sulfate-containing solution, a buffer solution, and an inhibitor solution 
containing the polymer to be tested; the concentration of polymer in the 
inhibitor solution was expressed as grams of polymer in the free acid (H) 
form. The composition of the barium- and sulfate-containing solutions is 
shown in Table 10. 
TABLE 10 
______________________________________ 
Composition of Barium- and Sulfate-Containing Solutions 
Barium-Containing Solution 
Sulfate-Containing Solution 
Component grams/liter Component grams/liter 
______________________________________ 
NaCl 59.574 NaCl 59.574 
KCl 5.663 Na.sub.2 SO.sub.4 
3.993 
CaCl.sub.2.2H.sub.2 O 
9.310 NaHCO.sub.3 0.171 
MgCl.sub.2.6H.sub.2 O 
13.209 Deionized water 
balance 
BaCl.sub.2.2H.sub.2 O 
1.903 
SrCl.sub.2.6H.sub.2 O 
1.402 
Deionized water 
balance 
______________________________________ 
Table 9 gives the compositions of formation water "Miller" and sea water 
(SSW-3) that are simulated by the barium- and sulfate-containing solutions 
listed in Table 10. Rather than make up a sea water and a formation water 
having the compositions listed in Table 9, two waters were made as in 
Table 10 with potassium and divalent cations in the barium-containing 
solution and sulfate and bicarbonate in the sulfate-containing solution. 
The sodium chloride was equally distributed between the two solutions. 
When the barium- and sulfate-containing solutions of Table 10 were mixed 
in a 50/50 ratio, the resulting mixture had the same ionic composition as 
if SSW-3 and "Miller" formation water from Table 9 were mixed in a 50/50 
ratio. 
The barium- and sulfate-containing solutions of Table 10 were filtered 
through a 0.45 micron filter. The barium containing solution was adjusted 
to pH 4.2 with dilute HCl, and the sulfate-containing solution was 
adjusted to pH 6.0 with dilute HCl. 
Compositions of the buffer and inhibitor solutions were as follows: 
______________________________________ 
Component Concentration 
______________________________________ 
Buffer Solution 
CH.sub.3 COONa.3H2O 
22.78 g/100 ml solution 
CH.sub.3 COOH 0.574 g/100 ml solution 
Deionized water Balance 
Inhibitor Solution 
Scale inhibitor to be tested 
10 g/liter 
Deionized water Balance 
______________________________________ 
The inhibitor solution was adjusted to a pH of 6.0 with dilute HCl or 
dilute NaOH. 
The test solutions containing a polymer to be tested, hereinafter called 
the "inhibitor test solution," were prepared by combining 2 ml of the 
buffer solution, 50 ml of the sulfate-containing solution, 3.15 ml of 
inhibitor solution, and 50 ml of the barium-containing solution. 
As controls, a "no inhibitor" test solution, a sulfate test solution and a 
barium test solution were prepared. The "no inhibitor" test solution was 
prepared by combining 2 ml of the buffer solution, 50 ml of the 
sulfate-containing solution, 50 ml of the barium-containing solution, and 
3.15 ml of deionized water. The sulfate test solution was prepared by 
combining 2 ml of the buffer solution, 100 ml of the sulfate-containing 
solution, and 3.15 ml of deionized water. The barium test solution was 
prepared by combining 2 ml of the buffer solution, 100 ml of the barium 
containing solution, and 3.15 ml of deionized water. 
The inhibitor, no inhibitor, sulfate, and barium test solutions were placed 
in a water bath at 90.degree. C. and gently shaken for 24 hours. After the 
24 hour incubation period, the test solutions were removed one at a time 
from the water bath and a diluted test solution was prepared from each 
test solution for analyzing barium content. The diluted test solution was 
prepared by adding to a 100 ml flask the following ingredients in the 
order listed: 
(1) 50 ml of EDTA solution 
(2) 1-2 ml of supernatant taken from the incubated test solution 
(3) EDTA solution (balance to make 100 ml) 
The EDTA solution consisted of 6.00 g of KCl, 72.8 g of K.sub.2 
EDTA.multidot.2H.sub.2 O, and 1800 g of deionized water. The pH of the 
solution was adjusted to 12 with KOH pellets, and then sufficient 
deionized water was added to make the total solution weight equal to 2000 
g. 
The diluted test solutions were measured for barium using direct current 
plasma on a Spectra Span 7 DCP Spectrometer manufactured by Applied 
Research Laboratories Fisons located in Valencia, Calif. The concentration 
of the barium in the undiluted test solutions was calculated from the 
measured values of barium. The percent barium sulfate inhibition was 
obtained from the following formula: 
##EQU1## 
where: 
Ba Inhibitor=concentration of barium in inhibitor solution 
Ba No Inhibitor=concentration of barium in no inhibitor solution 
Ba Barium=concentration of barium in barium test solution 
Ba Sulfate=concentration of barium in sulfate test solution 
EXAMPLE 3B 
Test Method for Barium Sulfate Inhibition "Forties" Formation Water 
The procedure used was the same as that for the "Miller" formation water 
with the following exceptions: 
TABLE 11 
______________________________________ 
Composition of Barium- and Sulfate-Containing Solutions 
Barium-Containing Solution 
Sulfate-Containing Solution 
Component grams/liter Component grams/liter 
______________________________________ 
NaCl 74.17 NaCl 23.955 
KCl 0.71 KCl 0.88 
CaCl.sub.2.2H.sub.2 O 
10.31 CaCl.sub.2.2H.sub.2 O 
1.57 
MgCl.sub.2.6H.sub.2 O 
4.215 MgCl.sub.2.6H.sub.2 O 
11.44 
BaCl.sub.2.2H.sub.2 O 
0.448 SrCl.sub.2.6H.sub.2 O 
0.0243 
SrCl.sub.2.6H.sub.2 O 
1.745 Na.sub.2 SO.sub.4 
4.375 
Na.sub.2 SO.sub.4 
0.017 NaHCO.sub.3 0.17 
NaHCO.sub.3 
0.685 Deionized water 
balance 
Deionized water 
balance 
______________________________________ 
Table 9 gives the compositions of formation water ("Forties") and sea water 
(SSW-1) that are duplicated by the barium- and sulfate-containing 
solutions listed above. 
Carbon dioxide was bubbled for two hours through the barium- and 
sulfate-containing solutions, the solutions were filtered through a 0.45 
micron filter, then each was adjusted to pH 4.0 with 15% HCl. 
No buffer was used. Compositions of inhibitor solutions were as follows: 
______________________________________ 
Inhibitor Solution 
Component Concentration 
______________________________________ 
Scale inhibitor to be tested 
1 g/liter 
Deionized water Balance 
______________________________________ 
The inhibitor solution was adjusted to a pH of 5.5 with dilute HCl or 
dilute NaOH. 
The inhibitor test solutions were prepared by combining 50 ml of the 
sulfate-containing solution, 3 ml of inhibitor solution, and 50 ml of the 
barium-containing solution. 
A no inhibitor test solution was prepared by combining 50 ml of the 
sulfate-containing solution, 3 ml of deionized water, and 50 ml of the 
barium-containing solution. A barium test solution was prepared by 
combining 50 ml of the barium-containing solution and 53 ml of deionized 
water. 
The test solutions were placed in a water bath at 90.degree. C. and gently 
shaken for 24 hours. After the 24 hour incubation period, the test 
solutions were removed one at a time from the water bath and a diluted 
test solution was prepared from each test solution for analyzing barium 
content. The diluted test solution was prepared by adding 10 ml of 
supernatant from the incubated test solution to a 100 ml flask. The 
balance of the 100 ml was made up with deionized water. 
The diluted test solutions were measured for barium using inductively 
coupled plasma. The concentration of barium in the undiluted test 
solutions was calculated from the measured values of barium. The percent 
barium sulfate inhibition was obtained from the following formula: 
##EQU2## 
EXAMPLE 3C 
Test Method for Barium Sulfate Inhibition "Froy" Formation Water 
The procedure used follows the same general principles as that for the 
"Miller" formation water test. The details of the "Froy" formation water 
tests are given below: 
TABLE 12 
______________________________________ 
Composition of Barium- and Sulfate-Containing Solutions 
Barium-Containing Solution 
Sulfate-Containing Solution 
Component grams/liter Component grams/liter 
______________________________________ 
NaCl 91.511 NaCl 24.074 
KCl 4.766 KCl 0.877 
CaCl.sub.2.2H.sub.2 O 
7.703 CaCl.sub.2.2H.sub.2 O 
1.570 
MgCl.sub.2.6H.sub.2 O 
1.672 MgCl.sub.2.6H.sub.2 O 
11.436 
BaCl.sub.2.2H.sub.2 O 
1.779 Na.sub.2 SO.sub.4 
4.376 
SrCl.sub.2.6H.sub.2 O 
1.369 Deionized water 
balance 
Deionized water 
balance 
______________________________________ 
Table 9 gives the compositions of formation water ("Froy") and sea water 
(SSW-2) that are duplicated by the barium- and sulfate-containing 
solutions listed above. 
The concentration of polymer in the inhibitor solution was expressed as 
grams of polymer in the free acid (H) form. Compositions of inhibitor 
solutions and the buffer solution were as follows: 
______________________________________ 
Buffer Solution 
Component Concentration 
______________________________________ 
CH.sub.3 COONa.3H.sub.2 O 
13.60 g/100 ml solution 
CH.sub.3 COOH 6.00 g/100 ml solution 
Deionized water Balance 
ph 4.2-4.3 
______________________________________ 
The inhibitor solution is then diluted further into the sulfate-containing 
solution in order to give the required concentration for the particular 
test. The concentration of inhibitor in the sulfate-containing solution 
must be higher than that required for the test by a factor which accounts 
for the dilution when mixed with the barium-containing solution. 
The barium-containing solution and the inhibitor/sulfate-containing 
solution were filtered separately through a 0.45 micron filter, collecting 
in separate containers a sufficient volume of each to equal a total of 200 
ml on mixing the two.* 2 ml of buffer solution was then added to the 
inhibitor/sulfate-containing solution. Both solutions were then placed 
into a water bath at the test temperature (75.degree. C. or 95.degree. C.) 
for 60 minutes. 
FNT *For a 50/50 sea water/formation water ratio, 100 ml of 
inhibitor/sulfate-containing solution and 100 ml of barium-containing 
solution were collected. For a 20/80 sea water/formation water ratio, 40 
ml of inhibitor/sulfate-containing solution and 160 ml of 
barium-containing solution were collected. 
After 60 minutes at the test temperature, the two solutions were mixed by 
pouring the barium-containing solution into the 
buffer/inhibitor/sulfate-containing solution and shaking. The inhibitor 
test solution (approx. 200 ml) was returned to the water bath for 2 or 22 
hours. 
A no inhibitor test solution was prepared as above by using a 
buffer/sulfate-containing solution in place of the 
buffer/inhibitor/sulfate-containing solution. A barium test solution was 
prepared as above by using a buffer/deionized water solution in place of 
the buffer/inhibitor/sulfate-containing solution. 
After the 2 or 22 hour incubation period, the test solutions were removed 
one at a time from the water bath and a diluted test solution was prepared 
from each test solution for analyzing barium content. The diluted test 
solution was prepared by adding 1 ml of supernatant from the incubated 
test solution to 19 ml of stabilization solution. The stabilization 
solution contains 1000 ppm commercial phosphino polycarboxylic acid 
inhibitor and 3000 ppm KCl in deionized water, adjusted to pH &gt;8 with 10N 
NaOH. 
The diluted test solutions were measured for barium using inductively 
coupled plasma. The concentration of barium in the undiluted test 
solutions was calculated from the measured values of barium. The percent 
barium sulfate inhibition was obtained from the following formula: 
##EQU3## 
where: 
Ba Inhibitor=concentration of barium in inhibitor test solution 
Ba No Inhibitor=concentration of barium in no inhibitor test solution 
Ba Barium=concentration of barium in barium test solution 
EXAMPLE 3D 
Test Method for Dynamic Capillary Tube Plugging/Scale Inhibition 
The tube plugging evaluation was carried out using a PMAC Pressure 
Measurement and Control Unit (with adaptor kit for use with barium scale 
salts), manufactured by S.B. Systems of Aberdeen, Scotland, UK. The 
apparatus measures the change in pressure across a coil using a ceramic 
pressure sensor inside the apparatus. The resultant signal is amplified 
for conversion to a display curve on an external recorder. Experimental 
conditions include the following: 
1. Stainless steel capillary: 500 mm length, 1.6 mm ID, 3.2 mm OD 
2. Total flowrate: 1000 ml/h (linear speed: 0.138 meters/second) 
3. 50/50 sea water/formation water 
4. pH:4.0 
5. Temperature: 90.degree. C. 
6. Pressure:1 bar 
TABLE 13 
______________________________________ 
Composition of Barium- and Sulfate-Containing Solutions 
Barium-Containing Solution 
Sulfate-Containing Solution 
Component grams/liter 
Component grams/liter 
______________________________________ 
NaCl 40.64 NaCl 24.52 
KCl 0.469 KCl 0.757 
CaCl.sub.2.2H.sub.2 O 
1.849 CaCl.sub.2.2H.sub.2 O 
1.534 
MgCl.sub.2.6H.sub.2 O 
1.104 MgCl.sub.2.6H.sub.2 O 
11.12 
BaCl.sub.2.2H.sub.2 O 
0.356 Na.sub.2 SO.sub.4 
4.094 
SrCl.sub.2.6H.sub.2 O 
0.548 NaHCO.sub.3 0.201 
CH.sub.3 COOHNa.3H.sub.2 O 
1.060 Deionized water 
balance 
NaHCO.sub.3 
0.705 
Deionized water 
balance 
______________________________________ 
Table 9 gives the compositions of formation water ("PMAC") and sea water 
(SSW-4) that are duplicated by the barium- and sulfate-containing 
solutions listed above. 
All salts except the NaHCO.sub.3 were added to the two solutions listed 
above and the flasks were filled almost to the mark with deionized water. 
The solutions were then sparged with CO.sub.2 for 30 minutes, after which 
the NaHCO.sub.3 was added to each solution and the flasks filled to the 
mark with deionized water. Each solution was then filtered through a 0.45 
micron filter and adjusted to pH 4.0 with dilute HCl. 
The concentration of polymer in the inhibitor solution was expressed as 
grams of polymer in the free acid (H) form. Compositions of inhibitor 
solutions were as follows: 
______________________________________ 
Inhibitor Solution 
Component Concentration 
______________________________________ 
Scale inhibitor to be tested 
1 g/liter 
Sulfate-containing solution 
Balance 
______________________________________ 
The inhibitor solution was adjusted to a pH of 4.0 with dilute HCl or 
dilute NaOH. 
Following standard P.circle-solid.MAC procedures, the barium- and 
sulfate-containing solutions were fed continuously at a 50/50 ratio, and 
the inhibitor was fed at a rate to maintain a dosage of 8 ppm. The 
experiment was continued until plugging occurred. 
EXAMPLE 4 
Test Method for Static Adsorption Properties 
Test conditions involved adding 10 grams of crushed rock (Tarbet formation 
sandstone) to a 50 milliliter (ml) plastic bottle, followed by the 
addition of 20 ml of the test solution (containing the scale inhibitor) 
and shaking the bottle to homogenize the contents. The test bottles were 
placed in an oven at 95.degree. C. for 24 hours, afterwhich the contents 
of the bottles were filtered through a 0.22 micron pore size filter at the 
test temperature (95.degree. C.). The crushed rock was prepared as 
follows: Tarbet formation core material (sandstone), originating from the 
Brent sequence of the North Sea, was solvent cleaned in toluene and then 
with a methanol/chloroform mixture (48 hours each). The cleaned sandstone 
was then dried and crushed to particles of less than 600 microns, with 
care taken not to crush individual grains.