Scale Inhibitors For A CO2 Flood
Fact Book
Kent Bowker
Selection and Application of BaS04
Scale Inhibitors for a CO 2 Flood,
Rangely Weber Sand Unit, Colorado
P.J. Shuler, SPE, Chevron Oil Field Research Co., and E.A. Freitas and K.A. Bowker, Chevron U.S.A. Inc.
Summary. The objective of this study was to develop a cost-effective scale-control program for the Rangely field CO 2 project. The
primary challenge was to identify scale inhibitors to control an existing barium sulfate (BaS04) problem at the new, low-pH conditions
caused by CO 2 injection. A secondary concern was the change in produced-water composition and increased calcium carbonate (CaC0 3 )
scaling tendency caused by the dissolution of carbonate minerals in the reservoir rock by the low-pH CO 2 injection water.
Laboratory evaluation identified several polymer-based and phosphonate scale inhibitors for the low pH (estimated 4.5) at CO 2 production wells and near-neutral pH conditions in the surface facilities. Field tests show a good correlation to laboratory results. Suitable
phosphonate products are preferred to polymer inhibitors because their residual concentrations may be determined accurately, they
are generally cheaper, and they have a longer squeeze treatment life.
Introduction
The Rangely Weber Sand Unit (RWSU), located in northwestern
Colorado, covers 19,000 acres and has a cumulative oil production
exceeding 720 million bbl. The California Co. (now Chevron
U.S.A. Inc.) discovered the Weber reservoir in 1933 but did not
begin development until 1944. The field was completely developed
on 40-acre spacing by 1949. A secondary recovery waterflood program began in 1958 following unitization.
BaS04 and CaC0 3 scale began to appear in the production wells
as the waterflood matured. The onset of BaS04 scale is related to
the decrease in sulfate ion concentration caused by dilution through
injection of fresher water. Sulfate-reducing bacteria further reduced
sulfate concentrations. Sulfate levels in field water fell from more
than 1,200 mg/L in the original formation water to an average of
350 mg/L and as low as 50 mg/L in some producers. The lower
sulfate ion concentration in the reservoir water released barium to
re-establish the barite solubility product. At problem producers,
water from sands with high barium concentrations mixes with water
from sands with higher sulfate concentrations so that the BaS04
solubility is exceeded and scale is formed. Pressure changes and
fluid agitation accelerate BaS04 and CaC0 3 precipitation.
The RWSU has controlled the BaS04 scale problem successfully
during the waterflood with phosphonate and phosphate ester scale
inhibitors. Scale inhibitors were applied in problem producers by
flush treatments, continuous injection through capillary tubing, 1
downhole chemical-injection pumps,2 and squeeze treatments.
A tertiary CO 2 water-alternating-gas flood began in Oct. 1986
in about one-fourth of the field (Fig. 1). Total field production exceeds 500,000 BWPD and 36,000 BOPD, with about 25% of the
oil attributed to the injection of 100 MMcflD of CO 2 ,
The inception of the CO 2 project necessitated a review of the
selection and application of all scale inhibitors. The primary concern
was that the existing BaS04 scale problem would no longer be controlled in the CO 2 area. The literature reports that, as CO 2 injection decreases the pH of the reservoir brine, the effectiveness of
the phosphonate-type inhibitors used in the Rangely waterflood
decreases. 3-5
A secondary concern was the effect that the injected CO 2 might
have on the chemical composition of the produced water. The literature reports that CO 2 flooding can dissolve carbonate minerals
in reservoir rock and thereby increase the concentration of calcium,
magnesium, iron, and bicarbonate in the produced water. 6-8 This
increases the scaling tendency of CaC0 3 and can alter the pH. This
fluid/rock interaction was expected in the Weber sandstone, which
contains several percent of calcite and ferroan dolomite cements. 9
The objective was to develop a cost-effective scale-control program for the CO 2 project. The ideal inhibitor will prevent BaS04
not only under low pH conditions, but also at neutral pH. This is
necessary because scale inhibitor treatments are often performed
Copyright 1991 Society of Petroleum Engineers
before CO 2 breakthrough and because reservoir heterogeneity
could cause the coproduction oflow- and neutral-pH brine. Another
requirement is the continued inhibition of CaC0 3 scale throughout
the producing system. Production of low-pH brine delays calcite
deposition downhole, but this scale has become a greater problem
on the surface where the CO 2 gas exsolves and the pH increases.
This paper addresses the following topics: field sampling to determine the produced-water composition before and after CO 2 injection; auxiliary laboratory tests to confirm that CO 2 injection
dissolves carbonate minerals; laboratory tests to screen candidate
scale inhibitors for the new water composition and pH found in
the CO 2 project; field testing of the most promising inhibitors; and
optimization of the scale-inhibitor squeeze treatments.
Changes in Produced-Water Chemistry
From CO 2 Injection
This section reviews laboratory and field studies to determine the
effect of CO 2 injection on the produced-water chemistry and its
alteration of the Weber sandstone. This work is presented in more
detail elsewhere. 9
pH Reduction. The pH of a brine decreases with increasing CO 2
partial pressure. Fig. 2 shows this trend for a Rangely brine (from
the Main Water Plant sampled pre-C0 2 flood). As expected, each
lO-fold increase in the CO 2 partial pressure causes a decrease of
one pH unit. 10 The calculated pH (determined with the OLI System ProChem® water chemistry software) matches these data
well.1l Extrapolating the results of Fig. 2 to 3,000 psig, typical
Rangely injection well pressure, predicts a pH as low as 3.5. This
condition is expected because the CO 2 mixes with the formation
water near the injection wellbore. The CO 2 and brine are injected
alternately at the injectors. This pH is estimated to increase to about
4.5 by the time the brine reaches the production wells because of
a decrease in pressure and an increase in bicarbonate concentration.
Produced-Water Analysis in CO 2 Area. The water composition
remained fairly constant in the CO 2 project area as the waterflood
matured in the 1980's. After oil/water separation, produced brine
was recycled for injection; very little river water was used as
makeup. The injection brine fell to about one-third the total salinity
of the original formation brine (33,000 vs. > 100,000 ppm total
dissolved solids) owing to the gradual addition of fresher water during the early stages of the waterflood.
Water composition was studied in detail in 20 production wells
in the CO 2 project to monitor changes caused by this tertiary
recovery process (Fig. 1, Table 1). The most obvious differences
(besides lowering of pH from CO 2 injection) are the increases in
calcium, magnesium, iron, and bicarbonate concentrations.
Others 12, 13 have reported an increase in bicarbonate concentration
SPE Production Engineering, August 1991
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259
Page 1 of 6
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6
•
5
pH 4
Rangely Brine Pre-C02 Flood
3
N
R 103W
R 102W
R 101 W
-
I
Ionic Strength 0.49 M
HC03 - = 250 ppm
Temperature = 160°F
2
10
CaC0 3 +C0 2 + H 2 0 ...... Ca ++ +2HC0 3- .
. ...........
[Ca,Mg]C0 3 +C0 2 +H 2 0 ...... rCa ++ ,Mg++]+2HC0 3-
(1)
.
..................................... (2)
Calcite and ferroan dolomite, the predominant carbonate minerals
in the Weber sandstone, commonly make up several percent of the
reservoir rock (Table 2).
Laboratory Study of C0 2 /Brine/Rock Interactions. Laboratory
coreflood experiments were performed to investigate the interaction
of injected carbonated water with Weber Sandstone under controlled
conditions. Two types of experiments were conducted (Table 3).
The first had a large throughput of carbonated brine at a high rate
to model conditions near the injector wellbore. The second experiment had a small volume of C0 2 /brine injected at a slow rate to
model conditions in the bulk of the reservoir. Effluent water samples
were collected to measure changes in the water composition before,
during, and after carbonated-water injection through Rangely core
material. In addition, core samples were examined before and after the CO 2 flood by petrologic analysis and scanning electron
microscope (SEM) photography to determine changes in mineralogy
and texture.
Consistent with the field results, both types of experiments showed
a sharp increase in the concentration of calcium, magnesium, iron,
and bicarbonate with CO 2 breakthrough. Fig. 3 shows an increase
500
1,000
Fig. 2-pH vs. CO 2 pressure for Rangely brine.
of these species at CO 2 breakthrough for the low-volume, lowrate, long-coreflood experiment.
SEM examination of post-COr flooded core material gives further evidence that the injected carbonated brine dissolves calcite
and ferroan dolomite. Fig. 4a shows a typical nonflooded sample
(taken from the same depth as core used in high-volume flood) where
whole ferroan dolomite rhombs exist. SEM photographs of postCOrflood core material show progressive leaching of dolomite.
Dissolution ranged from etching cleavage planes, to leaving a honeycombed structure (Fig. 4b), to complete dissolution. This suggests
that clay adhering to the dolomite can be mobilized and can plug
pore throats. No net change in permeability was observed during
the experiment; perhaps the increased permeability (porosity) by
carbonate cement dissolution offsets any decrease caused by clay
migration. SEM examination of three individual cores from the lowvolume coreflood experiment shows less dissolution than in the highvolume test.
Implications for Scale-Inhibitor Selection. The changes in the
produced-water chemistry caused by carbonate mineral dissolution
affect the selection of scale inhibitors in two ways.
1. Higher bicarbonate concentration increases the pH. The calculated pH of the produced water is close to 4.5 vs. 3.5 for unbuffered injection water. Reduced pressure also contributes to the
greater pH at production wells. Laboratory data presented in the
next section show that it is much easier to inhibit barium sulfate
at a pH of 4.5 than at 3.5.
2. Higher calcium concentration and increased dissolved bicarbonate level increase the CaC0 3 scaling tendency.
TABLE 2-MINERAL DISTRIBUTION IN
RANGELY FIELD PRODUCING SANDSTONES
TABLE 1-RANGELY WATER ANAL YSESPRE- VS. POST-CO 2 FLOOD
Concentration (mg/L)
Post-C0 2 Flood
Pre-CO 2 Flood
Standard
Standard
Ion
Wells Average Deviation Average Deviation
-11,650
1,092
792
Na
20 11,220
148
1,036
150
Ca
20
868
32.9
Mg
157
25.7
201
20
6.8
2.7
Fe
0.74
0.58
5
25.6
245
45.2
270
K
20
21.3
25.2
19.4
26.5
Ba
13
40.7
20.5
110.6
Sr
20
91.6
1,247
1,638
20,090
CI
20 19,460
1,250
548
311
399
HC0 3
20
233
19
250
190
248
S04
Br
95.5
24.9
128
30.2
20
6.5 to 7
Wellhead pH
7 to 7.5
Mineral
Quartz
Dolomite'
Calcite' ,
K-feldspar
Detrital mica and others
Kaolinite
Mixed-layer clay
Smectite
Chlorite
Solids
(%)
75 to 95
o to 15
o to 15
5 to 20
o to 5
Trace
o to 5
o to 5
o to 5
• About 30% is ferroan dolomite.
.. About 5% is ferroan calcite.
SPE Production Engineering, August 1991
260
Bluescape
100
CO 2 Pressure (psi)
Fig. 1-Rangely field map, showing 20 wells in water-sampling
program. Material from Wells Fee 40 and Lacy 12Y used in
coreflood experiments.
for other CO 2 field projects. One explanation for these changes
is that the low pH created by the high-pressure CO 2 dissolves carbonate minerals, such as calcite or dolomite, to form water-soluble
bicarbonates:
50
Page 2 of 6
12/30/2009
TABLE 3-LABORATORY COREFLOOD EXPERIMENTS
i
High-Volume,
Low-Volume,
High-Rate Flood Low-Rate Flood
Length of Rangely core, ft
0.25
3 (17 cores
butted together)
Carbonated brine
1.2
injected, PV
100+
Ratio of CO 2 /brine of
carbonated brine
1 to 4
1
:::: 100
0.5
Frontal advance rate, ft/D
2,900
Backpressure, psi
2,000
.§.
Brine/synthetic Rangely water
2.9% NaCI-11 ,400 mg/L Na
0.25% CaC1 2 -920 mg/L Ca
0.058% MgC1 2 -148 mg/L Mg
2000
~~~-~~~".....----------,
300
250
c
~
c ""'
t
1500
200
,g
§ 1000
150
-;; I!!
~
Il
(J
c
•
Calcium
.g
• Mogn.sium
§
..
.
100
50
Iron
o-
§~
a. E§
G>
~
II
(J
:2
(J
2
3
Cumulative Pore Volumes
4
5
Fig. 3-Effluent brine chemistry from low-volume, low-rate
Rangely CO 2 coreflood.
Coreflood procedure
1. Clean core(s) with solvent
2. Saturate with synthetic Rangely brine
3. Oilflood with Rangely crude
4. Waterflood to residual oil saturation
5. Inject carbonated brine
6. Inject brine flush
Laboratory Evaluation of Scale Inhibitors
for CO 2 Project
We performed laboratory screening tests to evaluate more than 30
scale inhibitors submitted by seven different vendors for their suitability for Rangely conditions. To be considered for field testing a
product had to perform well against BaS04 scale at the pH of 4.5
expected after CO 2 breakthrough, BaS04 scale at neutral pH, and
CaC0 3 scale at neutral pH.
Laboratory evaluation consisted of bottle tests where a supers.aturation of either BaS04 (70 mg/L) or CaC0 3 (900 mg/L) was added
to a bottle containing Rangely brine and inhibitor for a specified
time at reservoir temperature (160°F). Inhibitor effectiveness was
calculated from the barium or calcium left in solution vs. that of
a blank. A formic acid buffer was included in the tests conducted
at reduced pH. The Appendix details the testing procedure.
Table 4 presents the results for a representative cross section of
the inhibitors tested. Note that all inhibitor concentrations are parts
per million of total chemical, not just active ingredient. Several
trends emerged.
1. The phosphate ester and phosphonates all have excellent performance against both scales at neutral pH.
2. The phosphate ester and some phosphonates fail against
BaS04 when the pH is reduced to 4.5, the average pH expected
in the produced water in the CO 2 project. Some phosphonates perform well at a pH of 4.5 but do much worse if the pH is reduced
further.
3. Polymer-based products offer protection against BaS04 to a
lower pH. Some show good activity even at a pH of 3.5.
4. Some polymers fail against either or both scales at neutral pH.
The falloff in performance at neutral pH (especially vs. CaC0 3
scale) was common for many polymer-containing products (results
not shown). One vendor suggested using a blend of a phosphonate
and polymer; such a compromise might result in a product that
would be adequate over the entire pH range. This approach did
work for a SO/50 mixture ofInhibitors E (phosphonate) and F (active
ingredient is polymer only). Some of the successful polymer-based
scale inhibitors, such as Inhibitors G and H, have other active components to augment the polymer.
Other screening tests examined possible interferences from the
presence of crude oil or corrosion inhibitors. They generally decreased scale-inhibitor performance only slightly (results not
shown).
Five products were included in the field testing program: Inhibitor
D, a phosphonate used in the waterflood; Inhibitor E, a new phosphonate; Inhibitor ElF, a 50/50 mixture of Phosphonate E and Polymer F; and Inhibitors G and H, both polymer-based products.
Field Testing of Scale Inhibitors for CO 2 Project
Scale-Inhibitor Program-Pre-C0 2 Flood. Scale problems were
found in the submersible pumps of the production wells as early
as 1964. Wellbore pressure drop caused the CaC0 3 scale to form.
The problem was mitigated by surface treating the wells with an
organic ester scale inhibitor. Scale-inhibitor squeezes began in 1978,
Fig. 4-Gross dolomite dissolution from large-volume CO 2 flood-Rangely Well Fee 40,5,759 ft: (a) pre-C0 2 flood; (b) postCO 2 flood.
SPE Production Engineering, August 1991
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261
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TABLE 4-LABORATORY EVALUATION OF SCALE INHIBITORS FOR RANGELY CO 2 PROJECT
Performance' vs.
BaS04
pH 3.5
10 ppm
5 ppm
P
P
P
P
P
P
P
P
P
P
F
F
F
E
G
G
G
pH 4
10 ppm
pH 4.5
Performance vs.
CaC0 3
pH 7
5 ppm
10 ppm
pH 7
3 ppm
P
P
F
E
E'
P
P
P
P
G
F
E
E
E
E
E
E
E
E
E
E
E
E
G
G
E
E
E
3 ppm
Phosphate Ester
Inhibitor A (surface facilities)
Phosphonates
Inhibitor
Inhibitor
Inhibitor
Inhibitor
B (no longer used)
C (no longer used)
D (still used)
E (new product)
F
E
E
Polymers/Blends
Inhibitor
Inhibitor
Inhibitor
Inhibitor
F
ElF (50/50 mixture)
G
H
E
E
E
E
E
E
E
P
F
E
E
E
G
E
E
'0 to 49% effective-poor (P); 50 to 74% effective-fair (F); 75 to 89% effective-good (G); 90 to 100% effective-excellent (E).
after the scale problems increased throughout the field and the discovery of BaS04 scale.
Until 1986 nearly all treatments were precipitation squeezes,
where CaCI 2 is added to force the phosphonate inhibitor to precipitate in the formation. Once production is resumed, the neutral-pH
produced water passing over the precipitated inhibitor near the wellbore dissolves a low, but effective, concentration of scale inhibitor
into the brine. Three phosphonates, Inhibitors B through D, have
been squeezed successfully in the Rangely waterflood.
Inhibitor Squeezes for the CO 2 Project. Revised Strategy. The
reduction of pH in the CO 2 project was expected to hinder the performance of scale inhibitors used for the waterflood. In fact, three
scaling failures occurred after CO 2 breakthrough in producers
squeezed with Inhibitor C. In each case, the residual scale-inhibitor
concentration was 5 to 10 ppm, more than sufficient for producers
in the waterflood area. These failures are consistent with the laboratory data (Table 4).
Another consideration is that a low-pH environment could make
the precipitation squeeze method impractical. A vendor study suggests that the phosphonates used at Rangely would not precipitate
with a pH less than 4. Thus, it might not be possible to make the
scale inhibitor drop out in the formation by adding excess calcium,
as done before. Adsorption squeezes were investigated as an alternative in the first field test program.
Another effect of the CO 2 flood was the decreased incidence of
CaC0 3 scale downhole, where the pH remained low. However,
CaC0 3 scaling began to appear more frequently on the surface,
where the pH increases with a reduction in pressure. Recall that
the produced water has higher calcium and bicarbonate concentrations after CO 2 breakthrough.
Selecting Minimum Concentration. The minimum residual scale
inhibitor allowed at Rangely before the squeeze treatment is repeated
is based on field experience and laboratory testing results. Most
wells are resqueezed when they reach a residual of 3 ppm or less
for 2 consecutive weeks. This simple criterion is being re-evaluated
because of some recent scaling problems at this low residual level.
The minimum concentration is increased to 4 or 5 ppm in producers
where water analyses indicate a relatively high BaS04 scaling
index.
Measurement Techniques. Squeeze lives are monitored by the
phosphonate and/or polymer residuals-Le., the concentration of
chemical present in the produced water. The phospho nate residuals
are determined by the usual colorimetric technique with ammonium
molybdate and ascorbic acid. 14 The measurement of the polymer
residual (for the organic polymer products) needs further work.
None of the polymer procedures submitted has been approved for
Rangely because the field-measured residuals have not been consistent. This analytical chemistry problem is a major drawback of
the polymer inhibitors.
Precipitation and Adsorption Squeezes in the CO 2 Area. The
first field test was designed to evaluate the most promising phosphonates and polymer-based inhibitors for effectiveness under lowpH conditions and to test precipitation vs. adsorption squeezes (Table 5). The success of the chemicals was evaluated by measuring
squeeze life in both barrels of water produced and squeeze duration.
These results also are presented in terms of dollars-per-day and
dollars-per-barrel treatment costs. All chemicals tested in the CO 2
TABLE 5-SUMMARY OF SCALE-INHIBITOR FIELD TEST
Average Life
Chemical
Cost of
Chemical Only
Chemical Plus
Workover Cost'
Jobs
Reviewed
Days
bblof
Produced
Water
8
8
7
366
636
202
533,921
1,207,476
501,415
6.33
3.91
27.62
0.004
0.002
0.011
157
90
300
0.107
0.048
0.121
11
8
7
5
356
354
474
86
616,104
578,380
578,079
118,930
20.37
20.96
12.87
58.08
0.012
0.013
0.011
0.042
175
176
129
698
0.101
0.108
0.106
0.504
Average
$Iday
Average
$/bbl
Average
$Iday
Average
$/bbl
Precipitation Squeezes
Inhibitor C
Inhibitor D
Inhibitor E
Adsorption Squeezes
Inhibitor E
Inhibitor ElF
Inhibitor G
Inhibitor H
• Average workover cost was $55,000.
"Included for comparison; these eight Inhibitor C squeezes completed before CO 2 breakthrough.
SPE Production Engineering, August 1991
262
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TABLE 6-CHEMICAL REQUIREMENTS/MIXING
PROCEDURES FOR RANGELY SQUEEZES
1~,--------------------------------------,
500
300
Scale Inhibitor
Precipitation Squeezes
D
0.2
2
13.5
6
gal chemical/BFPD
bbl premix water/gal chemical
Ibm CaCl2/gal chemical
bbl overflush/net It pay
C
0.2
1
6
6
Adsorption Squeezes
E E/F G H
gal chemical/BFPD
bbl premix water/gal chemical
bbl overllush/net It pay
. - - Inhibitor 0; Precipitation Squeeze at Mclaughlin 14Y33
- - - Inhibitor E; Adsorption Squeeze at Union Pacific 135Y28
e-o.
E
0.25
1
10
10
S: 100
'ii
...'ii"
CD
a:
...:E~
E
0.35
0.5
15
10
5
3
2
area except Inhibitor C were technically successful-Le., almost
no scaling failures even after CO 2 breakthrough.
Adsorption-type squeezes are preferred over precipitation
squeezes because of the lower cost (no CaCl 2 injection required)
and the reduced risk of formation damage. Testing is continuing
with the precipitation-type squeeze because this procedure has given
long squeeze lives without undue problems in the waterflood area.
Also, the most cost-effective treatments reported in Table 5 for the
CO 2 project are the precipitation squeezes with Inhibitor D.
The lifetimes of the precipitation squeezes with Inhibitor Dare
similar for treatments in the CO 2 project and in the waterflood
area. The placement and the dissolution of the precipitated scale
inhibitor apparently is not impaired in the lower-pH environment
near CO 2 producers.
It is not known whether the average squeeze life of 21 months
for Inhibitor D is a function of the chemical itself or the squeeze
procedure. Table 6 shows the mixing procedures for the various
treatments. The premix procedure (larger, more dilute scaleinhibitor volume) may be the important factor. The second field
test now in progress includes precipitation squeezes with Phosphonate E using this premix procedure.
The adsorption squeezes include four different products, all having
the same squeeze design (Table 6). Inhibitor G achieved the longest
adsorption squeeze life, but Inhibitor H lasted only 3 months (Table
5). For an unknown reason, this chemical has very poor adsorption/
desorption characteristics in this reservoir.
Adsorption squeezes with a phosphonate chemical (Inhibitor E)
did not compare well with the long squeeze lives of the Inhibitor
D precipitation squeezes (Fig. 5). The second field test will evaluate
Inhibitor D in adsorption squeezes to see whether adsorption
squeezes with this chemical can duplicate the extended lifetimes
of its precipitation squeezes. The idea is to eliminate the cost of
the added CaCl 2 while maintaining a 1- to 2-year squeeze life.
Summary From First Field Test. The first field test met its two
objectives: (1) to determine available chemicals that can economically inhibit scale in Rangely's new low-pH environment and (2) to
develop procedures to give acceptable squeeze lives in the CO 2
area. Results show that properly selected phosphonates and polymerbased products will meet the field requirements. The phosphonate
inhibitors are preferred because of their lower chemical cost, longer
squeeze life, and ability to determine residuals accurately.
New Studies To Improve Squeeze Program
Additional field and laboratory work is in progress to better our
understanding of scale deposition and the interaction of scale inhibitors with the Weber sandstone. Preliminary results suggest a revised squeeze procedure that might improve lifetimes in both the
waterflood and the CO 2 areas.
The findillgs so far are that barium scale occurs mainly in the
shallower sand zones-i.e., those with the highest permeability and
highest fluid production-and that injection of scale-inhibitor solutions can cause formation damage.
Gamma ray logging was used to survey BaS04 scale. This technique works because, as is common in the oil field, the BaS04
deposits at Rangely are slightly radioactive from the incorporation
of radium into the crystal lattice. 15 The survey shows that barite
deposition is related to the amount of fluid produced rather than
to the lithology.
8
10
12
14
16
18
20
22
24
Months Since Start of Squeeze
Fig. 5-Typical squeeze treatment returns for phospho nate
Inhibitors D and E.
Preliminary coreflood data show that injection of scale inhibitor
can reduce Weber sandstone permeability, probably through clay
migration. The negatively-charged scale inhibitor may disperse fibrous illite clay by lifting damaged or broken clay fibers from the
pore wall and into solution. Eventually, the clay particles can catch
in the narrow pore throats and reduce permeability. Another way
to bring the illite clay into solution is through the dissolution of
carbonate minerals. Acidic phosphonate solutions can attack the
calcite and dolomite, thereby releasing clay particles anchored to
these minerals.
Information on the location of barite scale and the potential for
formation damage by injected scale-inhibitor solution suggests a
revision of placement practices at Rangely. Previously, scale inhibitor was squeezed in several stages with diverting agents to ensure
placement even in the lowest-permeability zones. Alternative approaches that might improve the squeezes include the following.
1. Discontinue the use of diverting agents. It does not make sense
to place inhibitor into sands that are not scaling and are perhaps
damaged by the scale-inhibitor solution. In addition, the deepest
sands are pressure depleted in some cases; inhibitor placed there
will never return and thus would be wasted.
2. Where only one zone is contributing to barium scale, isolate
and squeeze only this zone.
3. Inject the chemical in one slug rather than in several stages.
Staggered injection is not necessary if diversion is not required.
A single slug and overflush is easier to implement and may increase
squeeze life by maximizing inhibitor penetration into the formation.
These ideas will be evaluated during the second field test.
Conclusions
1. Injection of CO 2 significantly affects the produced-water
chemistry at Rangely. The pH is lowered to approximately 4.5
downhole in producers after CO 2 breakthrough, which renders
most inhibitors used in the waterflood ineffective against BaS04'
There is a marked increase in the concentrations of calcium, magnesium, iron, and bicarbonate owing to the dissolution of calcite
and ferroan dolomite; this increases the CaC0 3 scaling tendency
as the brine is brought to the surface and the pH rises.
2. Laboratory screening tests identified several phosphonate and
polymer-based scale inhibitors that met all the criteria for the CO 2
project: prevention of BaS04 at a pH of 4.5 and of BaS04 and
CaC0 3 at neutral pH. The performance of an inhibitor at low pH
must be measured; it is not predictable on the basis of its behavior
at neutral pH.
3. Both precipitation and adsorption squeezes have squeeze lives
exceeding 1 year. A phosphonate chemical used in precipitation
squeezes had the longest life (21 months).
4. Phosphonates are preferred over polymer-based scale inhibitors because their residuals can be determined much more reliably,
they generally are less expensive, and the provide the longest, most
cost-effective squeezes.
SPE Production Engineering, August 1991
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Authors
Patrick J. Shuler
Is a senior research
engineer at Chevron Oil Field Research Co. His
research interests
include scale inhibition, formation
damage, and EOR.
Shuler holds a BS
degree from the U.
of Notre Dame and
Bowker
Shuler
MS and PhD degrees from the U.
of Colorado, all in chemical engineering. Elizabeth A. Freitas has worked on the Rangely field for Chevron U.S.A. Inc.
since 1982 as a drilling representative and a gas and chemical engineer; her primary duties were water quality and scaleand corrosion-inhibition programs. She is now working in the
Facilities Engineering Group in the Overthrust Belt Area of
Wyoming. Freitas holds a BS degree in petroleum engineering from the U. of Southern California. (Photo unavailable.)
Kent A. Bowker began working for Chevron U.S.A. Inc. as
a petroleum geologist 10 years ago after earning an MS degree
from Oklahoma State U. He has experience In several basins
in addition to his work in Rangely field.
Acknowledgments
We thank R.E. Ladd for his geological input and B.L. Dias for
her assistance in the experimental work. We also thank the management of Chevron Oil Field Research Co. and Chevron U.S.A. Inc.
for permission to publish this paper.
References
1. Cruise, D.S., Davis, D.L. and Elliott, R.H.: "Use of Continuous Coil
Tubing for Subsurface Scale and Corrosion in Treating Rangely Weber Sand Unit," paper SPE 11853 presented at the 1983 SPE Rocky
Mountain Regional Meeting, Salt Lake City, May 23-25.
2. Cramer, R.W. and Bearden, J.L.: "Development and Application of
a Downhole Chemical Injection Pump for Use in ESP Applications,"
paper SPE 14403 presented at the 1985 Annual Technical Conference
and Exhibition, Las Vegas, Sept. 22-25.
3. Ramsey, J.E. and Cenegy, L.M.: "A Laboratory Evaluation of Bariurn Sulfate Scale Inhibitors at Low pH for Use in Carbon Dioxide EOR
Floods," paper SPE 14407 presented at the 1985 SPE Annual Technical
Conference and Exhibition, Las Vegas, Sept. 22-25.
.
4. Chesnut, G.R., Chappel, G.D., and Emmons, D.H.: "Development
of Scale Inhibitors and Evaluation Techniques for CO 2 EOR Floods,"
paper SPE 16260 presented at the 1987 SPE IntI. Symposium on Oilfield
and Geothermal Chemistry, San Antonio, Feb. 4-6.
5. Cushner, M.e., Przybylinski, J.L., and Ruggeri, J.W.: "How Temperature and pH Affect the Performance of Barium Sulfate Inhibitors," paper
428 presented at NACE Corrosion 88, St. Louis, March 21-25.
6. Omole, O. and Osoba, J.S.: "Carbon Dioxide-Dolomite Rock Interaction During CO 2 Flooding Process," paper CIM 83-34-17 presented
at the 1983 Annual Technical Meeting of the Petroleum Soc. ofCIM,
Banff, May 10-13.
7. Sayegh, S.G. et al.: "Rock-Carbonated Brine Interactions: Part 1Cardium Formation Cores," paper CIM 87-38-78 presented at the 1987
Annual Technical Meeting of the Petroleum Soc. ofCIM, Calgary, June
7-10.
8. Todd, A.C. et al.: "The Dissolution Effects of COz-Brine Systems
on the Permeability of U.K. and North Sea Calcareous Sandstones,"
paper SPE 10685 presented at the 1982 SPE/DOE Symposium on Enhanced Oil Recovery, Tulsa, April 4-7.
9. Bowker, K.A. and Shuler, P.J.: "Carbon Dioxide Injection and Resultant Alteration of the Weber Sandstone (Pennsylvanian/Permian),
Rangely Field, CO," paper SPE 19875 presented at the 1989 SPE Annual Technical Conference and Exhibition, San Antonio, Sept. 8-11.
10. Crolet, J.L. and Bonis, M.R.: "pH Measurement in Aqueous CO 2 Solutions Under High Pressure and Temperature," Corrosion (1983)
39-46.
11. Sanders, S.J.: "Case Studies in Modelling Aqueous Electrolyte Solutions," Computers & Chern. Eng. (1985) 223-44.
.
12. Ede, M.: "Main Results of Field Experiment Establishing Exploitation
With CO 2 in Hungary," Proc., Inti. Symposium on CO 2 Enhanced
Oil Recovery, Budapest (March 8-11, 1983) 327-40.
13. Newton, L.E. and McClay, R.A.: "Corrosion and Operational Problems, CO 2 Project, Sacroc Unit," paper 6391 presented at the 1977
SPE Permian Basin Oil and Gas Recovery Conference, Midland, March
10-11.
14. Myers, K.O., Skillman, R.L., and Herring, G.D.: "Control of Formation Damage at Prudhoe Bay, Alaska, by Inhibitor Squeeze Treatment," JPT (June 1985) 1019-34.
15. Smith, A.L.: "Radioactive Scale Formation," JPT (June 1987) 697-706.
Appendix-Experimental Procedure for
Scale-Inhibitor Evaluation
Ba804 •
Solutions.
1.
2.
3.
4.
Procedure.
test brine.
A-1.0649 g Na2S01250 cm 3 .
B-1.8313 g BaCl 2 ·2H 2 0/250 cm 3 .
C-O.4 g NaP0 3 /100 cm 3 .
1. Add 5 cm 3 oil if used.
2. Evacuate the bottle.
3. If you wish to lower the pH, add formic acid buffer
solution-l M formic acid/1 M HC!.
4. Add test brine (96 cm 3 , or 91 cm 3 if oil is used).
5. Add the test amount of scale inhibitor (corrosion inhibitor
optional).
6. Add 1 cm 3 Solution A.
7. Flush stopcock with 1 cm 3 Rangely brine.
8. Heat to 160°F for 15 minutes.
9. Add 1 cm 3 Solution B.
10. Flush stopcock with 1 cm 3 Rangely brine.
11. Maintain at 160°F with slow agitation for 3 hours.
12. Remove the bottle and add 0.1 cm 3 Solution C.
13. Cool rapidly (use ice water).
14. Filter sample to 0.45 /Lm.
15. Analyze for barium by inductively coupled plasma spectrometer.
CaC0 3 •
Solutions.
1. Saturate the test brine with CO 2 and divide it into two parts.
2. Add CaCl 2 ·2H 20 (2.64 giL) to one test brine.
3. Add NaHC0 3 (3.02 giL) to the other part, while continuing
to bubble CO 2, In these tests, 900 mg/L of CaC0 3 was added to
the Rangely brine.
4. Mix brines together at room temperature and keep under CO 2
pressure.
Procedure.
1. Evacuate the bottle and add the appropriate volume of scaleinhibitor solution.
2. Add 99 cm 3 of test brine.
3. Heat to 160°F for 5 hours.
4. Cool overnight.
5. Filter sample to 0.45 /Lm.
6. Analyze for calcium by ICP.
% Effectiveness = [(Cs - CBV(Ci -CB)] 100,
where Cs = concentration of Ba + + or Ca + + in the sample (mg/L),
CB = concentration of Ba + + or Ca + + left in the blank (mg/L),
and Ci = initial concentration of Ba + + or Ca + + (mg/L).
SI Metric Conversion Factors
E-Ol
acres x 4.046873
E-Ol
bbl x 1.589873
E-Ol
ft X 3.048*
ft3 X 2.831 685
E-02
OF (OF-32)/1.8
gal X 3.785412
E-03
in. 3 X 1.638706
E+Ol
E-Ol
Ibm X 4.535924
psi X 6.894757
E+OO
ha
m3
m
m3
°C
m3
cm 3
kg
kPa
8PEPE
• Conversion factor is exact.
Original SPE manuscript received for review March 6, 1989. Paper accepted for publication
Aug. 27, 1990. Revised manuscript received Jan. 2, 1991. Paper (SPE 18973) first presented
at the 1989 SPE Rocky Mountain Regional/low-Permeability Reservoir Symposium held
in Denver, March 6-8.
264
Bluescape
Rangely
Solution
Solution
Solution
SPE Production Engineering, August 1991
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