Uncorrected Proof AUTHORS Rajesh J. Pawar Earth and Environmental Sciences Division, Los Alamos National Labo- ratory, MS T003, Los Alamos, New Mexico 87545 AQ2 ; [email protected]Rajesh Pawar is a technical staff member at the Los Alamos National Laboratory. He received his Ph.D. from the University of Utah in chemical and fuels engineering. His primary research focus is fluid flow in porous media. He has served as the associate editor of Reviews in Geophysics. Norm R. Warpinski AQ3, AQ4 Sandia National Laboratories, Albuquerque, New Mexico; [email protected]John C. Lorenz Sandia National Labora- tories, Albuquerque, New Mexico; [email protected]John Lorenz worked for the Peace Corps and the U.S. Geological Survey before joining Sandia National Laboratories in 1981, where he is presently a Distinguished Member of the Tech- nical Staff. He received his Ph.D. from Princeton University, has been elected editor for AAPG, and has published widely on the sedimentology and natural fractures in hydrocarbon reservoirs. Robert D. Benson Colorado School of Mines, Golden, Colorado; [email protected]Robert (Bob) D. Benson is a research associate professor in the Department of Geophysics at the Colorado School of Mines and is codirector of the Reservoir Characterization Project. Benson has more than 25 years of experience in seismic ac- quisition, processing, and interpretation. He holds B.S. and M.S. degrees and a Ph.D. in geophysics from the Colorado School of Mines. He is a past president of the Denver Geophysical Society. Reid B. Grigg New Mexico Institute of Mining and Technology, Socorro, New Mexico; [email protected]Reid Grigg is a senior engineer and section head at the New Mexico Petroleum Recovery Research Center and an adjunct professor at the New Mexico Institute of Mining and Technology. His research interests include high-pressure gas- flooding processes, phase behavior, and studies of the fluid properties of high-pressure injection gas and reservoir fluids related to improved oil recovery and carbon storage. He has authored more than 70 publications. 1 2 Overview of a CO 2 3 sequestration field test 4 in the West Pearl Queen 5 reservoir, New Mexico 6 Rajesh J. Pawar, Norm R. Warpinski, John C. Lorenz, 7 Robert D. Benson, Reid B. Grigg, Bruce A. Stubbs, 8 Philip H. Stauffer, James P. Krumhansl, and 9 Scott P. Cooper 10 ABSTRACT 11 Carbon dioxide (CO 2 ) sequestration in geological formations is the 12 most direct carbon management strategy for reducing anthropo- 13 genic CO 2 emissions into the atmosphere and will likely be needed 14 for continuation of the global fossil-fuel – based economy. Storage of 15 CO 2 into depleted oil reservoirs may prove to be both cost effective 16 and environmentally safe. However, injection of CO 2 into oil res- 17 ervoirs is a complex issue, spanning a wide range of scientific, tech- 18 nological, economic, safety, and regulatory issues. Detailed studies 19 about the long-term impact of CO 2 on the host reservoir are 20 necessary before this technology can be deployed. This article pro- 21 vides an overview of a U.S. Department of Energy – sponsored proj- 22 ect that examines CO 2 sequestration in a depleted oil reservoir. The 23 main objectives of the project are (1) to characterize the oil reser- 24 voir and its sequestration capacity; (2) to better understand CO 2 25 sequestration-related processes; and (3) to predict and monitor 26 the migration and ultimate fate of CO 2 after injection into a de- 27 pleted sandstone oil reservoir. The project is focused around a 28 field test that involved the injection of approximately 2090 tons (2123.54 t) AQ1 of CO 2 into a depleted sandstone reservoir at the West 30 Pearl Queen field in southeastern New Mexico. Geophysical moni- 31 toring surveys, laboratory experiments, geophysical surveys, and 32 numerical simulations were performed in support of the field 33 experiment. Results show that the response of the West Pearl 34 Queen reservoir during the field experiment was significantly 35 different than expected based on the preinjection characterization 36 data. Furthermore, results from a 19-month bench-scale experi- 37 ments of CO 2 interaction with the Queen sand were not able to be Environmental Geosciences, v. 13, no. 3 (September 2006), pp. 1 – 18 1 Copyright #2006. The American Association of Petroleum Geologists/Division of Environmental Geosciences. All rights reserved. DOI:10.1306/eg.10290505013
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AUTHORS
Rajesh J. Pawar � Earth and EnvironmentalSciences Division, Los Alamos National Labo-ratory, MS T003, Los Alamos, New Mexico87545 AQ2; [email protected]
Rajesh Pawar is a technical staff member at theLos Alamos National Laboratory. He received hisPh.D. from the University of Utah in chemical andfuels engineering. His primary research focus isfluid flow in porous media. He has served as theassociate editor of Reviews in Geophysics.
Norm R. Warpinski � AQ3, AQ4Sandia NationalLaboratories, Albuquerque, New Mexico;[email protected]
John C. Lorenz � Sandia National Labora-tories, Albuquerque, New Mexico;[email protected]
John Lorenz worked for the Peace Corps andthe U.S. Geological Survey before joining SandiaNational Laboratories in 1981, where he ispresently a Distinguished Member of the Tech-nical Staff. He received his Ph.D. from PrincetonUniversity, has been elected editor for AAPG,and has published widely on the sedimentologyand natural fractures in hydrocarbon reservoirs.
Robert D. Benson � Colorado School ofMines, Golden, Colorado; [email protected]
Robert (Bob) D. Benson is a research associateprofessor in the Department of Geophysics at theColorado School of Mines and is codirector of theReservoir Characterization Project. Benson hasmore than 25 years of experience in seismic ac-quisition, processing, and interpretation. He holdsB.S. and M.S. degrees and a Ph.D. in geophysicsfrom the Colorado School of Mines. He is a pastpresident of the Denver Geophysical Society.
Reid B. Grigg � New Mexico Institute ofMining and Technology, Socorro, New Mexico;[email protected]
Reid Grigg is a senior engineer and section headat the New Mexico Petroleum Recovery ResearchCenter and an adjunct professor at the NewMexico Institute of Mining and Technology. Hisresearch interests include high-pressure gas-flooding processes, phase behavior, and studiesof the fluid properties of high-pressure injectiongas and reservoir fluids related to improvedoil recovery and carbon storage. He has authoredmore than 70 publications.
1
2 Overview of a CO2
3 sequestration field test4 in the West Pearl Queen5 reservoir, New Mexico6 Rajesh J. Pawar, Norm R. Warpinski, John C. Lorenz,7 Robert D. Benson, Reid B. Grigg, Bruce A. Stubbs,8 Philip H. Stauffer, James P. Krumhansl, and9 Scott P. Cooper
1 0 ABSTRACT
11 Carbon dioxide (CO2) sequestration in geological formations is the
12 most direct carbon management strategy for reducing anthropo-
13 genic CO2 emissions into the atmosphere and will likely be needed
14 for continuation of the global fossil-fuel–based economy. Storage of
15 CO2 into depleted oil reservoirs may prove to be both cost effective
16 and environmentally safe. However, injection of CO2 into oil res-
17 ervoirs is a complex issue, spanning a wide range of scientific, tech-
18 nological, economic, safety, and regulatory issues. Detailed studies
19 about the long-term impact of CO2 on the host reservoir are
20 necessary before this technology can be deployed. This article pro-
21 vides an overview of a U.S. Department of Energy–sponsored proj-
22 ect that examines CO2 sequestration in a depleted oil reservoir. The
23 main objectives of the project are (1) to characterize the oil reser-
24 voir and its sequestration capacity; (2) to better understand CO2
25 sequestration-related processes; and (3) to predict and monitor
26 the migration and ultimate fate of CO2 after injection into a de-
27 pleted sandstone oil reservoir. The project is focused around a
28 field test that involved the injection of approximately 2090 tons
(2123.54 t)AQ1 of CO2 into a depleted sandstone reservoir at the West
30 Pearl Queen field in southeastern New Mexico. Geophysical moni-
31 toring surveys, laboratory experiments, geophysical surveys, and
32 numerical simulations were performed in support of the field
33 experiment. Results show that the response of the West Pearl
34 Queen reservoir during the field experiment was significantly
35 different than expected based on the preinjection characterization
36 data. Furthermore, results from a 19-month bench-scale experi-
37 ments of CO2 interaction with the Queen sand were not able to be
Environmental Geosciences, v. 13, no. 3 (September 2006), pp. 1– 18 1
Copyright #2006. The American Association of Petroleum Geologists/Division of EnvironmentalGeosciences. All rights reserved.
DOI:10.1306/eg.10290505013
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38fully reproduced using the latest numerical modeling algorithms,
39suggesting that the current models are not capturing important
40geochemical interactions.
41INTRODUCTION
42Among the most direct methods to sequester CO2 is its injection
43into geological formations. Deep saline aquifers, uneconomic coal
44seams, and depleted gas reservoirs are potential options; however,
45depleted oil reservoirs are available for immediate deployment of
46this technology. Depleted oil reservoirs have distinct advantages
47over other geological storage options.
49� Knowledge base: A large number of oil reservoirs have already
50been extensively characterized. Most of the characterization
51information for oil fields in the United States and elsewhere is
52publicly available. Additionally, the use of CO2 in enhanced oil
53recovery (EOR) operations for more than three decades has re-
54sulted in information on interactions between CO2 and reservoir
55rock and fluids that could be useful in estimating capacity and
56predicting the long-term fate of CO2.
57� Infrastructure: A major advantage of oil and gas reservoirs is that
58numerous wells have been drilled in these fields. A large per-
59centage of these wells have the potential to be converted to
60injection and/or monitoring wells. In addition, CO2-EOR op-
61erations have also resulted in pipeline infrastructure for trans-
62porting CO2, most extensively in the Permian Basin in west
63Texas.
64� Economics: Depleted oil reservoirs have the potential for in-
65cremental oil recovery that can considerably improve the overall
66economics for CO2 sequestration projects.67
68There are also some disadvantages to depleted oil reservoirs.
69Based on the initial estimates, these reservoirs have lesser capacity
70compared to saline aquifers. In addition to the existing wells, these
71reservoirs have a large number of abandoned wells. In some cases,
72the locations of these wells are unknown. Depending on the quality
73of abandonment, these wells may become potential future path-
74ways for escape of CO2 from the reservoir.
75Before geological sequestration of CO2 can be used on large
76scales, confidence in this technology needs to be ensured by ad-
77dressing safety issues, developing a proper regulatory regime, and
78better evaluating the overall economics. Ensuring confidence re-
79quires undertaking projects with specific sequestration-related ob-
80jectives. In the case of oil reservoirs, this would require projects that
81are not typical (e.g., oil production-driven) EOR projects. Current
82industrial EOR reservoir strategies, which include uniform flood
83sweep, optimized placement of wells, inhibition of viscous finger-
84ing, and minimizing CO2 injection (Mungan, 1992), are based on
85economic goals that are not well aligned with sequestration goals.
Bruce A. Stubbs � Strata Production Company,Roswell, New Mexico; [email protected]
Stubbs is a consultant petroleum engineer, with33 years of industry experience, for Pecos Petro-leum Engineering, Inc., in Roswell, New Mexico. Hehas been a consultant since 1992 after spending5 years with Hondo Oil and Gas Company. Heholds a bachelor’s degree in mechanical engi-neering from the New Mexico State University.He is the project engineer for Strata ProductionCompany on the U.S. Department of EnergyClass III Project at Nash Draw.
Philip H. Stauffer � Los Alamos NationalLaboratory, Los Alamos, New Mexico;[email protected]
Phillip Stauffer is a technical staff member at theLos Alamos National Laboratory. His researchinvolves code development, simulation, and as-sessment of subsurface multiphase transport ina variety of geological environments. His back-ground in heat and mass transport includes workon the Yucca Mountain Project, the Ocean Dril-ling Program, and most recently, the Zero Emis-sions Research and Technology Program.
James P. KrumhanslAQ5 � Sandia NationalLaboratories, Albuquerque, New Mexico;[email protected]
Scott P. Cooper � Sandia National Labora-tories, Albuquerque, New Mexico;[email protected]
Scott Cooper is a senior member of the tech-nical staff at Sandia National Laboratories. Hereceived his B.S. degree from the South DakotaSchool of Mines and Technology (1997) andhis M.S. degree in geology from the New MexicoInstitute of Mining and Technology (2000). Hiscurrent research focuses on natural fracture sys-tems and reservoir characterization.
ACKNOWLEDGEMENTS
Funding for this work was provided by theU.S. Department of Energy. The authors alsothank KinderMorgan CO2 for donating theCO2 used during field-injection experiments.
AQ62 Overview of a CO2 Sequestration Field Test in the West Pearl Queen Reservoir
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86 Sequestration goals are targeted to enhance sequestra-
87 tion volume and duration of CO2 in geological for-
88 mations. In the past, there have been few economic
89 incentives and minimal research-and-development
90 support to understand the physical and chemical inter-
91 actions and ultimate fate of injected CO2 in oil-pro-
92 ducing reservoirs during EOR sweeps.
93 Our project aims to provide important elements of
94 the science and technology base that will be necessary
95 to properly evaluate the safety and efficacy of long-term
96 CO2 sequestration in depleted oil reservoirs. The re-
97 sults and data generated in this project will be valuable
98 in assessing other geological reservoirs. The ultimate
99 goal of the project is to predict the migration and long-
100 term fate of CO2 in sandstone oil reservoirs. Although
101 the ultimate goal of such studies is to improve our
102 understanding of the main sequestration mechanisms
103 and resultant reservoir processes, a complete assess-
104 ment of geological sequestration will require several
105 similar test programs to assess different geological set-
106 tings. The project is a multiorganizational effort that
107 includes United States national laboratories, academia,
108 and industry. The primary partners include the Los
109 Alamos National Laboratory, Sandia National Labora-
110 tories, Strata Production Company, the New Mexico
111 Institute of Mining and Technology, and the Colorado
112 School of Mines. The project combines a small-scale
113 field-injection experiment with geophysical monitor-
114 ing, numerical simulation, and laboratory experiments,
115 with the following objectives:
117 � characterization of the oil reservoir and its capacity
118 to sequester CO2
119 � characterization of the interactions of CO2 with
120 reservoir fluids and rocks
121 � assessment of the ability of geophysical techniques
122 to monitor123
124 The project is divided into three phases:
125 � Phase I consisted of preinjection activities, includ-
126 ing characterization of the reservoir, calculation of
127 expected CO2 injection and migration behavior,
128 acquisition of baseline geophysical surveys, prepa-
129 ration of the injection well, and acquisition of legal
130 permits for injection.
131 � Phase II consisted of activities pertaining to the in-
132 jection and soaking of CO2 in the reservoir; these
133 included the design of the field-injection test, pre-
134 paration of surface injection facilities, injection of
135 CO2, measurement of fluid-pressure changes and
136CO2 breakthroughs, acquisition of geophysical sur-
veys, and refinement of computer-simulation models. AQ7
138� Phase III consisted of activities related to predicting
139CO2 migration and its interaction with the reservoir
140rocks and fluids, including acquisition of postsoak
141geophysical surveys, venting of CO2 from the reser-
142voir, monitoring gas and liquid production, collec-
143tion and analysis of gas and liquid samples, iteration
144of computer-simulation models, and integration of
145the results, analyses, and data from the project.146
147We are currently continuing work in phase III,
148monitoring CO2 migration in the reservoir, and are in-
149tegrating the data acquired to understand CO2 migra-
150tion. This study provides details of the preinjection
151characterization activities and the field experiments.
152Details of the integration of data and modeling results
153and CO2 migration will be published at a later date.
154FIELD SITE
155We chose the West Pearl Queen depleted oil reservoir
156for the field test. It is located in southeastern New
157Mexico (Figure 1) and is operated by the Strata Pro-
158duction Company (SPC) of Roswell, New Mexico.
159This field had some distinct advantages, including
161� no economic and technical restrictions of an EOR
162operation
163� opportunity and freedom to observe the response
164of the reservoir without the concerns of early
165breakthrough or degradation of production reser-
166voir features
167� availability of offset wells for monitoring instead of
168production of oil
169� ability of varying soak times beyond industry EOR
170standards171
172The field has produced about 250,000 bbl (39,746 m3)
173of oil since 1984. Production from the field has slowed
174in recent years. No secondary or tertiary recovery op-
175erations have been applied in the field, which made
176this field an attractive field site because the interpre-
177tation of field experiment results would not have the
178complications related to the prior enhanced recovery
179operations.
180Figure 2 shows a site map with the locations of
181wells in the field. The field is primarily located in
182Sec. 27, 28, and 33, T19S R34W. The SPC has drilled
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184 Stivason Federal 5 is actively produced. Wells Stivason
185 Federal 1 and Stivason Federal 3 have been recently
186 converted into salt-water disposal wells. Well Stivason
187 Federal 2 has been shut in. Well Stivason Federal 4,
188 which has been shut in since 1998, was chosen as the
189 CO2-injection well for the field experiment. Produc-
190 tion from Stivason Federal 5 was stopped during the
191 field experiment, and the well was available for moni-
192 toring and for cross-well surveys. Figure 2 also shows
193 other wells in the area. Of these, only well Sun Pearl 2
194 is completed in the Queen Formation.
195PREINJECTION CHARACTERIZATION
196Preinjection characterization of the field included sev-
197eral activities. The goal was to characterize the reser-
198voir geology, reservoir-flow dynamics, and the poten-
199tial response of reservoir rock to CO2 injection.
200Geology
201Several techniques and data sources were used to char-
202acterize reservoir geology. Prior to this project, data
203available to characterize the reservoir geology were
Figure 1. Location of the WestPearl Queen field, southeast-ern New Mexico. The reservoirstrata are 4500 ft (1371 m) be-low the surface geology, whichconsists of poorly and uncon-solidated Tertiary and Quater-nary sediments.
Figure 2. Structure-contour (subsea-depth) map of the West Pearl Queen fieldbased on well picks at the top of theShattuck Member of the Queen Forma-tion. It is significantly different from thestructure map based on seismic datapresented later (Figure 8). This showsthe locations of the wells pertinent tothis study, including the production andwater-injection wells, the central CO2-injection well, and the monitor well.
4 Overview of a CO2 Sequestration Field Test in the West Pearl Queen Reservoir
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204 limited and primarily consisted of logs, including gamma
205 ray, neutron porosity, density porosity, and dual latero-
206 logs (resistivity). In addition, results of core analyses,
207 which consisted of porosity and permeability mea-
208 surements for well Stivason Federal 1, were also avail-
209 able. No seismic surveys were acquired for the field
210 prior to this project; hence, several activities were per-
211 formed to further characterize the reservoir structure
212 and geology. We were successful in obtaining actual core
213 from the reservoir. A detailed analysis using the core,
214 historic logs, and outcrop was performed. In addition,
215 several geophysical surveys were acquired, including
216 dipole sonic logs for wells Stivason Federal 4 and
217 Stivason Federal 5; a cross-well survey between wells
218 Stivason Federal 4 and Stivason Federal 5; and a high-
seismic survey.AQ8 The surface seismic survey employed
221 about 1000 source and receiver locations and covered
222 an area of 1 mi2 (2.6 km2) around well Stivason Federal 4.
223 The survey was repeated during the field experiment to
224 monitor CO2 migration. Both the repeat survey and the
225 baseline survey were used to interpret the structure.
226 The surveys had uniform azimuth and offset distribu-
227 tion and provided high-resolution coverage. Because
228 time-lapse effects are subtle, the surveys were designed
229 to maximize the signal-to-noise ratio of the data and its
230 repeatability. In processing, surface-consistent linear
231 processes were used, thereby preserving the integrity
232 of the signal between the baseline and monitor surveys.
233 The West Pearl Queen field reservoir is in the
234 Permian–age Shattuck Member of the Queen Forma-
235 tion. It is a sandy, shaly, and evaporitic unit deposited in
236 ephemeral flood-plain fluvial environments at the mar-
237 gin of the Permian Basin (Malicse and Mazzullo, 1990;
Mazzullo et al., 1991; Holley and Mazzullo, 1998AQ9 ). The
239 average depth of the reservoir is about 4500 ft (1371.6 m).
240 The average gross thickness of the reservoir is about 40 ft
241 (12.2 m). Analysis of core shows three basic lithologies.
242 About 80% of the available core consists of poorly
243 cemented, oil-stained sandstone with 15–20% porosity
244 and highly variable permeability up to 200 md (2 �245 10�13 m2). It is a cross-bedded to massive, arkosic, and
246 fine- to very fine-grained sandstone. Oil staining and
247 laboratory measurements indicate high porosity, and
248 the three zones composed of this facies probably con-
249 stitute the primary reservoirs. Several nonreservoir li-
250 thologies separate the zones of good reservoir properties.
251 One common facies consists of thinly bedded sand-
252 stone to siltstone. The other common facies consists
253 of laminated to massive, very fine-grained, light-gray
254 sandstones.
255Geophysical logs show that the reservoir is divided
256into three main high-porosity zones (Figure 3). In cer-
257tain locations, one of the zones is further divided into
258two zones. Mineralogical analysis of the core shows that
259the good reservoir is a fine-grained, friable sandstone
260containing a preponderance of quartz, with lesser amounts
261of detrital K-feldspar and Na-rich plagioclase grains. The
262formation is cemented by prominent overgrowths of
263very pure euhedral, diagenetic K-feldspar and Mg-rich
264calcite (Figure 4). Any clays that may have been initially
265present were apparently obliterated by the diagenetic
266processes that gave rise to the K-feldspar and carbonate
267mineral overgrowths.
268A P-wave tomogram from the cross-well survey is
269shown in Figure 5. In addition to the tomogram, de-
270rived velocity logs (red) and measured velocities using a
271dipole sonic log (black) are also shown. The West Pearl
272Queen Formation is the low-velocity zone between
2734500- and 4600-ft (1371.6- and 1402.1-m) depth. The
274individual productive zones in the reservoir cannot be
275distinguished with the cross-well survey.
276As mentioned earlier, both sets of three-dimensional
277surface seismic surveys were used to interpret the geo-
278logical structure. Cross-equalization of the baseline and
279monitor seismic surveys was a critical part of the anal-
280ysis. Figure 6 shows the reservoir interval on the base-
281line survey and both the matched and unmatched
282monitor surveys. Subtle differences are observed above
283the reservoir on the unmatched survey, and these dif-
284ferences were removed on the cross-equalized survey.
285The Queen Formation was interpreted as a trough be-
286tween 740 and 758 ms, representing the Seven Rivers–
287Queen lithofacies change from carbonate to siliciclastic
288rocks. The time-structure map and edge-detection maps
289created from the P-wave seismic data on the reservoir
290interval characterize a sand-filled incised paleochannel
291and some paleohighs associated with the dome struc-
292ture, as originally interpreted from the well data. The
293depth-structure map of the West Pearl Queen reservoir
294differs significantly from the time-structure map, show-
295ing an anticlinal structure to the east of the CO2-
296injection well (Figure 7). Figure 8 shows the RMS (root-
297mean-squared) amplitude map. Both the cross-well
298survey and RMS amplitude map show that the res-
299ervoir is heterogeneous between wells Stivason Federal
3004 and Stivason Federal 5.
301Outcrops of the Shattuck Member sandstones ap-
302proximately 50 mi (80 km) to the west but in the same
303position several miles landward of the Goat Seep reef
304contain two prominent and consistent fracture sets, but
305neither core nor well tests indicate the presence or
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306 influence of natural fractures in the subsurface reser-
307 voirs of the West Pearl Queen field. Similarly, the seis-
308 mic data do not show the presence of any major faults in
309 the reservoir, suggesting that there are no structural
310 complications that would compartmentalize or divert
311 injected CO2.
312
313 Laboratory Experiments
314 To characterize the reservoir rock and fluids and to
315 understand the impact of CO2 on reservoir rock prop-
316 erties, two separate types of laboratory experiments
were performed.318
319 1. Static experiments: These experiments were per-
320 formed to characterize the geochemical interactions
321 between reservoir rock, formation brine, and CO2.
322 Injection of CO2 leads to lowering the pH of for-
323 mation brine and may initiate geochemical reactions.
324 The geochemical reactions could either lower for-
Figure 4. Scanning electron microscopy photograph of a WestPearl Queen reservoir rock sample prior to being exposed to CO2.Calcite cements and potassium feldspars are fresh and unaltered.
Figure 3. Comparison of core data and wire-line-log data for well Stivason Federal 1. Poor gamma-ray differentiation of unitsreflects the high potassium-feldspar content of the sandstones. Large sections of the core were missing by the time of this study, butrecords of the porosity and permeability data were found for some of the missing intervals. The three high-porosity zones depictedthat both the neutron and density porosity logs (right scale) have been used in the modeling effort. A 10–12-ft (3–3.6-m) depth shiftexists between the core and wire-line data.
AQ10
6 Overview of a CO2 Sequestration Field Test in the West Pearl Queen Reservoir
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325 mation porosity and permeability by precipitating
326 new minerals or increase porosity and permeability
327 by dissolving mineral phases. In the long term, geo-
328 chemical interactions can lead to chemical fixation
329 of CO2 in the form of a stable mineral phase. It is
330 crucial to determine what types of geochemical re-
331 actions are occurring as well as what the kinetics of
332 the reactions are. These questions were addressed by
333 a combination of laboratory experiments and nu-
334 merical modeling. The laboratory experiments were
335relatively short term (months) and were most ap-
336plicable to predicting what changes might have hap-
337pened in the field experiment time frame. During
338the experiments, a few tenths of a gram of sandstone
339was placed in a stainless-steel autoclave with 3 mL of
340formation brine, and subjected to 700 psig (4.8 MPa)
341of CO2 pressure at 40jC. After 19 months, both the
342fluid and rock samples were examined. The present-
343day indigenous brine is essentially a sodium (52 ppt)-
344chloride (109 ppt) brine, with lesser amounts of
Figure 5. Tomogram ofP-wave (center) and derivedand measured log velocities(sides) for preinjection cross-well survey between wellsStivason Federal 4 and Stiva-son Federal 5.
Figure 6. Cross section showing the West Pearl Queen res-ervoir based on the baseline and matched and unmatched moni-tor three-dimensional seismic survey.
Figure 7. Depth-structure map of West Pearl Queen reservoirbased on seismic two-way traveltimes converted to depth usingthe log-derived velocity model.
348 that the dissolved Ca levels had increased by 23%,
349 and that of Mg had increased by 35%. Dissolved sili-
350 con (not silica) dropped from 12.3 to 3.6 ppm,
351 whereas aluminum concentration increased from
352 0.05 to 0.33 ppm. Considering the amounts of alkali
353 metals (Ca, Mg) initially present in the brine relative
354 to the amounts of silicon and aluminum, it would be
355 reasonable to surmise that most of the short-term
356 changes in the formation chemistry would involve
357 the removal of the carbonate minerals. In fact, all of
358 the calcite and virtually all of the more Mg-rich dolo-
359 mitelike phase were removed during the course of
360 the experiment. Diligent examination of the sam-
361 ples, however, also revealed some etching of the
362 plagioclase feldspars, as well the beginning of clay
363 precipitation (Figure 9). The K-feldspars were not
364 affected by the treatment. The laboratory experi-
365ments suggested that dawsonite might not form
366during the field test. Early formation of clays was
367relatively slow compared to the duration of the field
368test. These results indicate that the probable geo-
369chemical alterations during the field test will not
370affect reservoir transport properties.
3712. Flowthrough experiments: These experiments were
372performed with samples from the reservoir core rep-
373resenting several possible producing zones (Table 1)
374to test for porosity, permeability to brine, and rela-
375tive permeability to brine and CO2 (the relative
376permeability measured in these experiments did not
377include three-phase relative permeability in the pres-
378ence of oil). As can be seen from Table 1, the per-
379meability varied from high to low within a short
380distance. Figures 10 and 11 represent the relative per-
381meability curves for core plugs at 4510.5 ft (1374.8 m)
382depth. Each of these measurements was performed
383at 114jF (45.5jC) and at two pore pressures, 500
384and 2000 psig (3.4 and 13.8 MPa). The differences
385in the two figures are primarily caused by differ-
386ences in pressure. The difference in pressure results
387in large differences in the density of CO2, solubility
388of water in CO2 and CO2 in brine, and surface ten-
389sion between the phases. Figure 12 shows changes
390in porosity and permeability with time because of
391the effects of two-phase flow of brine and CO2.
392The figure shows porosity and permeability versus
393pore volumes of fluid injected. It is interesting to
394note that, with time, porosity increased, whereas
395permeability decreased. A possible explanation for
396this could be that geochemical reactions with CO2
397have freed cemented fines that migrated and got
398stuck in pore throats, thus reducing the permeabil-
399ity. In each of the tests, the irreducible brine satu-
400ration was between 60 and 70% when using CO2
401to reduce brine saturation in a core 100% saturated
402with brine. Figure 13 shows the amount of brine
Figure 8. Root-mean-squared (RMS) amplitude map of theWest Pearl Queen reservoir. Variability in the amplitude rep-resents heterogeneity in the reservoir.
Figure 9. Scanning electronmicroscopy photographs ofWest Pearl Queen reservoir sand-stone after 19 months exposureto high-pressure CO2 gas. Thepotassium feldspars (left) havenot been affected, whereas thesodium and calcium feldsparshave started to etch (middle), andauthigenic clays derived fromdissolution of these componentshave started to form (right).
8 Overview of a CO2 Sequestration Field Test in the West Pearl Queen Reservoir
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of403 produced because of CO2 injection during a labo-
404 ratory core-flooding experiment. After 4000 cm3
405 (244 in.3) of CO2 (at reservoir conditions) had been
injected, 0.62 PVAQ12 of brine was left behind in sample
407 4532.5.
408
409 Numerical Simulations
410 Two types of numerical simulations were performed,
411 including flow simulations and geochemical reaction
412 simulations. The overall goal of numerical simulations
413 is to predict the long-term migration and the fate of
414 CO2 in the reservoir. The goal of the preinjection nu-
415 merical simulations was to characterize the reservoir-
416 flow dynamics, as well as the geochemical interactions.
417 Results of these simulations were used to understand
418the laboratory experiment results and to predict field
419experiment behavior.
4211. Reservoir-flow simulations. These simulations were
422performed to characterize the overall flow behavior
423of the reservoir. Preinjection simulations were also
424used to determine whether the proposed amount of
425CO2 could be injected in the target interval given the
426operational and regulatory constraints. The regula-
427tion required the injection to be performed at a rate
Table 1. Rock Properties from West Pearl Queen Reservoir
Core Samplest1.1
Core Depth (ft)
Permeability to
Brine (md) Porosity (%)t1.2
4508.9 < <1t1.3
4510.5 160 21.7t1.4
4511.2 15.8 18.1t1.5
4513.0 2.62 14.0t1.6
4532.5 117 20.5t1.7
4532.7 <1t1.8
Figure 10. Relative permeability curve for core plug 4510.5at 500 psig (3.45 MPa). The relative permeability to CO2 de-creases slightly as brine saturation increases.
Figure 11. Relative permeability curve for core plug 4510.5at 2000 psig (13.8 MPa). At higher pressures, the relativepermeability to CO2 decreases significantly as brine saturationincreases.
Figure 12. Change in core porosity and permeability duringCO2 injection in laboratory experiments. Permeability decreasedby more than 50%, possibly because of growth and migration ofclays, whereas porosity, initially increasing by several percentbecause of dissolution, stabilized.
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428 so that the bottom-hole pressure does not exceed the
429 rock-fracturing pressure. Based on the prevailing litho-
447 consider thermodynamic interactions between the
448 hydrocarbon components present in the reservoir.
449 Several simulation runs were performed to charac-
450 terize the reservoir response to varying injection
451 conditions. The simulations were run to model the
452 injection as well as subsequent soak and venting op-
453 erations of the field experiments. The simulation
454 results indicated that CO2 could be injected in the
455 reservoir at a rate of 100 tons/day (101.6 t/day) with-
456 out exceeding the bottom-hole pressure constraint.
457 It was also estimated that the CO2 plume would reach
458 the monitoring well (Stivason Federal 5) during the
4596-month soak period. Simulation of the venting op-
460eration suggested that about half of the injected CO2
461could be produced from the reservoir in the first
4626 months of venting.
4632. Geochemical simulations. Two types of numerical
464models were used to characterize the geochemical
interactions. The first model, REACT, AQ13was used to
466predict the most stable configuration of the system
467after equilibrium has been achieved along a reaction
468path with the steady addition of CO2. The second
numerical model, FLOTRAN AQ14, AQ15(Lichtner, 2003), was
470used to explore both short- (months) and long (more
471than 1000-yr)-term geochemical behavior.472
473The model REACT was used to study a system
474containing minerals and brine with compositions simi-
475lar to the reservoir rock and brine and in proportions
476closer to what may be present in the reservoir (Table 2).
477Model predictions showed that this system could result
478in precipitation of large amounts of dawsonite [NaAl-
479CO3(OH)] (Figure 14). In addition, kaolinite would
480be formed from the reaction of albite. The brine-to-
481mineral ratio was varied to more closely reflect the
482conditions in the laboratory experiments mentioned
483earlier. This system predicted reaction products similar
484to the ones observed in the laboratory experiments, in-
485cluding the early appearance of some clay, the dis-
486appearance of calcite, and the partial early attrition of
487albite (Figure 15). However, the results of the model,
488having a more formationlike rock-to-brine ratio, suggest
489that the appearance of clays in the laboratory experi-
490ments should not be taken as a potential indicator that
491they would appear either over the long term in a se-
492questration setting or in the short term in a field test.
493The most important part of these calculations is the
494ubiquitous prediction that significant amounts of daw-
495sonite will accompany the breakdown of feldspars.
Figure 13. Amount of brine produced during CO2 injectionin laboratory experiment for core 4532.5 (20 cm3 [1.22 in.3]�1 PV). The core was initially saturated with brine. Even afterinjection of almost 200 PV of CO2, a significant amount of brine(�0.63 PV) is left behind in the core.
Table 2. Proportion of Brine and Minerals Used for REACT
Simulations t2.1
Component Weight (kg) t2.2
Brine 1.0 t2.3
K-feldspar 1.9 t2.4
Quartz 10.3 t2.5
Albite 2.5 t2.6
Anorthite 12.5 t2.7
Calcite 0.15 t2.8
CO2 0.6 t2.9
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of496 Simulations with FLOTRAN were used to match ob-
497 servations of the laboratory experiment after 19 months.
498 To match the experiment results, values of the kinetic
constants at 25jC,AQ16 k25 (mol/cm2 s), and the mineral
500 surface areas (m2/g) were varied. Values of surface areas
501 and the reaction parameters were obtained from litera-
ture (Knauss and Woley, 1986;AQ17 Rimstidt and Barnes,
1980; Fetter, 1999; Xu et al., 2003, respectively).AQ18 Table 3
504 lists the allowed mineral phases and the associated var-
505 iable parameters used to generate the best fit to the
506 experiment. The initial water/rock ratio was set to 3.16.
507 Similar to REACT simulations, this system also re-
508 sulted in the formation of dawsonite. To match the labo-
509 ratory observations, the formation of dawsonite and
510 chalcedony had to be suppressed (to allow formation
511 beidelite-Na, which may be the clay mineral observed
512 in the SEM images in Figure 9), and the kinetic rate
513 constant, k25, for K-feldspar had to be reduced from
514 10�16 to 10�17 (mol/cm2 s). Figure 16 shows the pre-
515 and postexperiment major ion brine chemistry for both
516 the laboratory experiment and the simulated experi-
517 ment. Most of the experimental results are captured in
518 this simulation; however, we were not able to lower the
519 total Al3+ in solution to the levels seen in the ex-
520 periment. In addition, the simulations predict slightly
521 more aqueous SiO2 than that seen in the experiment.
522 This model was used to predict the long-term geo-
523 chemical behavior by performing a 1000-yr simulation.
524 For this model, the water/rock ratio was changed to
525 0.176, closer to that expected in the field. Figure 17
526 shows the time history of mineral formation and dis-
527 solution over 1000 yr. The results show that quartz,
528 dolomite, and kaolinite precipitate. Initially, calcite preci-
529pitates, but after 50 yr, it dissolves slowly. Potassium-
531tially precipitates until approximately 50 yr and then
532rapidly dissolves. Total porosity in the simulation drop-
533ped from 0.15 to 0.146, which implies that significant
534changes in the porous medium will not occur. The
535fugacity of CO2 dropped from 48.26 to a value of 0.31
536after 1000 yr. This means that the pure-phase CO2 has
537been converted into both minerals (calcite, dolomite,
538and kaolinite) and aqueous carbonate species.
539FIELD EXPERIMENT
540The central part of the project was the characterization
541of field response to CO2 through a field experiment.
542The field experiment consisted of three steps: injec-
543tion, soak, and venting. The total duration of the test
544from the beginning of the injection to the initial venting
545was about 11 months. Details of each of these steps
546follow.
547Injection
548The injection consisted of 2090 tons (2123.54 t) of
549CO2 over a period of 50 days, between December 20,
5502002, and February 11, 2003. As mentioned earlier,
551CO2 was injected through well Stivason Federal 4.
552Based on preinjection characterization, the expected
553rate of injection was about 100 tons/day (101.6 t/day).
554This rate was estimated based on the bottom-hole pres-
555sure upper-limit constraint of 2900 psi (19.9 MPa).
Figure 14. Calculation of minerals that would be formed be-cause of CO2 reaction with West Pearl Queen reservoir sand-stone and brine using a mineral-to-brine ratio similar to thatfound in the actual reservoir.
Figure 15. Calculation of minerals that would be formed be-cause of CO2 reaction with West Pearl Queen reservoir sand-stone and brine using a mineral-to-brine ratio similar to thatused in the laboratory experiment.
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556 During injection, the surface injection pressure quickly
557 reached 1400 psi (9.6 MPa). Based on the surface pres-
558 sure, the bottom-hole pressure was estimated to be about
559 2900 psi (19.9 MPa), and the surface injection pressure
560 was not increased above this value. The injection rate
561 was about 200 bbl/day, which translated to 40 tons/day
562 (40.64 t/day). This rate was significantly lower than the
563 preinjection estimates. The surface injection pressure
564 remained constant throughout injection, and the rate
565 of injection could not be increased. Figure 18 shows
566 the pressure, injection rate, and cumulative injected
567CO2 during the experiment. We also deployed passive
568seismic monitoring technique during injection. A re-
569ceiver array was deployed in well Stivason Federal 5,
570and the microseisms generated during injection were
571recorded. Analysis of the data did not show any signifi-
572cant microseismic events, suggesting that the injection
573rate was not high enough to cause any significant frac-
574turing. The lower-than-expected injection rate sug-
575gests that the reservoir permeability was lower than
576estimated, and that the reservoir pressure was higher
577than expected.
Table 3. Best-Fit Parameters Used for FLOTRAN Simulations of the Bench-Scale Experiment for All Mineral Phases Allowed in the
Figure 16. Comparison ofFLOTRAN results with geochemi-cal laboratory experiment re-sults after 19 months. Dawsoniteand chalcedony formation hadto be suppressed to make themodel (‘‘model’’) match the lab-oratory results (‘‘measured’’ and‘‘experiment’’).
12 Overview of a CO2 Sequestration Field Test in the West Pearl Queen Reservoir
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578 Soak
579 At the end of injection, a downhole pressure monitor
580 was deployed in the injection well, and the well was
581 shut in for 6 months. The pressure in the reservoir
582 was monitored intermittently. The measured reservoir
583 pressure is shown in Figure 19. As can be seen from the
584 figure, the pressure near the injection well did indeed
reach 2900 psi (197.2 atm)AQ19 . The pressure reached an
586 asymptotic value after the initial drop-off, indicating
587 that steady state was reached. The equilibrium pres-
588 sure value was about 1700 psi (115.6 atm), which was
589significantly higher than earlier predictions. Carbon di-
590oxide was allowed to soak for 6 months, at the end of
591which, another three-dimensional, multicomponent
592seismic survey was acquired. As mentioned earlier, this
593monitoring survey had the same attributes as the base-
594line survey.595
596Venting
597After acquisition of the postinjection seismic survey,
598CO2 was vented from well Stivason Federal 4. The well
599was connected to a separator and a fluid collection
Figure 17. FLOTRAN predictions ofgeochemical reaction products after1000 yr. Most changes occur within thefirst 150–200 yr, when kaolinite anddolomite precipitate while anorthite dis-solves. Beidellite-Na initially precipitatesbut then dissolves.
Figure 18. CO2-injection parametersduring field injection experiment. The in-jection rate stabilized at 40 tons/day(200 bbl/day), well below the expected100 tons/day, because injection pressureswere much higher than expected.
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of601 facility to monitor the amounts of fluids produced, as
602 well as to collect periodic samples for chemical anal-
603 yses. In addition, gas samples from well Stivason Fed-
604 eral 5 were also collected for chemical analyses. During
605 the initial venting period, the well produced fluids (gas
606 and liquids) without any pumping. This period lasted
607 for 9 days. After 9 days, the well stopped flowing, at
608 which point a pumping unit had to be installed to pro-
609 duce the well further. The well has been on continuous
610 production since that time and is currently on produc-
611 tion. Figure 20 shows the amount of gas produced from
612 the well for the first 3 months of venting and pro-
613 duction. The daily rates of production of oil and water
614 for the first 3 months of production are plotted in
615Figure 21. The gas production rates were significant-
616ly lower than the CO2-injection rates. During the first
6173 months of venting, only 17% of the total injected
618CO2 was produced. The amounts of oil and water pro-
619duced during venting and subsequent production phase
620were similar to production from the well during the
621pre-experiment days when it was actively produced.
622Figure 22 is a plot of the overall gas compositions of
623the samples collected from well Stivason Federal 4 dur-
624ing the venting and subsequent production operations.
625Figure 23 shows the trend in % CO2 in the gas pro-
626duced from Stivason Federal 4 until December 2004.
627Similarly, Figure 24 shows a plot of the gas composition
628of the samples collected from well Stivason Federal 5.
Figure 19. Bottom-hole pressure inwell Stivason Federal 4 during the post-injection soak period, showing that thereservoir pressure was nearly stabilized atequilibrium 2 months after shut-in.
Figure 20. CO2 production from wellStivason Federal 4 during the postsoakventing operation. Open-flow rates dimin-ished rapidly during the first 200 h or9 days of venting, after which, it wouldnot flow. A pump was subsequently in-stalled on the well, and production reachednear equilibrium about 1 month afterventing first began.
14 Overview of a CO2 Sequestration Field Test in the West Pearl Queen Reservoir
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629 The pre-CO2-injection gas from the reservoir had less
630 than 1% CO2, whereas the gas samples collected from
631 well Stivason Federal 4 during the venting operation was
632 in the range of 95–99 mol% CO2 through June 2004.
633 The last two samples taken in October and December
634 2004 had 87.9 and 89.9 mol% CO2, respectively. Sam-
635 ples from well Stivason Federal 5 do not show any pres-
636 ence of CO2, which indicates that CO2 had not mi-
637 grated to well Stivason Federal 5 until December 2004.
638 The oil and water production data from well Stivason
639 Federal 5 and Sun Pearl 2, which are the only two ac-
640 tively producing wells from the West Pearl Queen res-
641 ervoir interval, indicate that production from these
642 wells has not been affected after the CO2-injection
643 experiment.
644Geophysical Monitoring
645As mentioned earlier, we used a time-dependent, three-
646dimensional seismic survey to monitor the CO2 plume
647in the reservoir. So far, only the P-wave data have been
648processed, whereas interpretation of the S-wave data
649is still in progress. The P-wave seismic difference vol-
650ume shows time-lapse amplitude anomalies in the res-
651ervoir interval east and southeast of the injection well.
652Figure 25 is a map of the RMS amplitude difference
653between the baseline and matched monitor survey over
654the West Pearl Queen reservoir interval. The contours
655that are overlain are the West Pearl Queen reservoir
656depth structure with a contour interval of 4 ft (1.22 m).
657The interpreted CO2 distribution is highlighted and
Figure 21. Water and oil productionfrom well Stivason Federal 4 during thepostsoak venting operation. The jumpin water production subsequent to theinstallation of pump is caused by theaccumulation of water during the shut-inperiod, during which the pump wasinstalled.
Figure 22. Composition of gasproduced from well StivasonFederal 4 during CO2 ventingoperation, showing the dramaticincrease in CO2 over the orig-inal gas compositions prior toinjection.
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of658 contained in the thicker, higher quality sands near the
659 crest of the subtle anticline. The extent of the CO2
660 plume as shown in the figure is consistent with ob-
661 served CO2 migration, based on production response
662 from the wells in the vicinity, as well as the gas com-
663 position analyses from well Stivason Federal 5. The
664 plume is also consistent with the reservoir structure
665 and sand continuity between wells Stivason Federal 4
666 and Stivason Federal 5. Analysis of seismic data also
667 shows that CO2 has not migrated to formations other
668 than the West Pearl Queen reservoir.
669 SUMMARY AND CONCLUSIONS
670 The observations and experimental results show that
671 extensive reservoir characterization is necessary to un-
672 derstand and predict the impact of CO2 injection on
673 storage reservoirs. The response of the West Pearl Queen
674reservoir during the field experiment was significantly
675different than expected based on the preinjection char-
676acterization.
677First, the observed CO2-injection rate was much
678lower than the estimates based on earlier characteriza-
679tion work. This indicates that the permeability of the
680reservoir to CO2 injection is significantly different than
681the laboratory values measured on core samples prior to
682this project. The static and dynamic laboratory experi-
683ments showed that geochemical interaction between
684CO2 and West Pearl Queen sandstone could result in
685the migration of fines and decreased permeability, al-
686though more research is necessary to confirm that per-
687meability changes observed in cores and in the field are
688the result of the same process. Second, the log analyses
689indicated that West Pearl Queen reservoir is continu-
690ous between the injection well (Stivason Federal 4) and
691the monitoring well (Stivason Federal 5). Numerical
692simulations with models based on the log analyses
Figure 23. CO2% in the gasproduced from well StivasonFederal 4 decreased with timeduring CO2 venting operation.
Figure 24. Composition of gas producedfrom well Stivason Federal 5. Mole %of CO2 in the produced gas from this wellindicates that injected CO2 has not mi-grated to the well until at least December 8,2004, approximately 2 yr after CO2 injec-tion began in well Stivason Federal 4.
16 Overview of a CO2 Sequestration Field Test in the West Pearl Queen Reservoir
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693 indicated that response of CO2 injection in well
694 Stivason Federal 4 would be observed in well Stivason
695 Federal 5 in about 6 months. However, the observed
696 production response during the field experiment as
697 well as the geologic interpretation based on the seismic
698 data imply that the reservoir is not continuous between
699 the two wells. Comparison of the structure contours in
700 Figure 2 (which were generated from well-log picks)
701 and the structure interpreted from geophysical data
702 (Figure 7) suggests that the reservoir geologic hetero-
703 geneity is not completely captured with analyses based
704 on the log data alone. This project clearly demonstrates
705 the importance of capturing the interwell heterogeneity
706 for monitoring purposes. Third, the rate of produc-
707 tion and the cumulative production during the initial 3
708 months of venting were significantly lower than ex-
709 pected. This indicates possible formation damage near
710 the wellbore. It is also possible that the injected CO2
711 dissipated away from the wellbore during the soak pe-
712 riod into porosity not connected to the monitoring and
713 production well.
714 Geophysical monitoring using P-wave analysis of
715 the three-dimensional multicomponent seismic data
716 shows an anomaly that may indicate the presence of
717 CO2. We are currently analyzing S-wave data to sup-
718 port this conclusion. This study shows the applicability
719 of the surface seismic method for detecting a CO2
720 plume, although the amount of CO2 injected was small
721 and individual zones were thin.
722 The laboratory experiments also provided some
723 valuable results. Although dawsonite is a potential geo-
724 chemical reaction product in sandstone reservoirs, this
725mineral was not formed during the laboratory experi-
726ments. Understanding the kinetics of dawsonite forma-
727tion is critical for sequestration in sandstone reservoirs
728for two reasons. First, dawsonite is an important sink for
729CO2, and second, its formation can also lead to irrevers-
730ible and potentially damaging changes in reservoir prop-
731erties such as permeability and porosity.
732The results described in this study provide a basis
733that can be used to perform further studies to evaluate
734depleted oil reservoirs as a sequestration option. Our
735conclusions, combined with those of additional obser-
736vations in this and other similar studies, should allow
737predictions on the long-term fate of CO2 in depleted
738sandstone oil reservoirs.
REFERENCES CITED AQ20
740Fetter, C. W., 1999, Contaminant hydrogeology: Upper Saddle741River, New Jersey, Prentice-Hall, 171 p.742Holley, C., and J. Mazzullo, 1988, The lithology, depositional envi-743ronments, and reservoir properties of sandstones in the Queen744Formation, Magutex North, McFarland North, and McFarland745fields, Andrews County, Texas, in B. K. Cunningham, ed., Perm-746ian and Pennsylvanian stratigraphy, Midland Basin, west Texas:
Studies to aid hydrocarbon exploration: PBS-SEPM AQ21Research748Seminar No. 1, Publication 88-28, p. 55–63.749Knauss, K. G., and T. J. Wolrey, 1986, Dependence of albite750dissolution kinetics on pH and time at 25jC and 70jC:751Geochimica et Cosmochimica Acta, v. 50, no. 11, p. 2481–7522497.753Lichtner, P. C., 2001, FLOTRAN user manual. LA-UR-01-2349:754Los Alamos, New Mexico, Los Alamos National Laboratory,755172 p.756Malicse, A., and J. Mazzullo, 1990, Reservoir properties of the desert
Figure 25. A map of RMS (root-mean-squared) amplitude difference betweenbaseline and monitor three-dimensional,multidimensional surveys. The differ-ence between the pre- and postinjectionmaps is taken as an indication of theprobable location of the injected CO2.
Pawar et al. 17
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757 Shattuck Member, Caprock field, New Mexico, in Barwis,McPherson, and Studlick,AQ22 eds., Sandstone petroleum reser-
759 voirs: Casebooks in earth science: New York, Springer-Verlag,760 p. 133–152.761 Mazzullo, J., A. Malicse, and J. Siegel, 1991, Facies and depositional762 environments of the Shattuck Sandstone on the northwest shelf763 of the Permian Basin: Journal of Sedimentary Petrology, v. 61,764 p. 940–958.765 Mungan, N., 1992, Carbon dioxide flooding as an enhanced oil
766recovery process: Journal of Canadian Petroleum Technology,767v. 31, p. 13–15.768Rimstidt, J. D., and H. L. Barnes, 1980, The kinetics of silica-water769reactions: Geochimica et Cosmochimica Acta, v. 44, no. 11,770p. 1683–1699.771Xu, T., J. A. Apps, and K. Pruess, 2003, Reactive geochemical772transport simulation to study mineral trapping for CO2
773disposal in deep arenaceous formations: Journal of Geophys-774ical Research, v. 108, no. B2, p. 2071.
18 Overview of a CO2 Sequestration Field Test in the West Pearl Queen Reservoir
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ofAUTHOR QUERIES
AUTHOR PLEASE ANSWER ALL QUERIES
AQ1 = Please note that the use of "tons" (long, UK) and "metric tons" (metric tons in AAPG format is abbreviated
as "t") may be a little confusing. Please provide an alternative value for "tons."
AQ2 = Please check if the address of the affiliation is correct.
AQ3 = Please provide the vita of author Warpinski.
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AQ7 = Please note that according to AAPG format, entries within a list must be made consistent with each other.
In this list, the first and last entries were made up of one sentence. Thus, this entry was changed to one
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taking note that the entries must be consistent with each other.
AQ9 = The reference "Holley and Mazzullo, 1998" is not present in the Reference list. Should this be "Holley and
Mazzullo, 1988?" What is the correct year?
AQ10 = Figure is poor in quality with unsharp text and lines and unreadable data. Please provide figure of better
quality, if possible.
AQ11 = Figure is poor in quality with unsharp text and lines and unreadable data. Please provide figure of better
quality, if possible.
AQ12 = Please clarify what the unit PV is.
AQ13 = Please provide the meaning of "REACT" if it is an acronym.
AQ14 = Please provide the meaning of "FLOTRAN" if it is an acronym.
AQ15 = The reference "Lichtner, 2003" is not present in the Reference list. Should this be "Lichtner, 2001?"
What is the correct year?
AQ16 = C was changed to jC. Correct unit?
AQ17 = The reference "Knauss and Woley, 1986" is not present in the Reference list. Should this be "Knauss and
Wolrey, 1986?" What is the correct spelling of the second author’s name?
AQ18 = According to AAPG format, reference citations must be ordered chronologically (from earlier date first to
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reference citations (referring to the "respectively") seems to be a bit confusing. Please clarify the citations
as to what or where they correspond to.
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atmospheres. Please make use of only one set of conversion values.
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and Wolrey, 1986"; "Lichtner, 2001."
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