Uncor

recte

d Pro

of

AUTHORS

Rajesh J. Pawar � Earth and EnvironmentalSciences Division, Los Alamos National Labo-ratory, MS T003, Los Alamos, New Mexico87545 AQ2; rajesh@lanl.gov

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;nrwarpi@sandia.gov

John C. Lorenz � Sandia National Labora-tories, Albuquerque, New Mexico;jcloren@sandia.gov

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; rbenson@mines.edu

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;reid@prrc.nmt.edu

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

Uncor

recte

d Pro

of

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; pecos@lookingglass.net

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;stauffer@lanl.gov

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;jlkrumh@sandia.gov

Scott P. Cooper � Sandia National Labora-tories, Albuquerque, New Mexico;scooper@sandia.gov

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

Uncor

recte

d Pro

of

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

Pawar et al. 3

Uncor

recte

d Pro

of183 five wells in the field. Of the five wells, currently, only

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

Uncor

recte

d Pro

of

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-

219 resolution, three-dimensional, nine-component surface

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

Pawar et al. 5

Uncor

recte

d Pro

of

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

Uncor

recte

d Pro

of

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.

AQ11

Pawar et al. 7

Uncor

recte

d Pro

of345 dissolved potassium (1.6 ppt), magnesium (3.1 ppt),

346 calcium (also 3.1 ppt), sulfate (1.8 ppt), and bicar-

347 bonate (0.12 ppt). Post-test fluid analysis showed

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

Uncor

recte

d Pro

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.

Pawar et al. 9

Uncor

recte

d Pro

of

428 so that the bottom-hole pressure does not exceed the

429 rock-fracturing pressure. Based on the prevailing litho-

430 static pressure gradient, 0.64 psi/ft (14.5 kPa/m),

431 and depth of the injection interval, this pressure was

432 determined to be about 2900 psi (19.9 MPa) at the

433 bottom hole. In addition, the simulations were also

434 used to determine the possible migration of CO2

435 after injection. A numerical model for the reservoir

436 was developed based on the geological characteriza-

437 tion. At the time the preinjection simulations were

438 performed, geophysical surveys were not acquired;

439 hence, only the data based on log and core analysis

440 were used to develop the flow model. The numerical

441 simulations were run using Eclipse, Schlumberger’s

442 oil reservoir simulator. The flow model was validat-

443 ed through matching the historic production data

444 and then used to perform CO2-injection simula-

445 tions. These simulations were performed using the

446 compositional module. Compositional simulations

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

10 Overview of a CO2 Sequestration Field Test in the West Pearl Queen Reservoir

Uncor

recte

d Pro

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-

530feldspar remains unaltered, whereas beidelite-Na ini-

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.

Pawar et al. 11

Uncor

recte

d Pro

of

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

Simulationt3.1

Surface Area

(cm2/g)

Log k 25

(mol/[cm2 s])

Initial Volume Fraction

Bench Scale

Initial Volume Fraction

Field Scale

Final Volume Fraction

Field Scale (pH = 6.6)t3.2

Albite 6 � 102 10�16 0.07 0.136 0.125t3.3

Anorthite 6 � 102 10�16 0 0.007 0.0t3.4

Quartz 5 � 102 10�17.9 00.129 0.587 0.591t3.5

SiO2 amorphous 1 � 105 10�15.6 0 0 0t3.6

K-feldspar 3 � 102 10�17 0.042 0.118 0.119t3.7

Magnesite 3 � 104 10�15 0 0 0t3.8

Kaolinite 3 � 105 10�17 0 0 1.18 � 10�2t3.9

Dolomite-dis 3 � 104 10�18.2 0.0001 4.25 � 10�4 1.85 � 10�3t3.10

Calcite 3 � 103 10�12.8 0.00043 1.53 � 10�3 3.82 � 10�3t3.11

Beidelite-Na 3 � 105 10�17 0 0 0t3.12

Gypsum 1 � 105 10�13 0 0 0t3.13

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

Uncor

recte

d Pro

of

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.

Pawar et al. 13

Uncor

recte

d Pro

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

Uncor

recte

d Pro

of

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.

Pawar et al. 15

Uncor

recte

d Pro

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

Uncor

recte

d Pro

of

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

Uncor

recte

d Pro

of

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

Uncor

recte

d Pro

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.

AQ4 = If possible, please provide the complete addresses of the affiliations.

AQ5 = Please provide a vita for author Krumhansl.

AQ6 = Is this running foot appropriate?

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

sentence by combining the two sentences and placing a semicolon between them. Please check.

AQ8 = According to AAPG format, entries within a list must be consistent with each other. In the former bulleted

list, the last entry was somewhat off because of the series of sentences that followed after the entry phrase.

Hence, the list was run in. Please check if it is correct. If not, please provide the appropriate changes,

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

most recent date last) and then alphabetically (from A to Z). This group of citations was not changed

according to the format because of the word "respectively." However, the correspondence of the

reference citations (referring to the "respectively") seems to be a bit confusing. Please clarify the citations

as to what or where they correspond to.

AQ19 = Please make conversions consistent. In the previous sections, you used pascals. Here you used

atmospheres. Please make use of only one set of conversion values.

AQ20 = Please indicate where in the text should these references be cited: "Holley and Mazzullo, 1988"; "Knauss

and Wolrey, 1986"; "Lichtner, 2001."

AQ21 = Please provide the meaning of "PBS" if it is an acronym. Permian Basin Section?

AQ22 = Please provide the first name initials of the editors.

END OF ALL QUERIES