CSUG/SPE 147544

Field Testing and Numerical Simulation of Combined CO2 Enhanced Oil Recovery and Storage in the SACROC Unit Chongwei Xiao1, Milton Lee Harris1, Fred Wang2, Reid Grigg1 1Petroleum Recovery Research Center, New Mexico Institute of Mining and Technology 2Bereau of Economic Geology, the University of Texas at Austin

Copyright 2011, Society of Petroleum Engineers This paper was prepared for presentation at the Canadian Unconventional Resources Conference held in Calgary, Alberta, Canada, 15–17 November 2011. This paper was selected for presentation by a CSUG/SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abstract The SACROC Unit in the Permian Basin has been under carbon dioxide (CO2) injection for enhanced oil recovery (EOR) for almost forty years since CO2 injection commenced in 1972. The mature CO2 operations in the SACROC Unit make it an optimal site for studying CO2 sequestration in conjunction with EOR. A pilot demonstration project was performed in a five-spot pattern, beginning at the end of 2008. The objective of this study is to understand the capacity and flow patterns of the CO2 plume to determine sequestration potential in conventional oil reservoirs. The pilot site locates in the Northern SACROC platform and was set up as a five-spot pattern consisting of 4 injectors and 1 center producer. Water and CO2 injection had occurred earlier in the SACROC Unit during reservoir development. The pilot testing started in 2008 and has been under CO2 injection since then. After thirteen months of CO2 injection, the production data from the pilot showed that the oil production rate of the producer (well 56-17) increased over tenfold during the first year of CO2 injection which demonstrated significant enhanced oil recovery by CO2 injection. This paper describes how the injection process in the SACROC pilot was simulated using a compositional simulator, Computer Modeling Group’s GEM. A simulation model with 47,104 grids was developed with geophysical data characterized from 3D seismic surveys and well logs. The simulation area is 6640 ft * 6640 ft * 840 ft, consisting of five wells in the pilot site. History matching gas, oil, and water production for each well since first drilled was performed to verify the model. The EOR under three injection schemes was predicted. The CO2 storage capacity under residual and solubility trapping mechanisms during CO2 miscible displacement was simulated and analyzed. This study demonstrated CO2 sequestration in oil reservoirs to be a low-risk, promising method for mitigating CO2 discharge into the atmosphere. Key words: CO2, EOR, storage, oil reservoir, sequestration Introduction The SACROC Unit in the Permian Basin has been under carbon dioxide (CO2) injection for enhanced oil recovery (EOR) for almost forty years since CO2 injection commenced in 1971. The mature CO2 operations in the SACROC Unit make it an optimal site for studying CO2 sequestration in conjunction with EOR. For the field demonstration by the Southwest Regional Partnership on Carbon Sequestration (SWP), a five-spot pattern pilot at the northern edge of the SACROC Unit underwent CO2 injection and CO2 monitoring instruments were set up. A large slug of CO2 was injected into four injectors (wells 56-4, 56-6, 58-2, and 59-2 in Figure 2) in a five-spot pattern over a period of thirteen months. The maximum oil production rate of well 56-17 between 1984 (start of production) and 1998 (well shut in) was 41 bbl/d. During the 30-days initial water injection before the start of CO2 injection in 2008, oil production was 9 bbl/d. The production rate increased to 590 bbl/d within one year after CO2 injection started. During this pilot test for thirteen months, 116,591 STBO and 198,658 MCF HC gas were produced, most of which is from enhanced oil recovery by CO2 injection. This work examines the combination of CO2 sequestration and EOR at SACROC as a long-term goal.

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Cross-section model with homogeneous properties (Brummett et al., 1976,Dicharry et al., 1973,Graue and Blevins, 1978,Langston et al., 1988). Recently, a simulation for history matching has been done with a black-oil model (Gonzalez et al., 2008). Also Weon Shik Han (Han et al., 2010) did simulation studies on the SACROC with the CMG’s compositional simulator to evaluate CO2 sequestration in two artificial models: a reservoir saturated with brine and a reservoir saturated with both brine and oil. The brine-only model shows a distinctive set of storage stages: hydrostratigraphic trapping in first stage (-30years duration), residual trapping in the second stage (-15 years duration), solubility trapping in the third stage (extending hundreds of years), and mineral trapping in the final stage (after thousand years). The major CO2 trapping mechanisms were hydrostratigraphic (mobile), residual and solubility trapping over the first 200 years. For the brine-oil model, the CO2 trapping mechanisms did not vary much over time. Both oil trapping and hydrodynamic (mobile) trapping dominated in the first 200 years. The limitation of this work lies in that the reservoir fluid is artificial and there is no history match.

Site Description The pilot site locates in the Northern SACROC platform and was set up as a five-spot pattern consists of four injection (58-2, 59-2A, 56-4A, and 56-6A), one center production (56-17) wells are shown in Figure 2. The geological properties of the site have been described by other researchers (Brummett, 1976,Dicharry, 1973,Vest, 1970). A cross-section of geologic structure and stratigraphy of the study area is shown in Figure 1. The oil at SACROC is produced from the Pennsylvanian age Canyon and Cisco Formations(Vest, 1970). The Wolfcamp shale of the lower Permian acts as a seal for this oil zone (Raines et al., 2001).

Geological model The geological model was set up by Fred Wang of the Bureau of Economic Geology at The University of Texas at Austin (BEG). The geological model is heterogeneous with permeability ranging from 0 to 401.7 mD and porosity ranging from 0 to 25%. The simulation area is 6640 ft wide and 6640 ft long and 840 feet thick. This area contains the five well pilots and surrounding area. The surrounding area was included as a buffer zone that has injection and production wells, but the other wells were not included in this study. This was used as a buffer area. It was assumed for these tests that 25% of the injected fluids flowed into the pilot area with the other 75% going to the surrounding patterns. The geological model with 32*32*46 (47,104) grids with elevation, porosity and permeability are shown in Figures 3, 4 and 5, respectively. The actual pilot area covers 7*7*46 (2254) grids near, but off centered in the simulation area.

Simulation Data Input Reservoir geophysics The reservoir geophysical properties published (Brummett et al., 1976; Dicharry, 1973; Vest 1970.) are given in Table 1. The reservoir boundary is assumed no-flow boundary conditions.

Fluid There is no gas cap in the reservoir according to Vest (Vest, 1970). The reservoir oil samples were taken from the pilot site and measured by GC (Varian CP-3800). The fluid composition is shown in Figure 6. The fluid properties were analyzed and lumped as six components by PVTsim, a fluid simulator; these are listed in Table 2. The minimum miscibility pressure (MMP) between CO2 and the reservoir fluid were calculated by PVTsim using the Peng-Robinson (PR) equation of state with Peneloux temperature modification options. The multi contact miscibility pressure was predicted to be 1687 psia at 132 °F. The MMP data is consistent with the experimental data obtained by Dicharry (Dicharry, 1973), who determined that the reservoir pressure must be at least 1,614 pisa to assure miscible displacement through multiple contact. The saturation pressure of the original reservoir oil was 1,950 psia. The CO2 solubility in aqueous phase was modeled by Henry’s law (Li and Nghiem, 1986).

Relative permeability Previously reported laboratory results (Brummett, 1976) verified residual oil saturation by water displacement of 26.1%. Experimental work performed by the Anderson et al. (Anderson et al., 1954) established an average irreducible water saturation of 17.7%. These values were used as the endpoints of the water-oil relative permeability relationship. The water/oil relative permeability curves used in this work are shown in Figure 7.

Simulation results discussion The reservoir performance under stimulation and CO2 migration status was simulated by a compositional simulator, CMG’s GEM. The fluid properties were tuned by PVTsim and CMG’s Winprop. History match The history match was accomplished with two main constraints: one specifies oil rate SC (surface rate) production and matches the gas production and water production, the other specifies gas rate SC (surface rate) and matches the oil production

Several simulations have been performed for the SACROC northern platform. Early simulation used an artificial model or

and water production.

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The history production and injection data for five wells were provided by Kinder Morgan. The original oil in place (OOIP) in the reservoir was estimated at 144.252 MM STB for the whole simulation area and 30.223 MM STB for the pilot area. Among five wells, only well 56-6 was continuously operated while the other four wells were closed after a short production period. Cumulative production of the five wells from the pilot area through 2008 was 2.746 MM STB (9.09 % OOIP) and 3.121 BCF HC gas (0.52 MM BOE). The primary recovery was low with quick pressure drop because the drive mechanism was solution gas drive. Well 56-6 has the longest production history among five pilot wells (1949-1998), thus during this production period the bottomhole pressure (BHP) for well 56-6 was tracked in the simulation; this remained throughout within the range of 2500–3100 psi. During primary recovery the pressure of 56-6 dropped quickly during the first several months to about 2500 psi.

Figures 8 and 9 present the history matching of the actual versus simulated gas and water production rate with STO as the main constraint. The history matches for gas rate SC are good: well 56-6 has cumulative gas production of less than 1% difference with history data; wells 56-4 and 59-2 are good in trend and with cumulative gas production deviation below 30%; wells 56-17 and 58-2 are good in trend but have a larger deviation. The history match for water rate SC (only three wells have water production) are acceptable considering that produced water values are generally the less accurate of the produced fluid measurements. The cumulative water production of wells 56-4 and 56-6 are about 25% different from history data. Figures 10 and 11 present the history matching of the actual versus simulated oil and water production rate with STG as the main constraint. The history matches for oil rate are good: well 56-6 has cumulative oil production with only 7% difference from history data; wells 56-17 and 56-4 are good in trend and with cumulative gas production deviation of about 16%; wells 58-2 and 59-2 have good trend with about 25% difference from history data. The history match for water rate SC are poor with cumulative water production at about 50% difference from history data. Prediction of oil recovery by CO2 injection Operationally 12.13 BCF of CO2 was injected into four injectors 56-4, 56-6, 58-2, and 59-2 in a five-spot pattern from September, 2008 to September, 2009. The first assumption is that 25% of this or 3.033 BCF CO2 flowed toward the center well production well and the other 75% to surrounding wells. The maximum oil production rate of well 56-17 was 41 bbl/d before CO2 re-injection and 590 bbl/d within one year after CO2 re-injection, respectively. Before CO2 injection, the cumulative oil production from 56-17 was 83,758 STB during the earlier production period of 1984-1998. After CO2 injection, residual oil was displaced by CO2 with production of 116,591 STB oil, 198,658 MCF HC gas, 1,884,714 B brine, and 1,803,621 MCF CO2. The comparison of the injection and production are shown in Table 3. The assumption that 25% of the CO2 went into the center pattern during this time does not appear correct. The production/injection ration would be over 2, thus 50% or more may be more accurate. The CO2/produced oil ratio is 26 MCF/STBO at the end of the thirteen-month operation. The oil recovery during 50 years by CO2 injection is predicted with three CO2 injection rates with water co-injection shown in Table 4. The predicted oil rate SC and cumulative oil production are shown in Figures 12 and 13. During the injection period, the oil rate quickly reached the maximum rate. After CO2 injection, the oil rate increased slightly about twenty years and then decreased. The cumulative oil production increased with the CO2 injection rate. After 50-year injection period, the oil recovery of the pilot area under three CO2 injection rates is 1.2256MM STB, 1.5531 MMSTB, and 2.7256 MM STB, corresponding to 4.06 %, 5.14 % and 9.02 % OOIP. Considering that the CO2 injection amounts correspond to 8.4 %, 16.8 % and 42.22 % HCPV of pilot area, the stimulation of CO2 injection is more efficient at a lower injection rate.

CO2 storage The pilot data for CO2 production under CO2 injection during the thirteen-month period is plotted in Figure 14. CO2 breakthrough occurred about one month after the start of injection. For the pilot test, 40.53% to 70.28% of the total injected CO2 was stored in the reservoir after thirteen-months of operation, respectively if 3.033BCF to 6.033 BCF CO2 were estimated to be injected into the pilot area. According to the material balance analysis in the pilot area, it appears that over 50% and up to 70% of the total injected CO2 was stored in the reservoir. The simulation of CO2 storage in the reservoir was carried out until the end of 2209 or for a period of 200 years after CO2 injection ended. CO2 productions under three different injection rates were predicted as show in Figures 15. Under the three different CO2 injection rates, 23.4%, 31.1% and 41.7% CO2 were produced over 20-year period and no production since then. CO2 was continuously produced at a decreasing rate, with a total production of 41.7% at the highest injection rate. Thus more than 50% of the injected CO2 was stored in the reservoir which is significant for CO2 EOR and sequestration projects. By increasing viscosity and lowering the mobility, CO2 storage would be increased in the active operation area.

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Supercritical CO2 storage in the reservoir under free and residual sequestration mechanisms after CO2 injection at three different CO2 injection rates is plotted in Figures 16. The CO2 storage by dissolution in the aqueous phase was only about 0.2% and was not included in the Figure 16. CO2 sequestration comparison at the end of injection, 50 years, 100 years and 200 years after CO2 injection at the first injection rate are shown in Figure 17. The sequestration of CO2 due to residual trapping ranges between 18-30%. It increased by the end of 20 years of production trapped gradually by reservoir pores and then decreased. The sequestration of CO2 in brine was about 0.2% due to low brine saturation. During the time frame considered, it is predicted that over 70% of the CO2 stored in the reservoir will be by dissolution into the oil phase. Conclusions This work studied the combined EOR and CO2 storage under different sequestration mechanisms after CO2 injection in an oil reservoir. The history matching was performed to verify the model. In general, the history matching results of oil and gas were good. The brine production history match was less accurate, which may have been due to errors in the water production records. Enhanced oil recovery by CO2 injection was predicted to be 4.06 %, 5.14 % and 9.02 % OOIP with 8.4 %, 16.8 % and 42.22 % HCPV CO2 injection during one year and observed for 200 years, respectively. It is estimated that during a 200-year period after CO2 injection, more than 50% of the injected CO2 remains stored in the reservoir under the three CO2 injection rates studied. CO2 sequestration could be increased by decreasing the mobility of CO2 and/or increasing the viscosity of CO2. During the 200-year post injection period, over 70% of the stored CO2 was dissolved in the oil phase; about 18-30% was stored by residual trapping; and relatively little dissolved in the aqueous phase. Thus the primary sequestration/storage mechanism in oil reservoirs is CO2 dissolution into the oil phase. Acknowledgements Most of this work was performed under agreement DE-FC26-05NT42591 between the SWP and the United States Department of Energy (DOE) through the National Energy Technology Laboratory (NETL) and thus acknowledge their contribution and also thank the DOE/NETL Staff for their support and individual comments and suggestions from their staff. We thank Kinder Morgan Production Company LLC, especially Merle Steckel for providing production and injection history data for the pilot area. References

Anderson, K. F.,Meadows, P.,Hawkins, M., E.,andElliott, W. C. J. Petroleum-Engineering Study of Scurry Reef Reservoir, Scurry County, Texas, Petroleum Engineer,August, 1954.

Brummett, W. M. J.,Emanuel, A. S.andRonquille, J. D. Reservoir Description by Simulation at SACROC - A Case History, SPE Journal of Petroleum Technology, SPE 5536, 1976, 28(10), 1241-1255.

Dicharry, R. M.,Perryman, T. L.andRonquille, J. D. Evaluation and Design of a CO2 Miscible Flood Project-SACROC Unit, Kelly-Snyder Field, SPE Journal of Petroleum Technology, SPE 4083, 1973, 25(11), 1309-1318.

Gonzalez, R. J.,Eslinger, E.,Reeves, S. R.,Schepers, K. C.andBack, T. Integrated Clustering/Geostatistical/Evolutionary Strategies Approach for 3D Reservoir Characterization and Assisted History-Matching in a Complex Carbonate Reservoir, SACROC Unit, Permian Basin, SPE/DOE Symposium on Improved Oil Recovery, Tulsa, Oklahoma, USA, SPE 113978, 2008,

Graue, D. J.andBlevins, T. R. SACROC tertiary CO2 pilot project, the Fifth Symposium on Improved Methods for Oil Recovery of the SPEof AIME, Tulsa, Oklahoma, SPE 7090, 1978,

Hall, H. N. Compressibility of reservoir rocks, Trans.,, AIME, 1953, 198, 309-314.

Han, W. S.,McPherson, B. J.,Lichtner, P. C.andWang, F. P. Evaluation of trapping mechanisms in geologic CO2 sequestration: Case study of SACROC northern platform, a 35-year CO2 injection site, American Journal of Science,April 2010, 310, 282-324.

Langston, M. V.,Hoadley, S. F.andYoung, D. N. Definitive CO2 flooding response in the SACROC unit, the SPE/DOE Enhance Oil Recovery Symposium Tulsa, Oklahoma, SPE 17321, 1988,

Li, Y.-K.andNghiem, L. X. Phase equilibria of oi, gas, and water/brine mixtures from a cubic equation of state and Henry's law, Canadian Journal of Chemical Engineering, 1986, 486-496.

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Raines, M. A.,Dobitz, J. K.andWehner, S. C. A review of the Pennsylvanian SACROC Unit. In J.J. Viveros and S.M. Ingram, eds., The Permian basin: Microns to satellites, looking for oil and gas at all scales., West Texas Geological Society Publication 2001, 91- 89, 39-66.

Vest, E. L. J. Oil Fields of Pennsylvanian-Permian Horseshoe Atoll, west Texas in Halbouty, Michael T. (ed.) Geology of Giant Petroleum Fields, AAPG Memoir N14, American Association of Petroleum Geologists, Tulsa, Oklahoma, 1970, 185-203.

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Table 1 Reservoir geophysical properties

Initial reservoir pressure (-4300 ft), psia 3122 Reservoir temperature (-4300 ft),

°F 132

Reference depth, ft 4300 Initial water saturation, pore space, % 36

Water/Oil contact (subsea), ft -4500 Residual gas saturation, % 38.5

Average residual oil saturation, pore space, % 26

rock compressibility @3137 psia(Hall, 1953) 5.6e-6 1/k Pa Formation volume factor, Bo 1.472

Table 2 Fluid properties used in the simulation

Component 1 (CO2) 2 (C1+N2) 3 (C2-4) 4 (C5-6) 5(C7-10) 6 (C11+)

Composition, mol% 0.32 29.48 31.5 10.15 16.16 12.39

Molecular weight 44.01 16.38 42.552 80.291 112.808 212.27

Liquid density, g/cm3 0.6468 0.7697 0.8425

Critical T, °C 31.05 -85.651 98.117 219.537 292.693 423.121

Critical P, bar 73.76 45.42 42.47 31.22 28.24 17.96

Bubble-point pressure (at 132 F), psia

Reservoir fluid viscosity at 1820 psia and 130 F, cp

Reservoir fluid density at 1820 pisa and 132F, lb/cu ft

Reservoir fluid density,

API

Water viscosity, cp

1850 0.38 42.2 41.8 0.51

Table 3 Material balance

Production FVF RB Oil

Gas 116,591 BO

198,658 MCF 1.472 171,622

Brine 1,884,714 BBL 1.0 1,884,714 CO2

TOTAL 1,803,621 MCF

4.36e-4*

786,791

2,843,127 Injected CO2: % of total into pilot

pattern FVF RB

25% 3,033,000 MCF 4.36e-4 1,322,388 50% 6,066,000 MCF 4.36e-4 2,644,776

*FVF for CO2 assumes reservoir conditions of 132⁰F & 2890 psia, thus a CO2 density of ~0.75 g/cc.

Table 4 CO2 injection rate

56-4 56-6 58-2 59-2 Total injection

CO2 rate 1, MMCF 703.5 929.4 414.4 972.1 3019.4 (0.17 million tons)

CO2 rate 2, MMCF 1407 1858.9 828.7 1944.2 6038.8 (0.34 million tons)

CO2 rate 3, MMCF 3517.5 4647.2 2071.8 4860.5 15096.9 (0.85 million tons)

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Figure 1. A structural and stratigraphic cross-section of profile A-A’, located within the SACROC northern platform (Vest, 1970).

Figure 2. Injection, production, and monitoring wells comprising the SWP SACROC 56-17 injection pilot site

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Figure 3. The Grid Top with elevation of the pilot in the SACROC Unit

Figure 4. The porosity of the pilot in the SACROC Unit

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Figure 5. The permeability of the pilot in the SACROC Unit

Figure 6. The reservoir fluid composition in the pilot at the SACROC Unit

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Figure 7. Water-oil relative permeability

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Figure 8. Five wells gas production history match with STO

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Figure 9. Three wells water production history match with STO

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Figure 10. Five wells oil production history match with STG

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Figure 11. Three wells water production history match with STG

Figure 12. Prediction of oil rate SC (surface condition) at different CO2 injection rates

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Figure 13. Prediction of cumulative oil production at different CO2 injection rates

Figure 14. CO2 productions during the injection period

0

50000

100000

150000

200000

250000

300000

Jun‐08 Sep‐08 Dec‐08 Mar‐09 Jul‐09 Oct‐09 Jan‐10

CO2 Prod

uction

 rate, M

CF/m

on

CO2 production rate, MCF/month

CO2 …

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Figure 15. CO2 production prediction

Figure 16. CO2 storage in the reservoir under different sequestration mechanisms

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Figure 17. CO2 sequestration comparison under a 200-year period