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Evaluation of CO Storage Mechanisms in CO Enhanced Oil Recovery Sites: Application to Morrow Sandstone Reservoir William Ampomah, Robert Balch, Martha Cather, Dylan Rose-Coss, Zhenxue Dai, Jason E. Heath, Thomas Dewers, and Peter Mozley Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.6b01888 • Publication Date (Web): 15 Sep 2016 Downloaded from http://pubs.acs.org on September 15, 2016

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Evaluation of CO2 Storage Mechanisms in CO2 Enhanced Oil Recovery Sites: Application to Morrow Sandstone Reservoir ‡

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William Ampomah, * Robert Balch, Martha Cather, Dylan Rose-Coss , Zhenxue Dai, Jason ֆ ֆ ‡ Heath, Thomas Dewers, and Peter Mozley ‡ New Mexico Tech, Socorro NM 87801 † Los Alamos National Laboratory Los Alamos, NM 87545, USA ֆ Sandia National Laboratory, Albuquerque, 87185

Abstract This paper presents numerical simulations of CO2 storage mechanisms in the Pennsylvanian Upper Morrow sandstone reservoir, locally termed as the Morrow B sandstone in the Farnsworth Unit (FWU) of Ochiltree County, Texas. CO2 storage mechanisms considered in the study under a CO2 enhanced oil recovery (EOR) mode include structural-stratigraphic trapping, CO2 dissolution in formation water and oil, and residual trapping. The reservoir simulation model has been constructed based on field geophysical, geological, and engineering data such as 3D surface seismic, well logs, and fluid analysis. A representative fluid sampled from the reservoir was analyzed and used to tune the equation of state. A thermodynamic minimum miscible pressure was subsequently computed and compared to the experimental outcome. A history matched model was constructed and used as a baseline to ascertain the effect of different hypothetical injection strategies (which considers CO2 purchase, gas recycling and infill drilling), water alternating gas (WAG) schemes, and variable salinity on CO2 storage. Simulation results showed significant amount of stored CO2 was dissolved in residual oil, contributing to enhanced oil recovery from the tertiary stage of the field operations. Supercritical phase CO2 mass within the reservoir compared to CO2 dissolved in formation water was dependent on CO2 injection strategy. Residual trapping contribution was significant when hysteresis was considered. Pressure, volume of reservoir fluid present, cap rock integrity and optimized WAG injection strategies were significant parameters to determine long-term CO2 storage capacity within FWU. Cap rock integrity analyses show sealing units have excellent storage capacity with the potential to support column heights of up to 10,000 ft. This work shows an improved strategy of maximizing CO2 storage within a depleted oil reservoir. The results from this study show that pressure changes within the reservoir should be continuously monitored to enhance CO2 storage. This study serves as a benchmark for future CO2-EOR projects in the Anadarko basin or geologically similar basins throughout the world. Keywords: Trapping mechanism, Reservoir simulation, CO2 storage, Hysteresis, Sealing capacity and water alternating gas

1 Introduction The purpose of carbon capture, utilization, and storage (CCUS) is to reduce the amount of CO2 released into the atmosphere to help mitigate the effects of anthropogenic climate change 1-3. CO2 can be injected into structural reservoirs in deep geological formations such as depleted oil and gas reservoirs, saline aquifers and unmineable coal seams 4-8. Using CO2 for enhanced oil recovery (EOR) is common in the oil industry, but most of the CO2 is usually produced from natural, geological sources. CCUS uses anthropogenic sources of CO2 for EOR. This, together with other factors, motivated the US Department of Energy (DOE) to set up regional carbon sequestration partnerships with research institutions and operating companies to study injection of anthropogenic CO2 for storage and EOR in the United States 911 . The Southwest Regional Partnership on Carbon Sequestration (SWP) is one of such groups that is ACS Paragon Plus Environment

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working closely with an industry partner, Chaparral Energy, to ascertain the storage capacity of CO2 and its economic benefits within the Farnsworth Unit 12. CO2 injection into saline geological complex structures for storage has been studied for over two decades as an effective means of reducing CO2 emissions from the atmosphere 13-16. Numerous studies have focused on mitigating CO2 emissions by capturing and injecting CO2 into oil reservoirs for EOR 1724 . CO2 storage in depleted oil reservoirs has tremendous advantages due to economic incentives over other geological sequestration mechanisms currently available. In the oil industry, CO2 flooding has been utilized for about 50 years so the processes have been more thoroughly investigated than sequestration in saline aquifers or unmineable coal seams. Most often, the water alternating gas (WAG) process has been successfully used to improve sweep efficiency by delaying early CO2 breakthrough 25. Previous research identified four primary mechanisms of CO2 geological sequestration. These mechanisms including: structural-stratigraphic trapping, solubility trapping, residual gas trapping and mineral trapping 26-29. Structural-stratigraphic trapping involves the storage of CO2 in a supercritical state in through the effects, often combined, of reservoir stratigraphy and structure in a manner analogous to trapping in a hydrocarbon reservoir. CO2 is usually trapped below a low permeable formation such as shale or mudstones. This prevents the CO2 from migrating upward due to buoyancy. Structural-stratigraphic trapping can also be due to impermeable zones such as cap rocks and sealed faults. Prior to sequestration, cap rock integrity must be assessed for long-term sealing potential. Solubility trapping occurs when injected CO2 dissolve in formation fluids, including formation water and/or oil. The dissolution can occur in both the formation water and/or oil phase. Solubility of CO2 in formation water depends on pressure, temperature and salinity within the target formation 30. Solubility of CO2 in oil phase is mostly higher than that of brine in mature oil reservoirs. Residual trapping involves the storage of CO2 as an immobile phase within the porous media due to capillary forces. This is an important mechanism as it does not require a stratigraphic seal or cap rock. In mineral trapping, formation mineralogy may react with CO2 and induce precipitation of carbonate minerals 26. This paper presents field-scale compositional simulation of CO2 storage capacity as a function of different trapping mechanisms within the Farnsworth Unit in the Texas panhandle. The target Morrow sandstone reservoir presents opportunities both to enhance oil production and sequester a large portion of injected CO2. The trapping mechanisms examined include structural-stratigraphic, solubility (water and oil) and residual trapping. The effects of WAG cycle, salinity and hysteresis on CO2 storage are studied. A cap rock integrity analysis has been conducted on FWU to access the long-term containment of supercritical CO2. A primary, secondary and tertiary history matched model constructed from the FWU was used as the base for the study 31. WAG injection with CO2 recycle was continued for a total of 25 years beyond waterflood and wells shut-in to monitor the storage for additional 200 years as a function of different mechanisms. This paper is sub-divided into five sections including: geological background of FWU, trapping mechanisms theory, reservoir model description, results and discussion and conclusions.

2 Geologic Background 2.1. Geologic Setting The Farnsworth Unit (FWU) produces from sandstones of the upper Morrow formation 32-33. The Morrow B formation is an operational name for strata deposited during the Morrowan-age of the ACS Paragon Plus Environment

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Pennsylvanian. Morrowan reservoirs are prevalent within the Anadarko basin throughout the Oklahoma and Texas panhandles, western Kansas, and southeastern Colorado 34. The upper Morrow formation within FWU contains up to five sandstone packages separated by mudstone intervals 32-33. Production comes from the upper most sand interval referred to as the Morrow B sandstone. The Morrow B sandstone deposited in an incised valley, fluvial-estuarine setting as shown in Figure 1 33, . Stratigraphy of the reservoir was controlled by a complex interplay of climatic and tectonic forces during the Pennsylvanian. Large scale glacioeustatic sea level fluctuations are thought to have caused the rapid transitions from shale to sandstone intervals 33, 36-38. Deposition was also influenced by positive elements at the time that resulted from the collision of the South American and North American plates. These positive elements include the Apishapa-Sierra Grande Uplift to the west, the Ancestral Front Range and Transcontinental Arch to the north, the Central Kansas Uplift and the Amarillo-Wichita uplifts to the south 33, 34,36.

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Figure 1 - Geological setting and Farnsworth field location

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The reservoir tends to be comprised of subarkosic, moderately to poorly sorted, sub-angular to subrounded, upper medium to very coarse sands and fine gravels. The overall immaturity and presence of both micrographic granitic rock fragments as well as volcanic quartz suggests that the Precambrian crystalline rocks of the Amarillo-Wichita Uplift were a probable source area 32-33. After deposition, diagenetic events such as feldspar alteration, authigenic clay formation, dissolution and/or precipitation of silica, and calcite cementation, either enhanced or diminished primary porosity and permeability 32, 4041 . The upper Morrow shale and Atokan Thirteen Finger Limestone comprise the primary caprocks at Farnsworth Unit (FWU). Cores samples from three newly drilled wells through the caprock were examined to ascertain the integrity of these lithologies in containment of injected CO2. The Morrow shale is comprised of three lithofacies. Lowermost is fine sand to fine mudstone deposited in an estuarine environment during transgression 33-34. This terminates at a black laminated, mudstone (Mfml), and the transition represents a flooding surface and change from estuarine to marine deposition. The middle of facies Mfml represents maximum flooding, above which deposition occurred during ACS Paragon Plus Environment

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regression. The uppermost facies is a calcareous mudstone deposited in a shallow marine setting. The top of the Morrowan section and base of the Atokan series is a sequence boundary 40. The Atokan interval alternates between two distinct lithofacies: a coal bearing, fine to medium mudstone facies, and a carbonate cementstone facies. Coals were deposited in coastal swamps during lowstands and cementstones formed under restricted marine conditions during highstands. 2.2. Reservoir Description The discovery well was drilled by Unocal in October 1955 in the east side of the field. It had an average connate water saturation of 31.4%. The initial reservoir pressure and temperature was 2203 psig at a datum of 7900 ft and 168 °F respectively. The original bubble point pressure was 2059 psi. The original oil had a formation volume factor of 1.192 RB/STB. Also, oil initially in place was estimated at about 120 MMSTB. The primary production was driven by a solution gas mechanism since there was no reported aquifer associated with the reservoir. About 100 wells were completed by 1960. The field was unitized in 1963 with Unocal as operator 31. Water injection for secondary recovery started in 1964. Chaparral Energy LLC (CELLC) acquired the FWU in November 2009 and Tertiary CO2-EOR began in December 2010. The anthropogenic CO2 for the project is supplied from the Arkalon ethanol plant in Liberal, Kansas and the Agrium fertilizer plant in Borger, Texas as shown in Figure 2.

Figure 2-Two anthropogenic CO2 supply sources for three fields in the Texas Panhandle including FWU site

31, 42

.

3 Theory 3.0. Trapping mechanisms This work focuses on three storage mechanisms including solubility, residual trapping and structural trapping. Mineral trapping modeling for FWU has been examined in separate studies 43-46. 3.3.1 Solubility Trapping In this study, an equation of state (EOS) is used to model oil and gas phase densities and fugacities. CO2 partitioning between oil and gas phases is computed by fugacity equilibration. A compressive Pressure Volume Temperature (PVT) analysis on a Farnsworth field fluid sample has been presented by Gunda et al.47. The original minimum miscible pressure (MMP) measured from slim tube experiment was 4200 ACS Paragon Plus Environment

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psia. Gunda et al.47 predicted an MMP of 4009 psia which represents less than 5% error compared to original value. Water is not allowed to dissolve in both gas and oil phases. However, CO2 can be present in all three phases (water, gas and oil). CO2 solubility in formation water and other aqueous phases are modeled by using Chang et al.30 correlation. The equation developed for distilled water solubility extended to include effects of salinity as shown in Eq (1).

R = R e( .

. )

(1)

where Rsb is solubility in Scf of CO2 per Stb of formation water, Rsw is solubility in Scf of CO2 per Stb of distilled water, T is temperature in °F, and C is salinity of formation water in weight percent of solid. The salinity is available from formation water chemistry analysis. The current measured salinity for FWU is around 3500 ppm. 3.3.2 Residual Trapping Residual trapping is an important CO2 trapping mechanism 28. Hysteresis phenomenon allows capillary pressures and relative permeabilities to vary between imbibition and drainage curves through scanning curves 48. Capillary pressure follows drainage curves for decreasing wetting-phase saturations and imbibition curves for increasing wetting-phase saturations. In case of a reversal in saturation directions, capillary pressure follows along the scanning curves 48. Entrapment of the non-wetting phase occurs when it is bypassed by the wetting phase thereby making it immobile. Previous research has presented several correlations in modeling hysteresis 48-50. In this paper the relative permeability hysteresis is based on the equation developed by Killough 48 as shown in Eq. 2. A typical drainage and imbibition curves used in modeling hysteresis are shown in Figure 3.

S = S +

!" #$ ( !" )

(2)

where

C =

# !& !"

−

# ()* !"

(3)

Sncrt is the critical trapped saturation of non-wetting phase; Sncrd is the critical saturation of drainage curve; Shy is the maximum non-wetting phase saturation; C is land’s coefficient; Snmax is the maximum non-wetting saturation; Sncri is the critical saturation of the imbibition curves.

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Figure 3- Drainage and imbibition curves used in modeling hysteresis effect

3.3.3 Structural - Stratigraphic Trapping Structural and stratigraphic trapping mechanisms are both important in the storage of CO2 in a depleted hydrocarbon reservoir. The integrity of the caprock is vital to prevention of upward movement of supercritical CO2 towards the surface. Seal bypass refers to the presence of fast paths for fluid transmission that have the potential to compromise the integrity of a caprock 51. Analysis was performed to study the integrity of the caprock for the FWU using mercury porosimetry. The mercury porosimetry data can be used to compute the height of supercritical CO2 that a caprock can contain 52. The results from the analysis for FWU indicate that lithologies within the overlying Morrow shale and Thirteen Finger Limestone units are excellent seals capable of providing storage of supercritical CO2 up to a column height of 10,000 ft as illustrated using data from two characterization wells in Figure 4. The highest values of column heights achieved the limiting 60,000 psia of the MICP testing apparatus before breakthrough (i.e., some samples did not intrude mercury even at the maximum value 60,000 psia of the MICP testing). Pore throat size distribution for Morrow B sandstone reservoir, Morrow shale and Thirteen Finger Limestone samples are plotted in Figure 5 as a function of incremental non-wetting phase saturation. This underscores the excellent sealing capacity of Thirteen Finger and Morrow Shale lithologies.


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Figure 4- CO2 columns heights (i.e., sealing capacity) versus depth. Formation or member contacts are indicated by black horizontal lines. 13 Finger, UMS, MB, LMS, and Lower Sand stand for the Thirteen Finger Limestone, the upper Morrow Shale, the Morrow B Sandstone, the lower Morrow Shale (or shale directly under the Morrow B), and the next lower sandstone below the Morrow B, respectively. The error bars represent the result of using a range in contact angle values from 10 to 57°.


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Figure 5- Pore throat size distributions versus incremental non-wetting phase saturation for samples from the Thirteen Finger Limestone, the upper Morrow shale, and the Morrow B sandstone.

4 Model Description The static (geocellular) model for the FWU was constructed from geophysical, geological and engineering data as described by Ampomah et al. 53. This model has been used by the SWP Simulation Working Group, and serves as the basis for research activities in hydrogeology, reactive transport, and risk assessment 31, 43-46, 54-56. Stratigraphic definition of the reservoir and adjacent units was supported by a 3-D seismic survey acquired in January 2013 as part of the SWP project 57. Ampomah et al.53 presented a detailed upscaling study to decrease the number of cells in the geological model to reduce computation cost for dynamic modeling studies. The dynamic model used for this study was extracted from the SWP geological model 53 which has been history matched 31. The model, which describes the west half of FWU, has a size of 81×77×5 grid blocks with gridblock dimensions of 200 ft × 200 ft. This model includes the Thirteen Finger limestone, Morrow shale, and Morrow B sandstone (Figure 6). The first two horizons serve as a caprock for the ACS Paragon Plus Environment

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Morrow B sandstone reservoir. All wells in FWU are vertical wells. The porosity and permeability for the Morrow B sandstone reservoir was constructed based on about fifty well core data from FWU. There was no global correlation existing between porosity and permeability at the time static model was constructed and therefore geostatistical tools were used in property population prior to history matching 42 . A sequential Gaussian and Gaussian random function algorithm was used in populating 3D porosity and permeability respectively. Porosity distribution in the reservoir has a range of 9.2% to 24% with a mean of 14.6%. Permeability ranges from 0.01 mD to 181 mD with an average value of 58 mD. A geomechanical study on several core samples within FWU was conducted and reported a potential fracture pressure range of 5400 and 5600 psia. This guided SWP simulation efforts within the FWU. Gunda et al. 47 provided a comprehensive reservoir fluid analysis on a FWU oil sample which has been used in various SWP reservoir simulation models. Reservoir fluid was tuned to an equation of state (EOS) using the 3-parameter Peng Robinson EOS 58 with a Peneloux volume correction 59. The Lohrenz-Bray-Clark correlation is used for the calculations of viscosities 60. Table 1 shows details of reservoir fluid properties used for the compositional numerical modeling. After the PVT tuning process, a slimtube simulation experiment conducted on FWU fluids resulted in a minimum miscible pressure (MMP) of about 4009 psia compared to experimental value of 4200 psia, representing a less than 5% error 47,61. Sensitivity analyses were conducted to study the effect of using recycled CO2 with or without impurities on MMP predictions 47. These analyses enabled modeling of CO2-EOR performance incorporating the real world use of both purchased and recycled CO2. Table 1- FWU Reservoir fluid characterization

Components

Mole fraction %

Molecular weight gm/mol

Critical Temperature o F

CO2 C1 C2 C3 C4’s C5’s C6’s HC1 (7-38) HC2 (38-70)

0 38.49 3.86 2.46 1.95 1.79 2.83 33.48 15.13

44.01 16.04 30.07 44.1 58.12 72.15 86.18 189.95 545.65

87.89 -116.59 90.05 205.97 453.65 301.12 380.71 802.94 1077.75

Critical Acentric Pressure factor Psi 1069.8 667.17 708.36 615.83 430.62 547.81 489.79 326.19 235.69

0.23 0.01 0.1 0.15 0.3 0.19 0.24 0.48 0.57

Ampomah et al.31 presented the preliminary history matching and prediction model of FWU which served as basis for SWP modeling efforts. The dynamic model had 60 production wells during primary depletion in the model. As there were no recorded gas-oil or water-oil contacts, all grid blocks were assigned an initial oil saturation of 69% and 31% connate water saturation. An initial reservoir pressure of 2217.7 psia was assigned to a datum depth of 7900 ft. The bubble point pressure of 2073.7 psia indicates that the reservoir was slightly undersaturated. Volume of oil originally in place (OOIP) was about 60 MMstb with 20.82 MMscf of dissolved gas. During waterflood, there were 47 producer wells with 13 wells converted from producers to injector wells. Six additional water injector wells were drilled ACS Paragon Plus Environment

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during this same period. FWU has 55 years of primary and secondary depleted recovery. In December 2010, Chaparral Energy LLC commenced CO2 flooding of the field. The additional four years of CO2 flood history was calibrated to the model. During the four-year CO2 history calibration, there were 12 water-alternating gas (WAG) wells and 28 producer wells. These were arranged in an inverted 5-spot pattern. The history match model showed areas where sweep efficiency was not good so 7 water injectors were distributed across less swept areas to enhance production during commencement of CO2 flood. Figure 7(a) shows a gas saturation distribution intersecting an injector well prior to commencement of WAG process. At FWU, gas saturation was nearly zero at the end of waterflood (December, 2010) 31 as can be deduced from the figure. Figure 7(b) illustrates water saturation at the end of waterflood. Water saturation distribution was mostly at maximum ~ 73%. The model area was successfully flooded mostly to residual oil saturation ~ 27%. This is not unexpected given the relatively good mobility ratio of about 1.6 and high injection throughput of at least 1.7 displaceable pore volumes. Figure 7(c) shows distribution of gas saturation which is predominantly CO2. The gas saturation was in the range of 55% at the end of tertiary stage history match. This attests to the promising CO2 storage potential at FWU. Figure 7(d) illustrates water saturation at the end of tertiary recovery history match. The figure shows a reduction in water saturation compared to figure 7(b) which attributes to increase in CO2 saturation with the reservoir. Figure 7e represents a 2D distribution of CO2 mole fraction at the end of tertiary history match (December, 2014). The areas in the figure 7(e) with large volumes of sequestered CO2 are the locations of CO2 injection patterns. This figure also indicates the direction of CO2 flow. There is less accumulation as the flow moves away from the injectors.

39, 53

Figure 6- Stratigraphy and type log of FWU


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Figure 7- (a) and (b) represents an intersection at well #8-4 of gas (CO2) and water saturation at the end of waterflood (December, 2010) respectively. (c) and (d) represents an intersection at well #8-4 of gas (CO2) and water saturation at the end of CO2 flood history match (December, 2014) respectively. Figure 7(e) shows a 2D view of mole fraction of CO2 component within the reservoir at the end


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of CO2 flood history match. These figures illustrate the CO2 storage potential within the Morrow B reservoir at the end of history matching process.

5 Results and Discussion 5.0 CO2 Storage Capacity at FWU Scenario based models were run and analyzed to ascertain how CO2 is stored within the reservoir under various operational scenarios. A total of 25 WAG wells and 35 producers were introduced into the model by the end of 2018. There is an anticipated constant CO2 purchase of 26,350 lb-mol/d and a compressor facility to recycle produced gas for re-injection purposes. A user-defined algorithm was developed to use purchased CO2 in addition to produced gas (recycled) as total group injection available rate for various simulation cases. A constant WAG ratio of 2:1 was used to initialize the simulation runs. All studied cases involve a continuous WAG injection for additional 21 years beyond the history matched period. After 25 years of injection, wells were completely shut-in and stored CO2 was monitored for additional 200 years as a function of various storage mechanisms. The entire duration of study was from December 2014 to January 2236. 5.1 Injection profiles effect on CO2 storage capacity Two main development strategies are used in this work to illustrate the effect of CO2 injection profiles on storage. a) With constant CO2 purchase (26350 lb-mol/d) and b) with decreasing CO2 purchase from 2022 to 2030 and inject only recycled gas after 2030. Case A involves injecting continuous 26350 lb-mol/d of purchased CO2 in addition to recycle gas for 21 year period. Case B also involves continuous injection of 26,350 lb-mol/d of purchase CO2 in addition to recycled gas until end of 2021. At year 2022, purchased CO2 was cut to 21,080.03 lb-mol/d representing a 20% reduction. CO2 purchased was subsequently reduced by 2,635 lb-mol/d each year until 2030. Afterwards, CO2 purchase ceased and only recycled gas was injected. Both cases have 25 WAG wells, 35 producers, CO2 purchase and recycle. The WAG cycle for these cases is 3:1 with a water salinity of 3500 ppm. Table 2 shows summary of results comparing above cases. Even though Case A had about 15% more CO2 volume stored than Case B, a large volume of CO2 was produced and amount of recycled percentage was low in Case A due to other constraints such as bottomhole pressures. Case B had almost the same amount of oil recovery with 40% less CO2 purchased. Case B has a probable chance of rendering a higher rate of return if the FWU were operated under such a scenario. In terms of long term storage of CO2 both cases demonstrated sufficiently high pressure above the MMP even at the end of the 200 year monitoring simulation run, as shown in Figure 8. Case A has a slightly higher average pressure due to the volume of total injected fluid. The minute gradual reduction in pressure could be due to changes in total compressibility and equilibrating of the system after wells are shut in. There is a possibility of reservoir pressure lowering below the MMP which could eventually ACS Paragon Plus Environment

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result in an increase in supercritical CO2. However, FWU has multiple good stratigraphic seals which will serve to trap the CO2 in the subsurface. Case B illustrates that recycling a high percentage of produced gas, addition of wells/patterns, and reduction in purchased CO2 after some years of operation improves oil recovery and maximizes CO2 storage. This development strategy is used in the following sections to study effect of WAG cycles, salinity and hysteresis on different storage mechanisms.

Figure 8- Pressure profile during monitoring period for Case A and Case B

5.2 Effect of WAG Cycles on Storage Mechanisms Changes in CO2 and water cycling in a CO2 flood can affect both the amount of CO2 stored and the storage mechanism within the reservoir. In addition to Case B described above, a development strategy with a WAG cycle of 1:1(Case B1) was simulated to analyze its effect on CO2 storage. CO2 and water injection profiles for these cases are shown in Figure 9. Case B has a higher CO2 injected volume and lower injected water volume than Case B1. The trend translated to higher oil recovery and volume of CO2 stored for Case B as summarized in Table 3. It is therefore necessary to use optimum injection cycles to ensure higher oil recovery and maximum utilization of available CO2. Figures 10 and 11 show CO2 storage profiles for Case B and Case B1 respectively. During the injection period in Case B, CO2 in supercritical phase was competing with dissolution in oil as opposed to Case B1. This was due to the larger volume of CO2 injected and lower bottomhole pressures at the producer wells. Case B1 had slight higher average pressure due to the larger volume of water enabling extra dissolution of supercritical CO2 ACS Paragon Plus Environment

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as shown in Table 3. In both cases at the shut in of wells, reservoir pressure started to equilibrate and was still above MMP, ensuring mobile CO2 stayed dissolved in the remaining oil. The solubility of CO2 in water was nearly constant at shut-in. At the end of simulation only 4% of stored CO2 is in the supercritical state which could be due to a gradual reduction in pressure. Though it is theoretically possible for the pressure to decrease below MMP after several years, it was not realized in this study. FWU has multiple overlying formations that act as formidable seals to contain mobile CO2 within the reservoir. The residual trapping was not dominant in cases B and B1. The 1% residual trapping could be due to capillary forces existing within the reservoir. Trends exhibited in these figures could change based on several factors including volume of distinct fluids within the reservoir, pressure, salinity and temperature. But it is obvious dissolution of CO2 in oil would dominate in most partially depleted oil reservoirs.

Figure 9- Injection profiles for Case B and Case B1 to study effect of WAG cycles on CO2 storage


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Figure 10- CO2 storage profile based on different mechanisms within the reservoir for Case B

Figure 11 - CO2 storage profile based on different mechanisms within the reservoir for Case B1


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Table 2 - Summary results for Cases A and B Injection Scenarios

Case Results Units A MMlb-mol 237.92 CO2 Purchased CO2 Production Cumulative MMlb-mol 720.04 CO2 Injection Cumulative MMlb-mol 854.43 Recycle MMlb-mol 616.52 Total Storage* MMlb-mol 134.39 % Storage % 57 % Oil Incremental Recovery % 34.1 *Total Storage = CO2 Purchase – CO2 produced + CO2 Recycled

B 153.25 604.97 719.22 565.97 114.25 75 33.9

5.3. Effect of Salinity on Storage Mechanisms Prior to waterflood reservoir salinity at FWU was thought to be ~35,000 ppm. Reservoir water salinity following waterflood was 3,500 ppm due to the injection of fresh water of TDS ~500 ppm. Numerical simulations were run with these two salinities to study the effect on CO2 storage within FWU. From simulation results, salinity changes strongly affects the solubility of CO2. The salinity in Case B was changed to 35,000 ppm while keeping other parameters constant. Figure 12 compares CO2 dissolved in water for salinities of 3,500 ppm and 35,000 ppm. For these two scenarios, the total CO2 in place was equal prior to and after wells shut in. The initial case with a salinity of 3,500 ppm had nearly 2 MMlbmol more of CO2 dissolved in formation water as compared with the 35,000 ppm senario. This extra 2 MMlb-mol dissolved in remaining oil in the latter case. There was not significant change in oil recovery for either case.


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Figure 12- CO2 dissolved in water at different salinities.

5.4. Effect of Hysteresis on Storage Mechanisms Whenever a wetting phase fluid bypasses a non-wetting phase it often renders the non-wetting phase immobile. During the imbibition process, the relative permeability of the wetting phase increases drastically compared to the non-wetting phase thereby increasing entrapment. FWU is considered a water wet reservoir. Drainage curves were measured as part of the special core analysis. Corey correlation was used to construct imbibition curves to study the hysterestic effect on CO2 storage 62. The cases B and B1 described above did not include the hysteresis model that contributes to about 1% storage due to residual trapping. Case B2 is an extension to Case B and includes hysteresis. The volume of CO2 stored in both cases is almost the same. The storage profiles for Case B and Case B2 are shown in Figures 10 and 13 respectively. Due to an increase in wetting phase relative permeability, a larger volume of water was produced in Case B2, subsequently reducing oil recovery and average reservoir pressure. The supercritical CO2 phase also increased slightly in Case B2 due to pressure reduction. Table 4 shows a summary comparison of both cases. In Case B2, CO2 stored due to residual trapping was pronounced. 14% of stored CO2 was trapped due to hysteresis. This apparently affected the amount of CO2 dissolved in oil since the percentage of CO2 dissolved in water was almost the same in both cases.


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Figure 13- CO2 storage profile based on different mechanisms within the reservoir for Case B2 to study effect of hysteresis

Table 3- Summary results for effects of WAG cycles on CO2 storage

Case B B1

WAG Cycle 3:01 1:01

Oil Recovery % 73 70

Oil % 76 72

Solubility Water % 19 24

Supercritical CO2

Residual

% 4 4

% 1 1

Table 4- Summary results for effects of hysteresis on CO2 storage

Case B B2

Hysteresis Model No Yes

Oil Recovery % 73 71

Oil % 76 63

Solubility Water % 19 18

Supercritical CO2

Residual

% 4 5

% 1 14

6 Conclusions This work presents an extension of performance assessment of FWU, studying different mechanisms contributing to CO2 storage within a depleted oil reservoir. This study serves as a benchmark for future CO2-EOR projects in the Anadarko basin or geologically similar basins throughout the world. ACS Paragon Plus Environment

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The major findings include: 1. A mercury injection capillary pressure analysis was used to calculate the CO2 column heights and supported by capillary sealing of caprock lithologies. The analysis presented showed sealing units including Morrow Shale and Thirteen Finger Limestone are capable of providing excellent sealing capacity for CO2 storage within the Morrow B sandstone unit, supporting column heights up to 10,000 ft. Failure analyses showed the targeted reservoir (Morrow B sandstone) is weaker than overlying lithologies, implying any generated fractures initiated around injection wells has low possibility to propagate into overlying sealing units. 2. Injection strategies presented in this paper shows that recycling a high percentage of produced gas, addition of well/patterns, and reduction of CO2 purchase after some years of operations has a tendency of yielding higher oil recovery and CO2 storage as well as higher rate of return. At FWU, the average reservoir pressure has been maintained to reduce the supercritical CO2 phase which makes solubility (oil and water) and residual trapping the most important storage mechanisms. The gradual reduction in pressure is observed in simulation results after all wells are shut-in signifies a possible increase in supercritical CO2 after passage of significant time. This trend stresses the need to evaluate sealing potential for long-term CO2 storage. 3. This paper elaborated the importance of WAG cycle in enhancing oil recovery and/or CO2 storage. The WAG cycle examples used in this work though illustrates the potential trend on their effect on recovery and storage but optimum cycles are desired to ensure maximum performance. Increasing gas cycles compared to water cycles have the potential of increasing CO2 storage and oil recovery, however, an optimum cycles are desired to control CO2 mobility to reduce viscous fingering which can be detrimental to CO2-EOR operations. Current SWP work performed on FWU used advanced numerical simulation tools to estimate optimum WAG cycles which yielded about 95% of potential CO2 storage 18. However, the trend in CO2 trapping mechanisms potential are expected to be the same as illustrated in this paper. 4. Dissolution of CO2 in oil was found to be the predominant mechanism for storing CO2 within depleted oil reservoir such as FWU. Salinity affects amount of potential CO2 disolution in formation water. Low salinity formations have a tendency of dissolving higher percentage of CO2 in formation water as illustrated in this paper. From the simulation results, it is necessary to consider hysteresis if present to ensure accurate modeling of CO2 storage as a function of different mechanisms. Residual trapping when hysteresis is modeled accurately can be a competing mechanism in storing CO2.There is a possibility of over predicting oil recovery when modeled without hystereis phenomenon.

AUTHOR INFORMATION Corresponding Author Correspondence to: William Ampomah, email: [email protected] Author Contributions ACS Paragon Plus Environment

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W.A. designed and carried out the reservoir fluid simulations, performed data analysis and wrote the draft manuscript. R. B., M. C., D.R., Z. D., J. H., T. D., and P. M. helped on model development, parameter characterization and laboratory experimentation. All authors discussed the results, reviewed, and revised the manuscript.

Acknowledgements Funding for this project is provided by the U.S. Department of Energy's (DOE) National Energy Technology Laboratory (NETL through the Southwest Regional Partnership on Carbon Sequestration (SWP) under Award No. DE-FC26-05NT42591. Additional support has been provided by site operator Chaparral Energy, L.L.C., and Schlumberger Carbon Services.

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Unit Conversions 1 Mscf 1 lb-mol 1ft 1psi

= 2.635 lb-mol = 1.977E-05 Metric tonnes = 0.3048 m = 6.895 KPa

1°C

= 33 °F


Enhanced Oil Recovery Sites - American Chemical Society

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