Using Polymers to Improve CO 2 Flooding in the North Burbank Unit

Transcription

1 Using Polymers to Improve CO 2 Flooding in the North Burbank Unit W. Li, D.S. Schechter Texas A&M University Abstract The North Burbank Unit, located in Osage County, was originally discovered in 192. It has an extensive history of activity, including primary depletion, produced gas cycling, and water and polymer flooding to the point of very high water cut at current conditions. The current oil production rate in the North Burbank Unit is approximately 1,4 BOPD from 36 active wells at a water cut of 99.5%. The North Burbank Unit has a cumulative production of 332 million bbl of oil out of an estimated 824 million bbl of original oil-in-place. Significant reserves are currently available for post-secondary production. CO 2 flooding is a good choice considering that the minimum miscibility pressure (MMP) in the North Burbank Unit is lower than the fracturing pressure and CO 2 is available from a purely anthropogenic source. This paper demonstrates that a 1-year-old field is not only an excellent CO 2 enhanced oil recovery (EOR) target, but is at the forefront of a new synergistic technology to couple EOR and anthropogenic CO 2 that would otherwise be released to the atmosphere. It is a logical alternative to reduce CO 2 emissions while increasing domestic production. High heterogeneity and high permeability at the top layers are the two main challenges of the North Burbank Unit. Two methods related to polymers are studied to improve CO 2 flooding in the North Burbank Unit. One is to add polymers with co-solvent, named CO 2 viscosifier, to CO 2 to increase CO 2 viscosity. The other is to add polymers to water to increase water viscosity during the water-alternating-gas (WAG) process, named polymer-alternating-gas () flooding. To analyze the impact of CO 2 flooding in the North Burbank Unit, five tracts that best represent the characteristics of the field were selected for reservoir modelling. Based on simulation results, the conventional WAG process increased average oil recovery in the North Burbank Unit by 1.89%, and gross CO 2 utilization and net CO 2 utilization are forecasted to be Mscf/bbl and 5.4 Mscf/bbl, respectively. Using CO 2 viscosifier and flooding could markedly delay gas breakthrough, reduce gas-oil ratio and increase oil recovery. CO 2 viscosifier and are forecasted to increase average oil recovery 7 to 8% more than conventional WAG flooding in the North Burbank Unit. Introduction Although CO 2 flooding is a well-established EOR technique, its density and viscosity nature is a challenge for CO 2 projects. Low density (.5 to.8 g/cm 3 ) causes gas to rise upward in reservoirs and bypass many lower portions of the reservoir. Low viscosity (.2 to.8 cp) leads to poor volumetric sweep efficiency. In heterogeneous reservoirs with high-permeability zones and natural fractures, the condition is even worse (1). CO 2 Viscosifier CO 2 viscosifiers (direct thickeners) are the most direct way to increase the viscosity of CO 2, hence improving overall sweep efficiency. A high-molecular-weight polymer and co-solvent are blended and pressurized together with CO 2 so that CO 2 viscosity can be greatly increased before CO 2 is injected. A number of studies show that gas viscosifier chemicals can increase CO 2 viscosity by an order of one to two and can control CO 2 mobility (2-6). However, the main barriers to using viscosifiers include the following: (1) the large volume requirement of co-solvent makes pilot-testing costs prohibitive (7) ; (2) co-polymers do not dissolve in CO 2 unless pressure far exceeds MMP (7) ; and (3) the environmental impact is negative (8). To overcome the issues of gas breakthrough and gravity segregation, a new combination method is proposed. This new method, termed, combines features of CO 2 flooding with polymer flooding to produce chemically enhanced WAG flooding. Coupling polymers with CO 2 is expected to improve the efficiency of the current WAG. The main feature of is that the polymer is injected with water throughout the whole WAG process. Zhang et al. (1) conducted an experiment based on Saskatchewan crude, named polymer injection chased with gas alternative water (PGAW). They stated that coupled CO 2 and polymer injection gave better recovery and efficiency than WAG and polymer flooding. Majidaie et al. (9) carried out the first coupled CO 2 and polymer injection simulation study for light oil based on a synthetic and homogeneous model. This study showed that and WAG have almost the same recovery. He also mentioned that a chemical slug of polymer with surfactant and alkali would significantly increase oil recovery. Workflow In this study, we discuss CO 2 viscosifier and flooding in light oils based on the field model, TR48, of the North Burbank Unit. The commercial software E1 was used, which is a simulator that can model both the solvent process and polymer flooding. The main steps in the simulation study are as follows: 1. Describe geological background, production history and reservoir characteristics in the North Burbank Unit. 2. CO 2 resource. 3. Build pressure-volume-temperature (PVT) model. 4. Build reservoir model. 5. Validate the reservoir model by matching primary and secondary production data. 6. Evaluate the performance of CO 2 viscosifier. 7. Evaluate the performance of. March 214 Volume 2 Number 1 ISSN

2 Geological Background As mentioned by Johnson (1), the North Burbank Unit is located on the northeastern Oklahoma Cherokee platform (Figure 1). Burbank sandstone is the main reservoir of the field. Burbank sandstone is the local informal name for the Red Fork sandstone. It is part of the Desmoinesian Cherokee Group, a sequence of sandstones, shales and thin limestones. As shown in Table 1, the Cherokee sandstones include, in ascending order, the Bartlesville, Red Fork, Sonner and Prue. Burbank sandstone has produced more than 9% of the oil and minor gas from depths of 2,8 to 3,2 ft. Minor amounts of oil and gas have been produced from younger Pennsylvanian sandstones, Mississippian Chat, and Ordovician sandstones. Johnson (1) also described that Burbank sandstones were fluvial-deltaic and a stratigraphic trap. Development History of the North Burbank Unit The North Burbank Pool, located in Kay and Osage Counties, Oklahoma, was discovered by Marland Oil Company in May 192. The discovery well (named No. 1 Tribal) was located in the southeast/northeast Section 36, T27N, R5E on the small Hay Creek anticline. In September of that year, Carter Oil Company drilled two wells on another small anticline 2 miles to the southeast in Section 9, T26N, R6E (11). Development drilling proceeded rapidly, and by 1924, 75% of the wells in the main part of the field had been drilled. The initial potential of wells in the Burbank sandstone varied from 1 to 12, BOPD. As shown in Figure 2, peak production was reached in July 1923, when the average daily production was 122, BOPD. FIGURE 1: Geologic map of the North Burbank Unit: a) Location of the North Burbank Unit (15) ; b) Highlighted tracts in the North Burbank Unit. Table 1: General stratigraphic column of the cherokee group and burbank sandstone. Eon System Series Group Subsurface Name Marmaton Big Lime Oswego Limestone Prue Sandstone Verdigris Limestone Upper Sonner Sandstone Henryetta Coal Middle Sonner Sandstone Lower Sonner Sandstone Pink Limestone Red Fork Sandstone(Burbank Sandstone) Inola Limestone Bartlesville Sandstone Brown Limestone Paleozoic Pennsylvanian Desmoinesian Cherokee Cabaniss Krebs Sources: Overpressuring and Seal Structure of Pennsylvanian Red Fork Formation in the Anadarko Basin, Oklahoma (edited from Virginie 1995) 2

3 Dykstra-Parsons Coefficient of Permeability Variation 1, Permeability (md) 1, 1 1 FIGURE 2: The North Burbank Unit production history. Three phases: primary development ( ); recycled gas injection ( s); and waterflooding (195s 21s) Percent 1 Depth (ft) Permeability (Md) , 1,2 2,979 2,983 2,987 2,991 2,995 2,999 3,3 3,7 3,11 3,15 3,19 3,23 3,27 3,3 3,35 3,39 3,43 3,57 3,6 3,64 FIGURE 3: Permeability vs. depth at well NBU48-28 (Core data 26). Production declined rapidly as a result of the wide-open operation, and the practice of pulling vacuum on wells, which began in 1924 in an effort to increase production. Produced gas injection began in 1926 by various operators in the field. The injection of purchased gas from external sources began in Approximately 15 million bbl had been produced under primary and gas injection by 1951, when, what was then one of the world s largest waterflooding projects, began operation. Between 4, and 5, bbl of water from the nearby Arkansas River was pumped to the field for injection (12). Approximately 182 million bbl have been produced in this secondary recovery phase. FIGURE 4: VDP at well NBU48-28 (Core data 26). Most of the current production now comes from waterflooding with a high water cut of 99.5%. Reservoir Properties The gross oil pay thickness of the North Burbank Unit varies from 3 to 1 feet, with an average of 47 to 5 feet (1, 11). The subsea is about 2,85 to 3,1 feet, with a reservoir temperature of 118 F. The initial reservoir pressure is 1,6 psi, which is believed to be above the initial saturation pressure for oil. The initial solution gas-oil ratio was estimated to be 38 ft 3 /bbl. Table 2 summarizes the basic reservoir and field characteristics (1). Based on core data, two typical reservoir characteristics of the North Burbank Unit were found (Figures 3 and 4): high permeability exists in the top layers, and the Dykstra-Parsons coefficient of permeability variation (VDP) varies from.5 to.98. CO 2 Resource In 211, the operator signed a long-term carbon dioxide (CO 2 ) purchase and sale agreement for the capture of CO 2 from a nitrogen fertilizer plant located in Coffeyville, Kansas. Almost all of the fertilizer plant s CO 2 emissions will be captured. A CO 2 gathering and compression facility was constructed at the plant site and 68 miles of pipeline was installed in order to deliver the CO 2 to the North Burbank Unit in Osage County, Oklahoma. Table 2: Summary of reservoir and field characteristics. Formation Red Fork sandstone Age Pennsylvanian, Desmoinesian Depth to Top of Reservoir 2,9 ft Gross Thickness 2,85 to 3,1 ft Reservoir Net Thickness, Average 5 ft Net Thickness, Maximum 1 ft Lithology Fining upward, very fine- to medium-grained sandstone with some carbonate silica and clay cement Porosity Type Intergranular and moldic due to dissolution of framework grains Average Porosity.2 Permeability Variable: to 1,2 md; average permeability: 5 to 8 md Field Well Spacing Primary Recovery Secondary Recovery Total Reserves in Place 1 wells/acre 15 million bbl 182 million bbl 824 million bbl March 214 Volume 2 Number 1 3

4 Swelling Factor CO 2 Mole Fraction Oil Recovery Factor (%) ,2 1,4 1,6 1,8 2, 2,2 2,4 2,6 Pressure (Psia) FIGURE 5: Correlation of swelling factor vs. CO 2 mole fraction. Fluid Viscosity (cp) CO 2 mole fraction FIGURE 6: Correlation of fluid viscosity vs. CO 2 mole fraction. Fluid Model The Peng-Robinson equation of state (EOS) was used in this study for fluid modelling of the North Burbank Unit. After combining 4 components into 11 pseudo-components, molecular weight, critical pressure, critical temperature, binary interaction coefficients, and Pedersen viscosity coefficients were regressed to match experimental data with simulated data. Based on the PVT model we obtained, we calculated swelling factor, fluid viscosity and MMP. The swelling factor for light oil increases to 1.58 (Figure 5) when the CO 2 fraction increases from. to.75 with a constant temperature of 122 F. As the CO 2 mole fraction increases from. to.75, fluid viscosity declines from 3 to 1 cp (Figure 6). Calculated MMP for the North Burbank Unit oil is about 1,68 psi (Figure 7). Considering that the initial reservoir pressure is about 1,6 psi and the highest injection pressure is about 2,1 psi, CO 2 miscible flooding is possible for this light oil. FIGURE 7: Calculated MMP from software. Reservoir Model Building a full-field 3D geologic model of the North Burbank Unit presented several unique challenges, including having permeability/porosity logs and secondary production/injection data for only a few wells. To address the problem of limited data, five tracts of the North Burbank Unit were selected from the 146 total tracts. These five sections represent typical geological characteristics and well patterns and also have boundary production data. All five tracts (ST48, ST59, ST78, ST88 and ST92) are simulated in this project, and ST48 was selected as an example to show how to improve CO 2 flooding in the North Burbank Unit. For the purpose of modelling, the ST48 is characterized by a gridded network with permeability and porosity parameters specified for each block. For this model, the.5.5 mile reservoir section is divided into 6 grid blocks in the x-direction, 6 grid blocks in the y-direction, and 1 grid blocks in the z-direction. In the x- and y-directions, the grid blocks are 44 feet in length. The grid blocks in the z-direction vary from 4 to 24 feet thick, which results in a pay zone of 91 feet. Figure 8 shows thickness and x-horizontal permeability (kh) in the model. The vertical permeability (kv) is.1 times the x-horizontal permeability, while y- horizontal permeability is 3 times the x-horizontal permeability. Table 3 presents the input reservoir rock and fluid properties used for the simulation. History Matching Using the reservoir model described above, simulation runs were made to history match the reservoir s pre-co 2 flood oil and water production during primary depletion and secondary X-horizontal Pzermeability (md) Layer FIGURE 8: Thickness (left) and x-horizontal permeability (right) of each layer. 4

5 Table 3: Reservoir rock and fluid properties. Reservoir Rock Reservoir Fluid Parameter Values Parameter Values Size of Model (ft) 2,64 2,64 91 Water Density (lb/ft 3 ) Number of Grid Water Viscosity (cp).5 VDP.85 Oil Density (lb/ft 3 ) 5 to 52 kv/kh.1 Oil Viscosity (cp) 2 to 4 Porosity.15 to.27 Initial Oil Saturation.61 to.8 Initial Pressure (psi) 1,35 Initial Water Saturation.2 to.39 Permeability (md) 6 to 23 3, 1 35 Oil Rate (bbl of oil/day) 2,5 2, 1,5 1, 5 Jan- Sep-13 May-27 Jan-41 Oct-54 Jun-68 Feb-82 Oct-95 Jul-9 Mar-23 Date (MM-YY) Oil Rate-Production Data Oil Rate-Simulation Result Water-Cut-Production Data Water-Cut-Simulation Result Water Cut (%) Oil Rate (bbl/day) Neat CO 2 viscosity 5-fold viscosity 1-fold viscosity 2-fold viscosity FIGURE 9: History matching result of oil rate and water cut. 1, 2, 3, 4, 5, 6, 7, 8, Days Viscosity (cp) Neat CO 2 viscosity 5-fold viscosity 1-fold viscosity 2-fold viscosity. 5 1, 1,5 2, 2,5 3, 3,5 4, 4,5 5, Pressure (psi) FIGURE 12: Production rate of different CO 2 viscosities. 8 Neat CO 2 viscosity Gas Oil Ratio (Mscf/bbl) 5-fold viscosity 6 1-fold viscosity 2-fold viscosity 4 2 FIGURE 1: Different viscosity curves changing with pressure (edited from Cai 21). 1, 2, 3, 4, 5, 6, 7, 8, Days Oil Recovery (%) Neat CO2 viscosity 5-fold viscosity 1-fold viscosity 2-fold viscosity CO 2 Viscosity FIGURE 11: Recovery factor of different CO 2 viscosities. development. The liquid production rate was used as the primary constraint. A good match of oil rate and water cut was reached (Figure 9), which validates the reservoir model. CO 2 Viscosifier Flooding Versus WAG To illustrate the possible CO 2 viscosifier effects, we plot a series of curves, as shown in Figure 1, to represent the new FIGURE 13: Gas-oil ratio of different CO 2 viscosities. viscosity-pressure relationship. Viscosity increases of 5-, 1- and 2-fold are used in this study according to the literature. The reservoir performance during CO 2 viscosifier flooding was compared with WAG. As shown in Figure 11, oil recovery is doubled compared with WAG when viscosity is increased 2-fold. Figure 11 also shows that oil recovery from the CO 2 viscosifier increases as CO 2 viscosity increases. We forecasted the oil production rate for the three different CO 2 viscosities (Figure 12). As shown in Figure 12, (1) the more gas viscosity increases, the later oil rate responds during gas injection, and (2) the more gas viscosity increases, the higher the peak rate. Figure 13 shows the gas-oil ratio of these three processes. It shows that the more gas viscosity increases, the lower the gas-oil ratio. From Figures 12 and 13, we can also conclude that increasing CO 2 viscosity would delay gas breakthrough. Versus Polymer Flooding and WAG To study the process, the correlations of rock adsorption and polymer viscosity with polymer concentration (shown in March 214 Volume 2 Number 1 5

6 Polymer Viscosity (cp) Polymer Concentration (lb/stb) FIGURE 14: Correlation of polymer concentration versus polymer viscosity. Oil Rate (bbl/day) , 2, 3, 4, 5, 6, 7, 8, Days Polymer Flooding WAG Rock Adsorption (ug/g) Oil Recovery (%) Polymer Concentration (lb/stb) FIGURE 15: Correlation of polymer concentration and rock adsorption. WAG Polymer Flooding Eor Methods FIGURE 16: Recovery factor of different EOR processes. Figures 14 and 15) were used for polymer flooding. We also assumed a residual resistance factor (RRF) value of 1.5 at.5 lb/ stb in this study. The reservoir performance during was compared with polymer flooding and WAG. Simulation results show that oil recovery from with a polymer concentration of.4 lb/stb is higher than polymer flooding (with a polymer concentration of.1 lb/stb for 2 years) and WAG (Figure 16), which indicates that oil recovery increases with polymer injection. We forecasted the oil production rate for the three different EOR process (Figure 17). The peak oil rate by is higher than WAG and polymer flooding. We can also find that has two oil rate peaks. One is due to gas injection, and the other is the result of polymer injection. Figure 18 shows the gas-oil ratio of these three processes. Gas production occurs after 7 months of CO 2 injection for WAG and. CO 2 breakthroughs occur after 2 years injection for the WAG process, while we do not find significant gas breakthrough in process. FIGURE 17: Production rate of different processes. Oil Recovery (%) Gas Oil Ratio (Mscf/bbl) WAG 1, 2, 3, 4, 5, 6, 7, 8, Days FIGURE 18: Gas-oil ratio of different processes. WAG 2-fold viscosity ST88 ST48 ST59 ST78 ST92 Average Sections FIGURE 19: Recovery factor of WAG and in five sections. Results of WAG, CO 2 Viscosifier and for Other Sections Similar results were reached through simulation for the other four sections. Oil recovery would increase by approximately 16.2, 7.2, 1.27, 7.3 and 13.5% for the five sections, ST88, ST48, ST59, ST78, ST92, respectively (Table 4). The average oil recovery increase by CO 2 flooding is 1.89%, and gross CO 2 utilization and net CO 2 utilization were forecasted to be Mscf/ bbl and 5.4 Mscf/bbl, respectively. Oil recovery from WAG, CO 2 viscosifier and for each section is compared in Figure 19. As shown in the figure, oil recovery significantly increases in sections ST48, ST59, ST78 and ST88 by CO 2 viscosifier and, while oil recovery only increases about 3 to 4.5% in ST92 because of the low permeability (average 3 Table 4: Summary of the five sections. ST88 ST48 ST59 ST78 ST92 Average Recovery increased (%) CO 2 utilization (Mscf/bbl) Net CO 2 utilization (Mscf/bbl)

7 md) in this section. Average oil recovery increased by and CO 2 viscosifier flooding is 7 to 8% higher than conventional WAG flooding. Discussion In this study, simulation results show that and CO 2 viscosifier could increase oil recovery significantly. could use a similar type of polymer to that used in polymer flooding, like Hydrolyzed polyacrylamide (HPAM). However, it is very difficult to find a type of polymer (as viscosifier) that can dissolve in CO 2 without co-solvent. Right now, there is no simulator that can consider the correlation between polymer concentration and CO 2 viscosity. We just simply increased CO 2 viscosity in the model. A new study is needed to develop this type of simulator. The other method that could model the process is using the K-value in STARS (CMG). Future work may include comparisons of results between STARS and E1. Then, a coreflooding experiment would be carried out to verify the performance simulated by this study. Synthetic models of WAG in different reservoirs and fluid conditions would be further discussed. Conclusions The following conclusions were made for ST48 and the other sections based on the simulation work: 1. Adding viscosifier to CO 2 during the WAG process could markedly delay gas breakthrough, reduce gas-oil ratio and increase oil recovery. 2. Compared with conventional WAG, oil recovery increased about 7.27% when CO 2 viscosity increased 2-fold in ST Recovery from is higher than polymer flooding and WAG in ST Two oil rate peaks are found in the process: one is due to gas injection and the other is a result of polymer injection. 5. Conventional WAG flooding increases average oil recovery by 1.89%, and gross CO 2 utilization and net CO 2 utilization were forecasted to be Mscf/bbl and 5.4 Mscf/bbl, respectively. 6. CO 2 viscosifier and flooding are forecasted to increase average oil recovery 7 to 8% more than conventional WAG flooding in the North Burbank Unit. Unit Conversion Table bbl = m 3 ft.348 = m F ( F -32)/1.8 = C mi = km lb = kg ft = m 3 lb/stb 2,853.1 = ppm psi.145 = Pa BOPD = m 3 /day NOMENCLATURE EOR EOS HPAM Enhanced oil recovery Equation of state Hydrolyzed polyacrylamide kv kh MMP PVT RRF VDP WAG Vertical permeability Horizontal permeability Minimum miscibility pressure Pressure-volume-temperature Polymer-alternating-gas Residual resistance factor Dykstra-Parsons permeability variation coefficient Water-alternating-gas Acknowledgements Financial support for this study was provided by Chaparral LLC. The authors wish to thank DeLon Flinchum and Matt Stover for their contribution of ideas and data. Thanks are also due to Steve Guillot, Scott Wehner and Mark Fischer for their suggestions on preparing the manuscript. REFERENCES 1. ZHANG, Y., HUANG, S.S. and LUO, P., Coupling Immiscible CO 2 Technology and Polymer Injection to Maximize EOR Performance for Heavy Oils; Journal of Canadian Petroleum Technology, Vol. 49, No. 5, pp , HELLER, J.P., DANDGE, D.K., CARD, R.J. and DONARUMA, L.G., Direct Thickeners for Mobility Control of CO 2 Floods; SPE Journal, Vol. 25, No. 5, pp , TERRY, R.E., ZAID, A. and WHITMAN, D.L., Polymerization in Supercritical CO 2 to Improve CO 2 /Oil Mobility Ratios; Paper SPE 1627 presented at the SPE International Symposium on Oilfield Chemistry, San Antonio, TX, 4-6 February MCCLAIN, J.B., BETTS, D.E., CANELAS, D.A., SAMULSKI, E.T., DESIMONE, J.M., LANDONA, J.D. and WIGNALL, G.D., Characterization of Polymers and Amphiphiles in Supercritical CO 2 using Small Angle Neutron Scattering and Viscometry; Proceedings of the 1996 Spring Meeting of the ACS, Division of Polymeric Materials, New Orleans, LA, Science and Engineering, Vol. 74, pp , BAE, J.H. and IRANI, C.A., A Laboratory Investigation of Viscosified CO 2 Process; SPE Advanced Technology Series, Vol. 1, No. 1, pp , LANE, R.H., ALI, H.A. AL-ALI and SCHECHTER, D.S., Application of Polymer Gels as Conformance Control Agents for Carbon Dioxide EOR WAG Floods; Paper SPE presented at the SPE International Symposium on Oilfield Chemistry, The Woodlands, TX, 8-1 April ENICK, R.M., OLSEN, D.K., AMMER, J.R. and SCHULLER, W., Mobility and Conformance Control for CO 2 EOR via Thickeners, Foams, and Gels A Literature Review of 4 Years of Research and Pilot Tests; Paper SPE presented at the SPE Improved Oil Recovery Symposium, Tulsa, OK, April KULKARNI, M.M. and RAO, D.N., Experimental Investigation of Miscible and Immiscible Water-Alternating-Gas (WAG) Process Performance; Journal of Petroleum Science and Engineering; Vol. 48, Nos. 1-2, pp. 1-2, MAJIDAIE, S., KHANIFAR, A., ONUR, M. and TAN, I.M., A Simulation Study of Chemically Enhanced Water Alternating Gas (CWAG) Injection; Paper SPE presented at the SPE EOR Conference at Oil and Gas West Asia, Muscat, Oman, April JOHNSON, C.L., Burbank Field U.S.A. Anadarko Basin, Oklahoma; AAPG Special Volumes, in TR: Stratigraphic Traps III, pp , HUNTER, Z.Z., North Burbank Unit Water Flood - Progress Report, January 1, 1956; API Drilling and Production Practices, pp , RIGGS, C.H., Burbank floods promise 18 million barrels of oil; Oil and Gas Journal, November 1, pp , Core Data, Calumet Oil Company, TCHUISSEU DIEUTCHOU, V., Overpressuring and Seal Structure of Pennsylvanian Red Fork Formation in the Anadarko Basin: Oklahoma; Oklahoma State University, OK, CARDOTT, B.J., Thermal Maturity of Woodford Shale Gas and Oil Plays, Oklahoma, USA; Journal of Coal Geology, Vol. 13, pp , December Cai, S.Z., Study of CO 2 Mobility Control Using Cross-linked Gel Conformance Control and CO 2 Viscosifiers In Heterogeneous Media; M.Sc. Thesis, Texas A&M University, College Station, TX, August 21. CETI Anthropogenic CO 2 for EOR in the North Burbank Unit. CETI April 214 2(1): xx-xx. Submitted 5 November 213; Revised 13 March 214; Accepted xx April 214. 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8 Authors Biographies Weirong Li is currently a Ph.D student in the Petroleum Engineering Department at Texas A&M University. Li worked for Petrochina as a reservoir engineer from 27 to 21. Li holds an M.S. degree in petroleum engineering from the Research Institute of Petroleum Exploration and Development, China, and a B.S. degree in petroleum engineering from Northeast Petroleum University, China. Li has focused his research in areas involving numerical simulation of chemical flooding and gas flooding. Dr. David S. Schechter received his B.S. degree in chemical engineering from the University of Texas at Austin (1984) and his Ph.D. in physical chemistry from Bristol University, England (1988). He was a postdoctoral research associate and Acting Assistant Professor at Stanford University from Dr. Schechter was a Senior Scientist at the Petroleum Recovery Research Center at New Mexico Tech from During that time, he was an adjunct professor in chemical engineering. He is currently Associate Professor of Petroleum Engineering at Texas A&M University. Dr. Schechter is author and Principal Investigator for a Department of Energy/National Petroleum Technology Office Class III Field Demonstration CO 2 project in the naturally fractured Spraberry Trend Area, although his interests extend to all facets of characterization, reservoir engineering and enhanced oil recovery and/or sequestration by CO 2 injection. Dr. Schechter has 23 years of direct experience with CO 2, including everything from basic laboratory studies to development of full field CO 2 floods. 8