Improving Oil Recovery by Use of Carbon Dioxide in the Bakken Unconventional System: A Laboratory Investigation
- Lu Jin (Energy & Environmental Research Center) | James A. Sorensen (Energy & Environmental Research Center) | Steven B. Hawthorne (Energy & Environmental Research Center) | Steven A. Smith (Energy & Environmental Research Center) | Lawrence J. Pekot (Energy & Environmental Research Center) | Nicholas W. Bosshart (Energy & Environmental Research Center) | Matthew E. Burton-Kelly (Energy & Environmental Research Center) | David J. Miller (Energy & Environmental Research Center) | Carol B. Grabanski (Energy & Environmental Research Center) | Charles D. Gorecki (Energy & Environmental Research Center) | Edward N. Steadman (Energy & Environmental Research Center) | John A. Harju (Energy & Environmental Research Center)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- August 2017
- Document Type
- Journal Paper
- 602 - 612
- 2017.Society of Petroleum Engineers
- Experimental Investigation, CO2 EOR, Bakken Formation, Unconventional Reservoir, Diffusion
- 8 in the last 30 days
- 787 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 12.00|
|SPE Non-Member Price:||USD 35.00|
Compared with a conventional reservoir, the ultralow permeability in the Bakken Formation makes it very challenging to perform normal waterflooding or gasflooding operations. “Permeability-jail” effects cause low injectivity and prevent injected fluids from sweeping oil out of the matrix efficiently. Two distinguishable flow regimes have been identified in fractured, hydrocarbon-rich shale formations: viscous flow in high-permeability fracture networks and diffusion-dominated flow in the low-permeability matrix with high oil saturation. Improving hydrocarbon transport (and technically recoverable resources) in unconventional reservoirs relies on our ability to enhance diffusion-dominated flow from the oil-saturated matrix to the natural- or induced-fracture network, which is the focus of this study.
To unlock the unproduced Bakken and Three Forks oil, high-pressure carbon dioxide (CO2) may be used to enhance the diffusion-dominated flow in the matrix and keep the viscous flow in the fractures under reservoir temperature and pressure conditions (e.g., 230°F and 5,000 psi). Core samples were collected from two Bakken wells, including all oil-bearing intervals: Upper Bakken (UB), Middle Bakken (MB), and Lower Bakken (LB) Members and the Three Forks (TF) Formation. Detailed core analyses were performed to measure petrophysical properties and characterize these units. Ten samples were selected for pore-sizedistribution measurement and 21 samples (11-mm-diameter rods) were used for 24-hour CO2 exposures and hydrocarbon-recovery experiments. These experiments were conducted as CO2 “bathing” at reservoir conditions (rather than “flow through” tests) and were aimed at increasing our understanding of the microstructure and diffusion-dominated-flow ability within these tight geologic formations.
CO2-exposure and hydrocarbon-extraction experimental results clearly showed the improvement of diffusion-dominated flow in all the Bakken members. The UB and LB samples, characterized by generally high total-organic-carbon (TOC) content (10–15 wt%) and small pore size (approximately 3–7 nm), yielded approximately 60% of the present mature hydrocarbon at the end of the 24-hour exposure. The MB and TF samples, characterized by lower TOC content (<0.5 wt.%) and moderate pore size (approximately 8–80 nm), provided more-favorable flow conditions for CO2 and hydrocarbons, yielding approximately 90% of the mature-hydrocarbon content. Because all experiments were conducted at reservoir conditions, the results demonstrate that diffusion plays a significant role in the mobilization of oil in tight reservoirs.
CO2 greatly enhances the diffusion process to improve hydrocarbon transport in the tight matrix. This observation is especially useful for densely fractured shale-oil formations (high surfacearea/volume ratio) where CO2 has greater areal contact with the reservoir, enabling CO2 diffusion into the matrix and hydrocarbon diffusion out of the matrix to occur more efficiently (increasing recoverable reserves), and where the fracture networks assist in alleviating potential injectivity challenges.
|File Size||1 MB||Number of Pages||11|
Afonja, G., Hughes, R. G., Rao, V. G. et al. 2012. Simulation Study for Optimizing Injected Surfactant Volume in a Miscible Carbon Dioxide Flood. Presented at the SPETT 2012 Energy Conference and Exhibition, Port-of-Spain, Trinidad, 11–13 June. SPE-158220-MS. https://doi.org/10.2118/158220-MS.
Aguilera, R. 2014. Flow Units: From Conventional to Tight-Gas to Shale-Gas to Tight-Oil to Shale-Oil Reservoirs. SPE Res Eval & Eng 17 (2): 190–208. SPE-165360-PA. https://doi.org/10.2118/165360-PA.
Alfi, M., Yan, B., Cao, Y. et al. 2014. How to Improve Our Understanding of Gas and Oil Production Mechanisms in Liquid-rich Shale. Presented at the SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. SPE-170959-MS. https://doi.org/10.2118/170959-MS.
Aryana, S. A., Barclay, C., and Liu, S. 2014. North Cross Devonian Unit–A Mature Continuous CO2 Flood Beyond 200% HCPV Injection. Presented at the SPE Annual Technical Conference and Exhibition, Amsterdam, 27–29 October. SPE-170653-MS. https://doi.org/10.2118/170653-MS.
Baihly, J. D., Altman, R. M., and Avlies, I. 2012. Has the Economic Stage Count Been Reached in the Bakken Shale? Presented at the SPE Hydrocarbon Economics and Evaluation Symposium, Calgary, 24–25 September. SPE-159683-MS. https://doi.org/10.2118/159683-MS.
Dacy, J. M. 2010. Core Tests for Relative Permeability of Unconventional Gas Reservoirs. Presented at the SPE Annual Technical Conference and Exhibition, Florence, Italy, 19–22 September. SPE-135427-MS. https://doi.org/10.2118/135427-MS.
Du, L. and Chu, L. 2012. Understanding Anomalous Phase Behavior in Unconventional Oil Reservoirs. Presented at the SPE Canadian Unconventional Resources Conference, Calgary, 30 October–1 November. SPE-161830-MS. https://doi.org/10.2118/161830-MS.
Eide, Ø., Fernø, M. A., Alcorn, Z. et al. 2016. Visualization of Carbon Dioxide Enhanced Oil Recovery by Diffusion in Fractured Chalk. SPE J. 21 (1): 112–120. SPE-170920-PA. https://doi.org/10.2118/170920-PA.
Hawthorne, S. B., Gorecki, C. D., Sorensen, J. A. et al. 2014. Hydrocarbon Mobilization Mechanisms Using CO2 in an Unconventional Oil Play. Energy Procedia 63: 7717–7723. https://doi.org/10.1016/j.egypro.2014.11.805.
Hawthorne, S. B., Miller, D. J., Jin, L. et al. 2016. Rapid and Simple Capillary-Rise/Vanishing Interfacial Tension Method to Determine Crude Oil Minimum Miscibility Pressure: Pure and Mixed CO2, Methane, and Ethane. Energy. Fuel. 30 (8): 6365–6372. https://doi.org/=10.1021/acs.energyfuels.6b01151.
Holm, L. W. and Josendal, V. A. 1974. Mechanisms of Oil Displacement by Carbon Dioxide. J Pet Technol 26 (12): 1427–1438. SPE-4736-PA. https://doi.org/10.2118/4736-PA.
Honarpour, M. M., Nagarajan, N. R., Orangi, A. et al. 2012. Characterization of Critical Fluid PVT, Rock, and Rock-Fluid Properties—Impact on Reservoir Performance of Liquid Rich Shales. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8–10 October. SPE-158042-MS. https://doi.org/10.2118/158042-MS.
Hosseini, S. A., Javadpour, F., and Michael, G. E. 2015. Novel Analytical Core-Sample Analysis Indicates Higher Gas Content in Shale-Gas Reservoirs. SPE J. 20 (6): 13971408. SPE-174549-PA. https://doi.org/10.2118/174549-PA.
Javadpour, F., Fisher, D., and Unsworth, M. 2007. Nanoscale Gas Flow in Shale Gas Sediments. J Can Pet Technol 46 (10). PETSOC-07-10-06. https://doi.org/10.2118/07-10-06.
Javadpour, F., McClure, M., and Naraghi, M. E. 2015. Slip-Corrected Liquid Permeability and Its Effect on Hydraulic Fracturing and Fluid Loss in Shale. Fuel 160 (15 November): 549–559. https://doi.org/10.1016/j.fuel.2015.08.017.
Jin, L. and Wojtanowicz, A. K. 2010. Coning Control and Recovery Improvement Using In-Situ Water Drainage/Injection in Bottom/Water/Drive Reservoir. Presented at the SPE Improved Oil Recovery Symposium, Tulsa, 24–28 April. SPE-129663-MS. https://doi.org/10.2118/129663-MS.
Jin, L. and Wojtanowicz, A. K. 2011a. Minimum Produced Water From Oil Wells with Water-Coning Control and Water-Loop Installations. Presented at the SPE Americas E&P Health, Safety, Security, and Environmental Conference, Houston, 21–23 March. SPE-143715-MS. https://doi.org/10.2118/143715-MS.
Jin, L. and Wojtanowicz, A. K. 2011b. Analytical Assessment of Waterfree Production in Oil Wells with Downhole Water Loop for Coning Control. Presented at the SPE Production and Operations Symposium, Oklahoma City, Oklahoma, 27–29 March. SPE-141470-MS. https://doi.org/10.2118/141470-MS.
Jin, L. and Wojtanowicz, A. K. 2013. Experimental and Theoretical Study of Counter-Current Oil Water Separation in Wells with In-situ Water Injection. J. Pet. Sci. Eng. 109 (September): 250–259. https://doi.org/10.1016/j.petrol.2013.08.037.
Jin, L. and Wojtanowicz, A. K. 2014. Progression of Injectivity Damage With Oily Waste Water in Linear Flow. Petrol. Sci. 11 (4): 550–562. https://doi.org/10.1007/s12182-013-0371-0.
Jin, L., Hawthorne, S., Sorensen, J. et al. 2016. A Systematic Investigation of Gas-based Improved Oil Recovery Technologies for the Bakken Tight Oil Formation. Presented at the Unconventional Resources Technology Conference, San Antonio, Texas, 1–3 August. URTEC-2433692-MS.
Jin, L., Pu, H., Wang, Y. et al. 2015. The Consideration of Pore Size Distribution in Organic-Rich Unconventional Formations May Increase Oil Production and Reserve by 25%, Eagle Ford Case Study. Presented at the Unconventional Resources Technology Conference, San Antonio, Texas, 20–22 July. SPE-178507-MS. https://doi.org/10.2118/178507-MS.
Jin, L., Wojtanowicz, A. K., and Hughes, R. G. 2010. An Analytical Model for Water Coning Control Installation in Reservoirs with Bottomwater. J Can Pet Technol 49 (5): 65–70. SPE-137787-PA. https://doi.org/10.2118/137787-PA.
Johnson, J. W. and LeBreton, J. M. 2004. History and Use of Relative Importance Indices in Organizational Research. Organ. Res. Meth. 7 (3): 238257. https://doi.org/10.1177/1094428104266510.
Jones, R. S. Jr. 2016. Producing-Gas/Oil-Ratio Behavior of Multifractured Horizontal Wells in Tight Oil Reservoirs. Presented at the Unconventional Resources Technology Conference, San Antonio, Texas, 1–3 August. URTEC-2460396-MS.
Josh, M., Esteban, L., Delle Piane, C. et al. 2012. Laboratory Characterisation of Shale Properties. J. Pet. Sci. Eng. 88–89 (June): 107–124. https://doi.org/10.1016/j.petrol.2012.01.023.
Kazi, T., Li, Y., Jin, L. et al. 2015. How Typical Langmuir Isotherm Curves Underestimate OGIP and Production by 20%, a Barnett Case Study. Oral presentation given at the Southwest Section AAPG Annual Convention, Wichita Falls, Texas, 11–14 April.
Khoshghadam, M., Khanal, A., and Lee, W. J. 2015. Numerical Study of Impact of Nano-Pores on Gas-Oil Ratio and Production Mechanisms in Liquid-Rich Shale Oil Reservoirs. Presented at the Unconventional Resources Technology Conference, San Antonio, Texas, 20–22 July. SPE-178577-MS. https://doi.org/10.2118/178577-MS.
Klenner, R. C. L., Braunberger, J. R., Sorensen, J. A. et al. 2014. A Formation Evaluation of the Middle Bakken Member Using a Multimineral Petrophysical Analysis Approach. Presented at the Unconventional Resources Technology Conference, Denver, 25–27 August. URTEC-1922735-MS.
Kovscek, A. R., Tang, G.-Q., and Vega, B. 2008. Experimental Investigation of Oil Recovery from Siliceous Shale by CO2 Injection. Presented at the SPE Annual Technical Conference and Exhibition, Denver, 21–24 September. SPE-115679-MS. https://doi.org/10.2118/115679-MS.
Kuila, U. 2013. Measurement and Interpretation of Porosity and Pore-Size Distribution in Mudrocks: the Hole Story of Shales. PhD dissertation, Colorado School of Mines, Golden, Colorado.
Kurtoglu, B. and Kazemi, H. 2012. Evaluation of Bakken Performance Using Coreflooding, Well Testing, and Reservoir Simulation. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8–10 October. SPE-155655-MS. https://doi.org/10.2118/155655-MS.
Kurtoglu, B., Rasdi, F., Salman, A. et al. 2013. Evaluating Long Term Flow Regimes in Unconventional Oil Reservoirs with Diverse Completion Technology. Presented at the SPE Unconventional Resources Conference-Canada, Calgary, 5–7 November. SPE-167145-MS. https://doi.org/10.2118/167145-MS.
Kurtoglu, B., Salman, A., and Kazemi, H. 2015. Production Forecasting Using Flow Back Data. Presented at the SPE Middle East Unconventional Resources Conference and Exhibition, Muscat, Oman, 26–28 January. SPE-172922-MS. https://doi.org/10.2118/172922-MS.
Kutner, M. H., Nachtsheim, C., Neter, J. et al. 2004. Applied Linear Statistical Models, fifth edition. New York City: McGraw-Hill. Mathworks 2015. http://mathworks.com/products/matlab/.
Monger, T. G., Ramos, J. C., and Thomas, J. 1991. Light Oil Recovery From Cyclic CO2 Injection: Influence of Low Pressures, Impure CO2, and Reservoir Gas. SPE Res Eng 1 (6): 25–32. SPE-18084-PA. https://doi.org/10.2118/18084-PA.
Montgomery, D. C. and Runger, G. C. 2010. Applied Statistics and Probability for Engineers. New York City: John Wiley & Sons. National Institute of Standards and Technology (NIST). 2013. NIST/SEMATECH Engineering Statistics Handbook. Gaithersburg, Maryland: NIST.
Nojabaei, B., Johns, R. T., and Chu, L. 2013. Effect of Capillary Pressure on Phase Behavior in Tight Rocks and Shales. SPE Res Eval & Eng 16 (3): 281–289. SPE-159258-PA. https://doi.org/10.2118/159258-PA.
Ozkan, E., Raghavan, R. S., and Apaydin, O. G. 2010. Modeling of Fluid Transfer from Shale Matrix to Fracture Network. Presented at the SPE Annual Technical Conference and Exhibition, Florence, Italy, 19–22 September. SPE-134830-MS. https://doi.org/10.2118/134830-MS.
Ozkan, S., Kurtoglu, B., and Ozkan, E. 2012. Long-Term Economic Viability of Production from Unconventional Liquids-Rich Reservoirs: The Case of Bakken Field. SPE Econ & Mgmt 4 (4): 215–221. SPE-162901-PA. https://doi.org/10.2118/162901-PA.
Pitman, J. K., Price, L. C., and LeFever, J. A. 2001. Diagenesis and Fracture Development in the Bakken Formation, Williston Basin: Implications for Reservoir Quality in the Middle Member. US Geological Survey Professional Paper 1653, US Department of the Interior and US Geological Survey, Denver, November 2001.
Pollastro, R. M., Roberts, L. N. R., and Cook, T. A. 2013. Geologic Assessment of Technically Recoverable Oil in the Devonian and Mississippian Bakken Formation. In Assessment of Undiscovered Oil and Gas Resources of the Williston Basin Province of North Dakota, Montana, and South Dakota, 2010, US Geological Survey Digital Data Series DDS–69–W, Chap. 5, US Department of the Interior and US Geological Survey, Reston, Virginia.
Ran, B. and Kelkar, M. 2015. Fracture Stages Optimization in Bakken Shale Formation. Presented at the Unconventional Resources Technology Conference, San Antonio, Texas, 20–22 July. SPE-178615-MS. https://doi.org/10.2118/178615-MS.
Roy, S., Raju, R., Chuang, H. F. et al. 2003. Modeling Gas Flow Through Microchannels and Nanopores. J. App. Phys. 93 (4870). https://doi.org/10.1063/1.1559936.
Sakhaee-Pour, A. and Bryant, S. 2012. Gas Permeability of Shale. SPE J. 15 (4): 401–409. SPE-146944-PA. https://doi.org/10.2118/146944-PA.
Salako, O. and MacBeth, C. 2015. Effective Imaging of Reservoir Fluid Changes. Oral presentation given at the 77th EAGE Conference and Exhibition, Madrid, Spain, 1–4 June.
Tonidandel, S. and LeBreton, J. M. 2014. RWA Web: A Free, Comprehensive, Web-Based, and User-Friendly Tool for Relative Weight Analyses. J. Bus. Psychol. 30 (2): 207–216. https://doi.org/10.1007/s10869-014-9351-z.
Tovar, F. D., Eide, O., Graue, A. et al. 2014. Experimental Investigation of Enhanced Recovery in Unconventional Liquid Reservoirs Using CO2: A Look Ahead to the Future of Unconventional EOR. Presented at the SPE Unconventional Resources Conference, The Woodlands, Texas, 1–3 April. SPE-169022-MS. https://doi.org/10.2118/169022-MS.
Wan, T. and Sheng, J. 2015. Compositional Modeling of the Diffusion Effect on EOR Process in Fractured Shale Oil Reservoirs by Gas Flooding. J Can Pet Technol 54 (2): 107–115. SPE-2014-1891403-PA. https://doi.org/10.2118/2014-1891403-PA.
Wan, T., Yu, Y., and Sheng, J. J. 2015. Experimental and Numerical Study of the EOR Potential in Liquid-Rich Shales by Cyclic Gas Injection. J. Unconven. Oil Gas Resour. 12 (December): 5667. https://doi.org/10.1016/j.juogr.2015.08.004.
Whitson, C. H. and Sunjerga, S. 2012. PVT in Liquid-Rich Shale Reservoirs. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8–10 October. SPE-155499-MS. https://doi.org/10.2118/155499-MS.
Zhang, K., Perdomo, M. E. G., Kong, B. et al. 2015. CO2 Near-Miscible Flooding for Tight Oil Exploitation. Presented at the SPE Asia Pacific Unconventional Resources Conference and Exhibition, Brisbane, Australia, 9–11 November. SPE-176826-MS. https://doi.org/10.2118/176826-MS.
Ziarani, A. S. and Aguilera, R. 2012. Knudsen’s Permeability Correction for Tight Porous Media. Transp. Porous Med. 91 (1): 239260. https://doi.org/10.1007/s11242-011-9842-6.