Diffusion-Dominated Proxy Model for Solvent Injection in Ultratight Oil Reservoirs
- Michael Cronin (Pennsylvania State University) | Hamid Emami-Meybodi (Pennsylvania State University) | Russell T. Johns (Pennsylvania State University)
- Document ID
- Society of Petroleum Engineers
- SPE Journal
- Publication Date
- April 2019
- Document Type
- Journal Paper
- 660 - 680
- 2019.Society of Petroleum Engineers
- Diffusion, Huff Soak Puff, Solvent Injection, Shale Oil, Enhanced Oil Recovery
- 4 in the last 30 days
- 482 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 5.00|
|SPE Non-Member Price:||USD 35.00|
Enhanced oil recovery (EOR) by solvent injection offers significant potential to increase recovery from shale oil reservoirs, which is typically between 3 and 7% original oil in place (OOIP). The rather sparse literature on this topic typically models these tight reservoirs on the basis of conventional-reservoir processes and mechanisms, such as by convective transport using Darcy’s law, even though there is little physical justification for this treatment. The literature also downplays the importance of the soaking period in huff ’n’ puff.
In this paper, we propose, for the first time, a more physically realistic recovery mechanism based on solely diffusion-dominated transport. We develop a diffusion-dominated proxy model assuming first-contact miscibility (FCM) to provide rapid estimates of oil recovery for both primary production and the solvent huff ’n’ soak ’n’ puff (HSP) process in ultratight oil reservoirs. Simplified proxy models are developed to represent the major features of the fracture network.
The key results show that diffusion-transport considered solely can reproduce the primary-production period within the Eagle Ford Shale and can model the HSP process well, without the need to use Darcy’s law. The minimum miscibility pressure (MMP) concept is not important for ultratight shales where diffusion dominates because MMP is based on advection-dominated conditions. The mechanism for recovery is based solely on density and concentration gradients. Primary production is modeled as a self-diffusion process, whereas the HSP process is modeled as a counter-diffusion process. Incremental recoveries by HSP are several times greater than primary-production recoveries, showing significant promise in increasing oil recoveries. We calculate ultimate recoveries for both primary production and for the HSP process, and show that methane injection is preferred over carbon dioxide injection. We also show that the proxy model, to be accurate, must match the total matrix-contact area and the ratio of effective area to total contact area with time. These two parameters should be maximized for best recovery.
|File Size||2 MB||Number of Pages||21|
Abbasi, M. A., Ezulike, D. O., Dehghanpour, H. et al. 2014. A Comparative Study of Flowback Rate and Pressure Transient Behavior in Multifractured Horizontal Wells Completed in Tight Gas and Oil Reservoirs. Journal of Natural Gas Science and Engineering 17: 82–93. https://doi.org/10.1016/j.jngse.2013.12.007.
Adel, I. A., Tovar, F. D., Zhang, F. et al. 2018. The Impact of MMP on Recovery Factor During CO2–EOR in Unconventional Liquid Reservoirs. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, 24–26 September. SPE-191752-MS. https://doi.org/10.2118/191752-MS.
Albinali, A. and Ozkan, E. 2016. Anomalous Diffusion Approach and Field Application for Fractured Nano-Porous Reservoirs. Presented at the SPE Annual Technical Conference and Exhibition, Dubai, 6–28 September. SPE-181255-MS. https://doi.org/10.2118/181255-MS.
Alfarge, D., Wei, M., and Bai, B. 2017a. Factors Affecting CO2-EOR in Shale-Oil Reservoirs: Numerical Simulation Study and Pilot Tests. Energy & Fuels 31 (31): 8462–8480. https://doi.org/10.1021/acs.energyfuels.7b01623.
Alfarge, D., Wei, M., and Bai, B. 2017b. IOR Methods in Unconventional Reservoirs of North America: Comprehensive Review. Presented at the SPE Western Regional Meeting, Bakersfield, California, 23–27 April. SPE-185640-MS. https://doi.org/10.2118/185640-MS.
Amann-Hildenbrand, A., Ghanizadeh, A., and Krooss, B. M. 2012. Transport Properties of Unconventional Gas Systems. Marine and Petroleum Geology 31 (31): 90–99. https://doi.org/10.1016/j.marpetgeo.2011.11.009.
Carlson, E. S. and Mercer, J. C. 1991. Devonian Shale Gas Production: Mechanisms and Simple Models. J Pet Technol 43 (4): 476–482. SPE-19311-PA. https://doi.org/10.2118/19311-PA.
Carslaw, H. S. and Jaeger, J C. 1986. Conduction of Heat in Solids, second edition. Oxford University Press (Reprint).
da Silva, F. V. and Belery, P. 1989. Molecular Diffusion in Naturally Fractured Reservoirs: A Decisive Recovery Mechanism. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8–11 October. SPE-19672-MS. https://doi.org/10.2118/19672-MS.
Dahi-Taleghani, A. and Olson, J. E. 2013. How Natural Fractures Could Affect Hydraulic-Fracture Geometry. SPE J. 19 (1): 161–171. SPE-167608-PA. https://doi.org/10.2118/167608-PA.
Darvish, G. R., Lindeberg, E. G. B., Holt, T. et al. 2006. Reservoir Conditions Laboratory Experiments of CO2 Injection Into Fractured Cores. Presented at the SPE Europec/EAGE Annual Conference and Exhibition, Vienna, Austria, 12–15 June. SPE-99650-MS. https://doi.org/10.2118/99650-MS.
Dejam, M., Hassanzadeh, H. and Chen, Z. 2017. Pre-Darcy Flow in Porous Media. Water Resources Research 53 (53): 8187–8210. https://doi.org/10.1002/2017WR021257.
EIA. 2017. Annual Energy Outlook 2017 With Projections to 2050. January 2017 edition (Reprint). https://www.eia.gov/analysis/studies/worldshalegas/archive/2013/pdf/fullreport_2013.pdf.
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.
Elsharkawy, A. M., Poettmann, F. H., and Christiansen, R. L. 1992. Measuring Minimum Miscibility Pressure: Slim-Tube or Rising-Bubble Method? Presented at the SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, 22–24 April. SPE-24114-MS. https://doi.org/10.2118/24114-MS.
EP Energy. 2012. EP Energy Operations Update I. US Securities and Exchange Commission, Exhibit 99.A (reprint). https://www.sec.gov/Archives/edgar/data/1066107/000110465912021517/a12-7733_4ex99da.htm.
Fernø, M. A, Hauge, L. P., and Rognmo, A. U. et al. 2015. Flow Visualization of CO2 in Tight Shale Formations at Reservoir Conditions. Geophysical Research Letters 42 (42): 7414–7419. https://doi.org/10.1002/2015GL065100.
Gamadi, T. D., Sheng, J. J., Soliman, M. Y. et al. 2014. An Experimental Study of Cyclic CO2 Injection to Improve Shale Oil Recovery. Presented at the SPE Improved Oil Recovery Symposium, Tulsa, 12–16 April. SPE-169142-MS. https://doi.org/10.2118/169142-MS.
Ghasemi, M., Astutik, W., Alavian, S. A. et al. 2017. Determining Diffusion Coefficients for Carbon Dioxide Injection in Oil-Saturated Chalk by Use of a Constant-Volume-Diffusion Method. SPE J. 22 (2): 505–520. SPE-179550-PA. https://doi.org/10.2118/179550-PA.
Gong, X. 2013. Assessment of Eagle Ford Shale Oil and Gas Resources. PhD dissertation, Texas A&M University, College Station, Texas, USA (July 2013).
Grisak, G. E. and Pickens, J. F. 1981. An Analytical Solution for Solute Transport Through Fractured Media With Matrix Diffusion. Journal of Hydrology 52 (1–2): 47–57. https://doi.org/10.1016/0022-1694(81)90095-0.
Grogan, A. T., Pinczewski, V. W., Ruskauff, G. J. et al. 1988. Diffusion of CO2 at Reservoir Conditions: Models and Measurements. SPE Res Eng 3 (1): 93–102. SPE-14897-PA. https://doi.org/10.2118/14897-PA.
Hawthorne, S. B., Gorecki, C. D. Sorensen, J. A. et al. 2013. Hydrocarbon Mobilization Mechanisms From Upper, Middle, and Lower Bakken Reservoir Rocks Exposed to CO2. Presented at the SPE Unconventional Resources Conference Canada, Calgary, 5–7 November. SPE-167200-MS. https://doi.org/10.2118/167200-MS.
Hawthorne, S. B., Miller, D. J., Grabanski, C. B. et al. 2017. Measured Crude Oil MMPs With Pure and Mixed CO2, Methane, and Ethane, and Their Relevance to Enhanced Oil Recovery From Middle Bakken and Bakken Shales. Presented at the SPE Unconventional Resources Conference, Calgary, 15–16 February. SPE-185072-MS. https://doi.org/10.2118/185072-MS.
Hoteit, H. and Firoozabadi, A. 2009. Numerical Modeling of Diffusion in Fractured Media for Gas-Injection and -Recycling Schemes. SPE J. 14 (2): 323–337. SPE-103292-PA. https://doi.org/10.2118/103292-PA.
Johns, R. T., Emami-Meybodi. H., and Cronin, M. 2018. Techniques for Improved Recovery in Ultra-Tight Reservoirs Based on Diffusion. US Patent Application 62643367. March 2018.
Kolesar, J. E., Ertekin, T., and Obut, S. T. 1990a. The Unsteady-State Nature of Sorption and Diffusion Phenomena in the Micropore Structure of Coal: Part 1—Theory and Mathematical Formulation. SPE Form Eval 5 (1): 81–88. SPE-15233-PA. https://doi.org/10.2118/15233-PA.
Kolesar, J. E., Ertekin, T. and Obut, S. T. 1990b. The Unsteady-State Nature of Sorption and Diffusion Phenomena in the Micropore Structure of Coal: Part 2—Solution. SPE Form Eval 5 (1): 89–97. SPE-19398-PA. https://doi.org/10.2118/19398-PA.
Lake, L. W., Johns, R. T., Rossen, W. R. et al. 2014. Fundamentals of Enhanced Oil Recovery, 496 pp. Richardson, Texas: Society of Petroleum Engineers (Reprint).
Li, L. and Sheng, J. J. 2016. Experimental Study of Core Size Effect on CH4 Huff-n-Puff Enhanced Oil Recovery in Liquid-Rich Shale Reservoirs. Journal of Natural Gas Science and Engineering 34: 1392–1402. https://doi.org/10.1016/j.jngse.2016.08.028.
Li, L., Zhang, Y., and Sheng, J. J. 2017. Effect of the Injection Pressure on Enhancing Oil Recovery in Shale Cores During the CO2 Huff-n-Puff Process When It Is Above and Below the Minimum Miscibility Pressure. Energy & Fuels 31 (31): 3856–3867. https://doi.org/10.1021/acs.energyfuels.7b00031.
Luo, P., Luo, W., and Li, S. 2017. Effectiveness of Miscible and Immiscible Gas Flooding in Recovering Tight Oil From Bakken Reservoirs in Saskatchewan, Canada. Fuel 208 (Supplement C): 626–636. https://doi.org/10.1016/j.fuel.2017.07.044.
Mohebbinia, S. and Wong, T. 2017. Molecular Diffusion Calculations in Simulation of Gasfloods in Fractured Reservoirs. Presented at the SPE Reservoir Simulation Conference, Montgomery, Texas, 20–22 February. SPE-182594-MS. https://doi.org/10.2118/182594-MS.
Morel, D., Bourbiaux, B., Latil, M. et al. 1993. Diffusion Effects in Gasflooded Light-Oil Fractured Reservoirs. SPE Advanced Technology Series 1 (2): 100–109. SPE-20516-PA. https://doi.org/10.2118/20516-PA.
Olorode, O., Freeman, C. M., Moridis, G. et al. 2013. High-Resolution Numerical Modeling of Complex and Irregular Fracture Patterns in Shale-Gas and Tight Gas Reservoirs. SPE Res Eval & Eng 16 (4): 443–455. SPE-152482-PA. https://doi.org/10.2118/152482-PA.
Olorode, O. M., Akkutlu, I. Y., and Efendiev, Y. 2017. Compositional Reservoir Flow Simulation for Organic-Rich Gas Shale. SPE J. 22 (6): 1963–1983. SPE-182667-PA. https://doi.org/10.2118/182667-PA.
Ozkan, E., Brown, M. L., Raghavan, R. et al. 2011. Comparison of Fractured-Horizontal-Well Performance in Tight Sand and Shale Reservoirs. SPE Res Eval & Eng 14 (2): 248–259. SPE-121290-PA. https://doi.org/10.2118/121290-PA.
Patzek, T. W., Male, F., and Marder, M. 2013. Gas Production in the Barnett Shale Obeys a Simple Scaling Theory. Proc. of the National Academy of Sciences. http://www.pnas.org/content/early/2013/11/12/1313380110.abstract.
Patzek, T. W., Saputra, W., and Kirati, W. 2017. A Simple Physics-Based Model Predicts Oil Production From Thousands of Horizontal Wells in Shales. Presented at the SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 9–11 October. SPE-187226-MS. https://doi.org/10.2118/187226-MS.
Peng, D. Y. and Robinson, D. B. 1976. A New Two-Constant Equation of State. Ind. Eng. Chem. Fundamen. 15 (1): 59–64. https://doi.org/10.1021/i160057a011.
Raghavan, R. and Chen, C. 2013. Fractional Diffusion in Rocks Produced by Horizontal Wells With Multiple, Transverse Hydraulic Fractures of Finite Conductivity. Journal of Petroleum Science and Engineering 109: 133–143. https://doi.org/10.1016/j.petrol.2013.08.027.
Raghavan, R. and Chen, C. 2016. Rate Decline, Power Laws, and Subdiffusion in Fractured Rocks. SPE Res Eval & Eng 20 (3): 738–751. SPE-180223-PA. https://doi.org/10.2118/180223-PA.
Rassenfoss, S. 2017. Shale EOR Works, But Will It Make a Difference? J Pet Technol 69 (10), https://www.spe.org/en/jpt/jpt-article-detail/?art=3391 (downloaded 17 November 2017).
Riazi, M. R., Whitson, C. H. and da Silva, F. 1994. Modelling of Diffusional Mass Transport in Naturally Fractured Reservoirs. Journal of Peroleum Science and Engineering 10 (3): 239–253. https://doi.org/10.1016/0920-4105(94)90084-1.
Ringrose, P. and Bentley, M. 2016. Reservoir Model Design A Practitioner’s Guide, 245. Dordrecht Heidelberg New York London, Springer (Reprint).
Sherafati, M. and Jessen, K. 2018. Coarse-Scale Modeling of Multicomponent Diffusive Mass Transfer in Dual-Porosity Models. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, 24–26 September. SPE-191568-MS. https://doi.org/10.2118/191568-MS.
Siripatrachai, N., Ertekin, T., and Johns, R. T. 2017. Compositional Simulation of Hydraulically Fractured Tight Formation Considering the Effect of Capillary Pressure on Phase Behavior. SPE J. 22 (4): 1046–1063. SPE-179660-PA. https://doi.org/10.2118/179660-PA.
Solano, R., Johns, R.T., and Lake, L. W. 2001. Impact of Reservoir Mixing on Recovery in Enriched-Gas Drives Above the Minimum Miscibility Enrichment. SPE Res Eval & Eng 4 (4): 358–365. SPE-73829-PA. https://doi.org/10.2118/73829-PA.
Sorensen, J. A., Hawthorne, S. B., Smith, S. A. et al. 2014. Subtask 1.10—CO2 Storage and Enhanced Bakken Recovery Research Program (Final Report Prepared for DOE NETL Award No. DE-FC26-08NT43291). Grand Forks, North Dakota, University of North Dakota (Reprint). https://www.undeerc.org/bakken/PDFs/JAS-Subtask%201.10%20Revised-Jun14.pdf.
Stalkup, F. I., Jr. 1983. Status of Miscible Displacement. J Pet Technol 35 (4): 815–826. SPE-9992-PA. https://doi.org/10.2118/9992-PA.
Tezuka, K., Kamitsuji, R., and Tamagawa, T. 2008. Fractured Reservoir Characterization Incorporating Microseismic Monitoring and Pressure Analysis During Massive Hydraulic Injection. Presented at the International Petroleum Technology Conference, Kuala Lumpur, 3–5 December. IPTC-12391-MS. https://doi.org/10.2523/IPTC-12391-MS.
Todd, H. B. and Evans, J. G. 2016. Improved Oil Recovery IOR Pilot Projects in the Bakken Formation. Presented at the SPE Low Perm Symposium, Denver, 5–6 May. SPE-180270-MS. https://doi.org/10.2118/180270-MS.
Walton, I. and McLennan, J. 2013. The Role of Natural Fractures in Shale Gas Production. Presented at the ISRM International Conference for Effective and Sustainable Hydraulic Fracturing, Brisbane, Australia, 20–22 May. ISRM-ICHF-2013-046.
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. Journal of Unconventional Oil and Gas Resources 12: 56–67. https://doi.org/10.1016/j.juogr.2015.08.004.
Yu, W., Lashgari, H., and Sepehrnoori, K. 2014. Simulation Study of CO2 Huff-n-Puff Process in Bakken Tight Oil Reservoirs. Presented at the SPE Western North American and Rocky Mountain Joint Regional Meeting, Denver, 17–18 April. SPE-169575-MS. https://doi.org/10.2118/169575-MS.
Yu, Y. and Sheng, J. J. 2016. Experimental Evaluation of Shale Oil Recovery From Eagle Ford Core Samples by Nitrogen Gas Flooding. Presented at the SPE Improved Oil Recovery Conference, Tulsa, 11–13 April. SPE-179547-MS. https://doi.org/10.2118/179547-MS.
Zoback, M. D. 2010. Reservoir Geomechanics, Cambridge University Press (Reprint).
Zuloaga-Molero, P., Yu, W., Xu, Y. et al. 2016. Simulation Study of CO2-EOR in Tight Oil Reservoirs With Complex Fracture Geometries. Scientific Reports 6: 33445. https://doi.org/10.1038/srep33445.