Factors Controlling Fluid Migration and Distribution in the Eagle Ford Shale
- Roberto Aguilera (University of Calgary) | John Freddy Ramirez Vargas (University of Calgary)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- July 2016
- Document Type
- Journal Paper
- 403 - 414
- 2016.Society of Petroleum Engineers
- Eagle Ford, Buoyancy, Fluids Migration, Condensate, dry gas and oil
- 3 in the last 30 days
- 539 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 10.00|
|SPE Non-Member Price:||USD 30.00|
Production of shale and tight oil is the cornerstone of the United States race for energy independence. According to the US Energy Information Administration, approximately 90% of the oil-production growth comes from six tight-oil plays. The Eagle Ford is one of these plays, and it accounts for 33% of the oil-production growth with a contribution of 1.3 million B/D. This is outstanding. However, oil recoveries as a percentage of the original oil in place (OOIP) are extremely low. This must be improved. A geological challenge in the Eagle Ford shale is the understanding of unconventional fluids distribution over geologic time: Shallower in the structure, there is black oil; deeper and to the south; condensate appears; and at the bottom, dry gas can be found. Differences in burial depth, temperature, and vitrinite reflectance are used to explain this unique distribution. A similar fluid distribution occurs in other unconventional reservoirs (e.g., Duvernay shale in Canada). The low oil recovery and the unusual distribution of fluids led to the key objective of this paper—to identify the main factors that control fluid migration (caused by buoyancy of gas in oil) from one zone to another through geologic time. This was performed by constructing a conceptual cross-sectional compositional simulation model with northwest/southeast orientation that allowed the study of fluid migration, fluid distribution, and fluid contacts throughout 1 million years while maintaining computational time within reasonable limits. The controlling parameters studied were porosity, permeability, pore-throat aperture (rp35), and spacing between natural fractures. Results show that fluids in the matrix remained with approximately the same original distribution (i.e., approximately the same dry-gas/condensate contact and approximately the same condensate/oil contact). These fluids are the target of an ongoing research project with the ultimate goal of improving oil recovery from tight reservoirs by means of enhanced oil recovery (EOR) (Fragoso et al. 2015). There is, however, some gas migration through natural fractures to the top of the structure. This migration is interpreted in this study to be responsible for higher initial gas production in some oil wells in the top of the structure. Some operators indicate, however, that rapid gas/oil-ratio increases in the updip oil region are the result of low reservoir pressures and the rapid onset of two-phase flow. It would probably take geochemical evidence to support this conclusion.
|File Size||1 MB||Number of Pages||12|
Addison, V. 2016. EOG Shifts Drilling Strategy, Pushes EOR. http://www.epmag.com/eog-shifts-drilling-strategy-pushes-eor-847741 (accessed 16 May 2016).
Aguilera, Roberto. 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. http://dx.doi.org/10.2118/165360-PA.
Beaumont, E. A. and Foster, N. H. (eds.) 1999. Exploring for Oil and Gas Traps, AAPG Treatise of Petroleum Geology. In Handbook of Petroleum Geology.
Breyer, J. A., Denne, R., Funk, J. et al. 2013. Stratigraphy and Sedimentary Facies of the Eagle Ford Shale (Cretaceous) Between the Maverick Basin and the San Marcos Arch, Texas, USA, Search and Discovery, Article #50899.
Cantisano, M. T., Restrepo, D. P., Cespedes, S. et al. 2013. Relative Permeability in a Shale Formation in Colombia Using Digital Rock Physics. Presented at the Unconventional Resources Technology Conference, Denver, USA, 12–14 August. SPE-168681-MS. http://dx.doi.org/10.1190/URTEC2013-092.
Fan, L., Martin, R. B., Thompson, J. W. et al. 2011. An Integrated Approach for Understanding Oil and Gas Reserves Potential in Eagle Ford Shale Formation. Presented at the Canadian Unconventional Resources Conference, Calgary, 15–17 November. SPE-148751-MS. http://dx.doi.org/10.2118/148751-MS.
Fragoso, A., Wang, Y., Jing, G. et al. 2015. Improving Recovery of Liquids from Shales Through Gas Recycling and Dry Gas Injection. Presented at the Latin American and Caribbean Petroleum Engineering Conference, Quito, Ecuador, 18–20 November. SPE-177278-MS. http://dx.doi.org/10.2118/177278-MS.
Gale, J. F. W., Laubach, S. E., Olson, J. E. et al. 2014. Natural Fractures in Shale: A Review and New Observations. AAPG Bull. 98 (11): 2165–2216. http://dx.doi.org/10.1306/08121413151.
Gong, X., Tian, Y., McVay, D. A. et al. 2013. Assessment of Eagle Ford Shale Oil and Gas Resources. Presented at the SPE Unconventional Resources Conference–Canada, Calgary, 5–7 November. SPE-167241-MS. http://dx.doi.org/10.2118/167241-MS.
Holditch, S. 1979. Factors Affecting Water Blocking and Gas Flow From Hydraulically Fractured Gas Wells. J Pet Technol. 31 (12): 1515–1524. SPE-7561-PA. http://dx.doi.org/10.2118/7561-PA.
Honarpour, M. M., Nagarajan, N. R., Orangi, A. et al. 2012. Characterization of Critical Fluid Pressure/Volume/Temperature, Rock and Rock-Fluid Properties—Impact on Reservoir Performance of Liquid-Rich Shales. Presented at the 2012 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, 8–10 October. SPE-158042-MS. http://dx.doi.org/10.2118/158042-MS.
Kazemi, H., Merril, L. S., Porterfield, K. L. et al. 1976. Numerical Simulation of Water-Oil Flow in Naturally Fractured Reservoirs. SPE J. 16 (6): 317–326. SPE-5719-PA. http://dx.doi.org/10.2118/5719-PA.
Lopez, B. and Aguilera, R. 2016. Flow Units in Shale Condensate Reservoirs. SPE Res Eval & Eng. SPE-178619-PA (in press; posted April 2016). http://dx.doi.org/10.2118/178619-PA.
Magoon, L. B. and Dow, W. D. (eds.) 1994. The Petroleum System—From Source to Trap. AAPG Memoir 60.
Martin, R., Baihly, J. D., Malpani, R. et al. 2011. Understanding Production From Eagle Ford-Austin Chalk System. Presented at the SPE Annual Technical Conference and Exhibition, Denver, USA, 30 October–2 November. SPE-145117-MS. http://dx.doi.org/10.2118/145117-MS.
Peters, K. E., Curry, D. J., and Kacewicz, M. (eds.) 2012. An Overview of Basin and Petroleum System Modeling: Definitions and Concepts. In Basin Modeling: New Horizons in Research and Applications, AAPG Hedberg Series No. 4, 1–16.
Pommer, M. and Milliken, K. 2015. Pore Types and Pore-Size Distributions Across Thermal Maturity, Eagle Ford Formation, Southern Texas. AAPG Bull. 99 (9):1713–1744. http://dx.doi.org/10.1306/03051514151.
Railroad Commission of Texas. 2016. Eagle Ford Shale Information, http://www.rrc.state.tx.us/oil-gas/major-oil-gas-formations/eagle-fordshale/ (accessed 16 May 2016).
Welte, D. H., Horsfield, B., and Baker, D. R. (eds.) 1997. Petroleum and Basin Evolution: Insights From Petroleum Geochemistry, Geology and Basin Modeling. New York: Springer.