Carbon Dioxide Storage in Deltaic Saline Aquifers: Invasion Percolation and Compositional Simulation
- Shayan Tavassoli (The University of Texas at Austin) | Prasanna Krishnamurthy (The University of Texas at Austin) | Emily Beckham (The University of Texas at Austin) | Tip Meckel (The University of Texas at Austin) | Kamy Sepehrnoori (The University of Texas at Austin)
- Document ID
- Society of Petroleum Engineers
- SPE Reservoir Evaluation & Engineering
- Publication Date
- September 2020
- Document Type
- Journal Paper
- 2020.Society of Petroleum Engineers
- deltaic formation, compositional simulation, geological modeling, CO2 storage, invasion percolation
- 16 in the last 30 days
- 53 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||USD 5.00|
|SPE Non-Member Price:||USD 35.00|
Storage of large amounts of carbon dioxide (CO2) within deep underground aquifers has great potential for long-term mitigation of climate change. The U.S. Gulf Coast is an attractive target for CO2 storage because of the favorable formation properties for injection and containment of CO2. Deltaic formations are one of the primary targeted depositional environments in the Gulf Coast. In this paper, we investigate CO2 storage in deltaic saline aquifers through a combination of geological modeling and flow simulation. The approach presented in this paper based on a combination of invasion percolation and compositional reservoir simulation focuses on buoyancy-dominant flow of CO2 in the long term and its pressure-driven flow in the short term. The results provide insights into how to screen and identify prospective locations for CO2 storage and determine the underlying geological features controlling CO2 migration for a basin-scale study.
The geological model in our study is developed based on a laboratory-scale three-dimensional (3D) flume experiment replicating the formation of a delta structure and populated with geologic properties according to Miocene Gulf of Mexico natural analogues. We used invasion percolation simulations to understand the buoyancy-driven flow and the relationship between architecture, stratigraphy, and fluid migration pathways. The results were used to develop an upscaled model for compositional simulation with the key features of the original geological model and to determine injection schemes that maximize the injection capacity and minimize the amount of mobile CO2 in the formation. To achieve this, we used compositional reservoir simulations to study the pressure-driven flow and phase behavior.
The results of invasion percolation simulations were used to identify the key stratigraphic units affecting CO2 migration. The realistic geometries and high resolution of the model facilitate the transfer of results from synthetic to subsurface data. The results allow for the analysis of deltaic depositional environments, important stratigraphic surfaces, and their impact on CO2 storage. The reservoir simulation model and phase behavior were validated against available field and laboratory data. The results of reservoir simulations were used to investigate the effects of main mechanisms, such as gas trapping and solubilization, on storage capacity. We compared our simulation results based on invasion percolation (buoyancy driven) and reservoir simulation (pressure driven). The comparison is helpful to understand the strengths and weaknesses of each approach and determine best practices to evaluate CO2 migration within similar formations.
The unique and extremely well-characterized deltaic model allows for unprecedented representation of the depositional aquifer architecture. This research combines geologic modeling, flow simulation, and application for CO2 storage. The integrated conclusions will constrain predictions of actual subsurface flow performance and CO2 storage capacity in deltaic systems while identifying potential risks and primary stratigraphic migration pathways. This research provides insights on prediction of CO2 storage performance and characterization of prospective saline aquifers.
|File Size||7 MB||Number of Pages||13|
Bachu, S. and Adams, J. J. 2003. Sequestration of CO2 in Geological Media in Response to Climate Change: Capacity of Deep Saline Aquifers To Sequester CO2 in Solution. Energy Convers & Manag 44 (20): 3151–3175. https://doi.org/10.1016/S0196-8904(03)00101-8.
Beckham, E. C. 2018. CO2 Storage in Deltaic Environments of Deposition: Integration of 3-Dimensional Modeling, Outcrop Analysis, and Subsurface Application. Master’s thesis, The University of Texas at Austin, Austin, Texas, USA.
Bennion, B. and Bachu, S. 2005. Relative Permeability Characteristics for Supercritical CO2 Displacing Water in a Variety of Potential Sequestration Zones. Paper presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, USA, 9–12 October. SPE-95547-MS. https://doi.org/10.2118/95547-MS.
Bennion, B. and Bachu, S. 2008. Drainage and Imbibition Relative Permeability Relationships for Supercritical CO2/Brine and H2S/Brine Systems in Intergranular Sandstone, Carbonate, Shale, and Anhydrite Rocks. SPE J. 11 (3): 1–13. SPE-99326-PA. https://doi.org/10.2118/99326-PA.
Benson, S. M. and Cole, D. R. 2008. CO2 Sequestration in Deep Sedimentary Formations. Elements 4 (5): 325–331. https://doi.org/10.2113/gselements.4.5.325.
Berg, S. and Ott, H. 2012. Stability of CO2–Brine Immiscible Displacement. Int J Greenhouse Gas Control 11: 188–203. https://doi.org/10.1016/j.ijggc.2012.07.001.
Berkowitz, B. and Balberg, I. 1993. Percolation Theory and Its Application to Groundwater Hydrology. Water Resour Res 29 (4): 775–794. https://doi.org/10.1029/92WR02707.
Bromhal, G. S., Sams, W. N., Jikich, S. et al. 2005. Simulation of CO2 Sequestration in Coal Beds: The Effects of Sorption Isotherms. Chem Geol 217 (3-4): 201–211. https://doi.org/10.1016/j.chemgeo.2004.12.021.
Brooks, R. H. and Corey, A. T. 1966. Properties of Porous Media Affecting Fluid Flow. J Irrigation & Drain Div 92 (2): 61–90.
Bruant, R., Guswa, A., Celia, M. et al. 2002. Safe Storage of CO2 in Deep Saline Aquifers. Environ Sci & Technol Wash DC 36 (11): 240–245. https://doi.org/10.1021/es0223325.
Cantelli, A. W., Kim, J., Martin, J. et al. 2002. NCED Data Repository, https://repository.nced.umn.edu/browser.php?current=location&keyword=17&location=2&dataset_id=2.
Carruthers, D. 1998. Transport Modelling of Secondary Oil Migration Using Gradient-Driven Invasion Percolation Techniques. PhD dissertation, Heriot-Watt University, Edinburgh, Scotland.
Chen, X., Kianinejad, A., and DiCarlo, D. A. 2014. An Experimental Study of CO2-Brine Relative Permeability in Sandstone. Paper presented at the SPE Improved Oil Recovery Symposium, Tulsa, Oklahoma, USA, 12–16 April. SPE-169137-MS. https://doi.org/10.2118/169137-MS.
CMG. 2017. User Guide. Calgary, Alberta, Canada: Computer Modelling Group Ltd.
EPA. 2012. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990–2010. Washington, DC, USA: U.S. Environmental Protection Agency, Office of Atmospheric Programs.
Fenghour, A., Wakeham, W. A., and Vesovic, V. 1998. The Viscosity of Carbon Dioxide. J Phys & Chem Ref Data 27 (1): 31–44. https://doi.org/10.10163/1.556013.
Garcia, J. E. 2001. Density of Aqueous Solutions of CO2. Report LBNL-49023, Lawrence Berkeley National Laboratory, Berkeley, California, USA.
Helland-Hansen, W. and Martinsen, O. J. 1996. Shoreline Trajectories and Sequences: Description of Variable Depositional-Dip Scenarios. SEPM J Sediment Res 66. https://doi.org/10.1306/d42683dd-2b26-11d7-8648000102c1865d.
Holloway, S. 2001. Storage of Fossil Fuel-Derived Carbon Dioxide beneath the Surface of the Earth. Annu Rev Energy & Environ 26 (1): 145–166. https://doi.org/10.1146/annurev.ednergy.26.1.145.
Holtz, M. H. 2002. Residual Gas Saturation to Aquifer Influx: A Calculation Method for 3-D Computer Reservoir Model Construction, Calgary, Alberta, Canada, 30 April–2 May. Paper presented at the SPE Gas Technology Symposium, Calgary, Alberta, Canada, 30 April–2 May. SPE-75502-MS. https://doi.org/10.2118/75502-MS.
Hosseininoosheri, P., Hosseini, S. A., Nuñez-López, V. et al. 2018. Impact of Field Development Strategies on CO2 Trapping Mechanisms in a CO2–EOR Field: A Case Study in the Permian Basin (SACROC Unit). Int J Greenhouse Gas Contr 72: 92–104. https://doi.org/10.1016/j.ijggc.2018.03.002.
IEA. 2009. Development of Storage Coefficients for Carbon Dioxide Storage in Deep Saline Formations. Paris, France: Environmental Projects Ltd. (Greenhouse Gas R&D Programme).
IPCC. 2005. IPCC Special Report on Carbon Dioxide Capture and Storage. Prepared by Working Group III of the Intergovernmental Panel on Climate Change [B. Metz, O. Davidson, H. C. de Coninck, M. Loos, and L. A. Meyer (eds.)]. Cambridge, UK and New York, New York, USA: Cambridge University Press, 442 pp.
Kim, W., Paola, C., Voller, V. et al. 2006. Experimental Measurement of the Relative Importance of Controls on Shoreline Migration. J Sediment Res 76 (2): 270–283. https://doi.org/10.2110/jsr.2006.019.
Kovscek, A. R. and Cakici, M. D. 2005. Geologic Storage of Carbon Dioxide and Enhanced Oil Recovery. II. Cooptimization of Storage and Recovery. Energy Convers & Manag 46 (11-12): 1941–1956. https://doi.org/10.1016/j.enconman.2004.09.009.
Krishnamurthy, P. G., Meckel, T. A., and DiCarlo, D. 2019. Mimicking Geologic Depositional Fabrics for Multiphase Flow Experiments. Water Resour Res 55 (11): 9623–9638. https://doi.org/10.1029/2019WR025664.
Krishnamurthy, P. G., Senthilnathan, S., Yoon, H. et al. 2017. Comparison of Darcy’s Law and Invasion Percolation Simulations with Buoyancy-Driven CO2-Brine Multiphase Flow in a Heterogeneous Sandstone Core. J Pet Sci & Eng 155: 54–62. https://doi.org/10.1016/j.petrol.2016.10.022.
Kumar, A. 2004. A Simulation Study of Carbon Sequestration in Deep Saline Aquifers. MS thesis, The University of Texas at Austin, Austin, Texas, USA.
Kumar, A., Ozah, R., Noh, M. et al. 2005. Reservoir Simulation of CO2 Storage in Deep Saline Aquifers. SPE J. 10 (3): 336–348. SPE-89343-PA. https://doi.org/10.2118/89343-PA.
Land, C. S. 1968. Calculation of Imbibition Relative Permeability for Two-and Three-Phase Flow from Rock Properties. SPE J. 8 (2): 149–156. SPE-1942-PA. https://doi.org/10.2118/1942-PA.
Martin, J., Paola, C., Abreu, V. et al. 2009. Sequence Stratigraphy of Experimental Strata under Known Conditions of Differential Subsidence and Variable Base Level. AAPG Bull 93 (4): 503–533. https://doi.org/10.1306/12110808057.
Mitchum, R. M. 1977. Seismic Stratigraphy and Global Changes of Sea Level, Part 1: Glossary of Terms Used in Seismic Stratigraphy. In Seismic Stratigraphy—Application to Hydrocarbon Exploration: AAPG Memoir, ed. C. E. Payton, Chap. 26, 205–212. Tulsa, Oklahoma, USA: AAPG.
Neshat, S. S. and Pope, G. A. 2018. Three-Phase Relative Permeability and Capillary Pressure Models with Hysteresis and Compositional Consistency. SPE J. 23 (6): 2394–2408. SPE-191384-PA. https://doi.org/10.2118/191384-PA.
Nghiem, L., Sammon, P., Grabenstetter, J. et al. 2004. Modeling CO2 Storage in Aquifers with a Fully Coupled Geochemical EOS Compositional Simulator. Paper presented at the SPE/DOE Symposium on Improved Oil Recovery, Tulsa, Oklahoma, USA, 17–21 April. SPE-89474-MS. https://doi.org/10.2118/89474-MS.
Nghiem, L., Shrivastava, V., Tran, D. et al. 2009. Simulation of CO2 Storage in Saline Aquifers. Paper presented at the SPE/EAGE Reservoir Characterization and Simulation Conference, Abu Dhabi, UAE, 19–21 October. SPE-125848-MS. https://doi.org/10.2118/125848-MS.
Noh, M. H. 2003. Reactive Transport Modeling in Fractures and Two-Phase Flow. PhD dissertation, The University of Texas at Austin, Austin, Texas, USA.
Oldenburg, C. M., Mukhopadhyay, S., and Cihan, A. 2016. On the Use of Darcy’s Law and Invasion-Percolation Approaches for Modeling Large-Scale Geologic Carbon Sequestration. Greenhouse Gases Sci & Technol 6 (1): 19–33. https://doi.org/10.1002/ghg/1564.
Paola, C., Mullin, J., Ellis, C. et al. 2001. Experimental Stratigraphy. Exper Stratigr GSA Today 11 (7): 4. https://www.geosociety.org/gsatoday/archive/11/7/pdf/i1052-5173-11-7-4.pdf.
Pedersen, K. S., Fredenslund, A., Christensen, P. L. et al. 1984. Viscosity of Crude Oils. Chem Eng Sci 39 (6): 1011–1016. https://doi.org/10.1016/0009-2509(84)87009-8.
Permedia. 2013. Migration Software Version 5000.10.0. Ottawa, Ontario, Canada: The Permedia Research Group Inc.
Ryu, J., Espinoza, D. N., Balhoff, M. T. et al. 2019. Simulation of Fault Reactivation Using the HISS Model. Paper presented at the SPE Annual Technical Conference and Exhibition, Calgary, Alberta, Canada, 30 September–2 October 2019. SPE-196153-MS. https://doi.org/10.2118/196153-MS.
Sahimi, M. 2014. Applications of Percolation Theory. Boca Raton, Florida, USA: CRC Press.
Sorkhabi, R. and Tsuji, Y. 2005. The Place of Faults in Petroleum Traps. In Faults, Fluid Flow, and Petroleum Traps: AAPG Memoir, ed. R. Sorkhabi and Y. Tsuji, Vol. 85. Tulsa, Oklahoma, USA: AAPG. https://doi.org/10.1306/M851033.
Stauffer, D. and Aharony, A. 2014. Introduction to Percolation Theory, revised second edition. Boca Raton, Florida, USA: CRC Press.
Strong, N. and Paola, C. 2006. Fluvial Landscapes and Stratigraphy in a Flume. Sedimentary Rec 4 (2): 4–8. https://doi.org/10.2110/sedred.2006.2.4.
Strong, N. and Paola, C. 2008. Valleys that Never Were: Time Surfaces versus Stratigraphic Surfaces. J Sedimentary Res 78 (8): 579–593. https://doi.org/10.2110/jsr.2008.059.
Tavassoli, S., Xu, Y., and Sepehrnoori, K. 2018. Modeling Fault Reactivation Using Embedded Discrete Fracture Method. Paper presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, USA, 24–26 September. SPE-191412-MS. https://doi.org/10.2118/191412-MS.
Teng, H. and Yamasaki, A. 1998. Solubility of Liquid CO2 in Synthetic Sea Water at Temperatures from 278 K to 293 K and Pressures from 6.44 MPa to 29.49 MPa, and Densities of the Corresponding Aqueous Solutions. J Chem & Eng Data 43 (1): 2–5. https://doi.org/10.101/je9700737.
Teng, H., Yamasaki, A., Chun, M. K. et al. 1997. Solubility of Liquid CO2 in Water at Temperatures from 278 K to 293 K and Pressures from 6.44 MPa to 29.49 MPa and Densities of the Corresponding Aqueous Solutions. J Chem Thermodynamics 29 (11): 1301–1310. https://doi.org/10.1006/jcht.1997.0249.
Trevisan, L., Krishnamurthy, P. G., and Meckel, T. A. 2017. Impact of 3D Capillary Heterogeneity and Bedform Architecture at the Sub-Meter Scale on CO2 Saturation for Buoyant Flow in Clastic Aquifers. Int J Greenhouse Gas Control 56: 237–249. https://doi.org/10.1016/j.ijggc.2016.12.001.
Vail, P. R., Mitchum, R. M. Jr., and Thompson, S. III. 1977. Seismic Stratigraphy and Global Changes of Sea Level, Part 3: Relative Changes of Sea Level from Coastal Onlap. In Seismic Stratigraphy—Application to Hydrocarbon Exploration: AAPG Memoir, ed. C. E. Payton, Chap. 26, 63–81. Tulsa, Oklahoma, USA: AAPG.
Wilkinson, D. and Willemsen, J. F. 1983. Invasion Percolation: A New Form of Percolation Theory. J Phys A: Math & Gen 16 (14): 3365–3376. https://doi.org/10.1088/0305-4470/16/14/028.
Yuan, C. and Pope, G. A. 2012. A New Method To Model Relative Permeability in Compositional Simulators To Avoid Discontinuous Changes Caused by Phase-Identification Problems. SPE J. 17 (4): 1221–1230. SPE-142093-PA. https://doi.org/10.2118/142093-PA.
Zaytsev, I. D. and Aseyev, G. G. 1992. Properties of Aqueous Solutions of Electrolytes. Boca Raton, Florida, USA: CRC Press.