Estimating Sustainable Long-Term Fluid Disposal Rates in the Alberta Basin

Mahendra Samaroo (), Rick Chalaturnyk and Maurice Dusseault
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Mahendra Samaroo: Department of Civil and Environmental Engineering, University of Alberta, Edmonton, AB T6G 2R3, Canada
Rick Chalaturnyk: Department of Civil and Environmental Engineering, University of Alberta, Edmonton, AB T6G 2R3, Canada
Maurice Dusseault: Department of Earth and Environmental Sciences, University of Waterloo, Waterloo, ON N2L 3G1, Canada

Energies, 2023, vol. 16, issue 6, 1-37

Abstract: Reliable regional-scale permeability data and minimum sustained injectivity rate estimates are key parameters required to mitigate economic risk in the site selection, design, and development of commercial-scale carbon sequestration projects, but are seldom available. We used extensive publicly available disposal well data from over 4000 disposal wells to assess and history-match regional permeability estimates and provide the frequency distribution for disposal well injection rates in each of 66 disposal formations in the Alberta Basin. We then used core data and laboratory analyses from over 3000 cores to construct 3D geological, geomechanical and petrophysical models for 22 of these disposal formations. We subsequently used these models and the history-matched regional permeability estimates to conduct coupled geomechanical and reservoir simulation modeling (using the ResFrac™, Palo Alto, CA, USA, numerical simulator) to assess: (i) well performance in each formation when injecting carbon dioxide for a 20-year period; (ii) carbon dioxide saturation and reservoir response at the end of the 20-year injection period; (iii) reliability of our simulated rates compared to an actual commercial sequestration project. We found that: (i) the injection rate from our simulations closely matched actual performance of the commercial case; (ii) only 7 of the 22 disposal formations analyzed appeared capable of supporting carbon dioxide injectors operating at greater than 200,000 tons per year/well; (iii) three of these formations could support injectors operating at rates comparable to the successful commercial-scale case; (iv) carbon dioxide presence and a formation pressure increase of at least 25% above pre-injection pressure can be expected at the boundaries of the (12 km × 12 km) model domain at the end of 20 years of injection.

Keywords: subsurface risk; injectivity; fracturing; Alberta Basin; CO 2 sequestration; coupled 3D modeling; mechanical earth models; induced seismicity (search for similar items in EconPapers)
JEL-codes: Q Q0 Q4 Q40 Q41 Q42 Q43 Q47 Q48 Q49 (search for similar items in EconPapers)
Date: 2023
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