Induced Seismicity Hazard Assessment for a Potential CO2 Storage Site in the Southern San Joaquin Basin, CA

Kohli, Arjun; Li, Yunan; Kim, Tae Wook; Kovscek, Anthony R.

doi:10.3390/geohazards4040024

Cited by 3 publications

References 25 publications

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Optimizing Injection Well Trajectory to Maximize Storage Security and Minimize Geomechanical Risk

Li,

ONeal,

Whitezell

et al. 2024

SPE Western Regional Meeting

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Summary The objective is to demonstrate an optimal well design for a potential geological carbon storage (GCS) project. CO2 plume shape, size, and pressure response in the subsurface are design variables. The chosen well trajectory improves injectivity while minimizing formation pressure buildup. The CO2 plume shape and migration are controlled within a complex dipping storage formation. In order to achieve the goals, we designed a toolbox (pyCMG) to standardize the well design optimization process that is applicable to different carbon storage assets. This toolbox is helpful to maximize storage security and minimize geomechanical risk. We developed a numerical model of transport within a storage formation fully coupled with geomechanical deformation to represent a prospective GCS site in Kern County, California. It honors a pre-defined injection scheme with injection rates that ramp up and then decline for a total of 12.3 Mt of CO2 injection in 18 years. The peak injection rate is greater than 1 Mt/yr whereas the post injection period is 100 years. The pyCMG toolbox allows efficient computations for hundreds of cases. It is useful to understand potential outcomes and optimize the well trajectory to fulfill plume and pressure buildup constraints while satisfying the target inject amount. We propose to develop a long, deviated injection well to best address the injectivity and plume migration challenges for this heterogeneous, dipping formation. The well design optimization successfully reduces the pressure build-up by 54% over the base design while only increasing the areal extent of the plume by 8.4%. We quantified the carbon dioxide plume shape and size at the land surface. The plume grows rapidly at the beginning due to injection, it increases slightly after shut-in due to slow up-dip migration driven by buoyancy, and becomes stationary within the post-injection monitoring period. The optimal injector design balances the optimization goals of CO2 plume size, pressure increase in storage formation, and pressure build-up at fault. The optimal well is robust under uncertainties from injection schemes and geological model realizations. The best injector is capable to enlarge the total storage amount with an average of annual injection rates greater than 1 Mt/yr. Rock deformation due to the pressure buildup is also computed. The maximum land uplift is predicted to be 2.1 cm during the year of the peak annual injection rate. Land surface uplift strongly correlates with the subsurface pressure response.

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Optimizing Injection Well Trajectory to Maximize Storage Security and Minimize Geomechanical Risk

Li,

ONeal,

Whitezell

et al. 2024

SPE Western Regional Meeting

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Optimizing Injection Well Trajectory to Maximize CO2 Storage Security and Minimize Geomechanical Risk

Li,

ONeal,

Whitezell

et al. 2024

SPE Journal

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Summary The work demonstrates an optimal well design for a potential geological carbon storage (GCS) project in Kern County, California (USA). Carbon dioxide (CO2) plume shape, size, and pressure response history in the subsurface are outcomes. We created a toolbox (pyCCUS) to standardize the well design optimization process and it is applicable to different carbon storage assets. This toolbox is helpful to maximize storage security and minimize geomechanical risk. The numerical model of the storage formation features two-way coupled transport and geomechanical deformation. It honors a predefined injection scheme with injection rates that ramp up and then decline for a total of 12.3 MtCO2 injection in 18 years. The peak injection rate is greater than 1 MtCO2/yr, whereas the post-injection monitoring period is 100 years. We propose to develop a long, deviated injection well to best address the injectivity and plume migration challenges for this complex, heterogeneous, dipping formation. The chosen well trajectory improves injectivity while minimizing formation pressure buildup. The well design optimization successfully reduces the pressure buildup by 54% over the base design while only increasing the areal extent of the plume by 21%. We quantify the CO2 plume shape and size at the land surface. The plume grows rapidly during injection, but it increases only slightly after shut-in due to slow updip migration driven by buoyancy. The plume becomes stationary within the post-injection monitoring period. The optimal injector design balances the optimization goals of CO2 plume size, pressure increase, and pressure buildup at geological faults. The optimal injection well design is robust under uncertainties from injection schemes and geological model realizations. Rock deformation due to the pressure buildup is also computed. The model estimates 2.1 cm of uplift that occurs during the year of the peak annual injection rate. Land surface uplift strongly correlates with the subsurface pressure response.

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3-D Leakage and Seismic Hazard Assessment for a Potential CO2 Storage Site in the Southern San Joaquin Basin, CA

Kohli,

Kim,

et al. 2024

SPE Western Regional Meeting

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We investigate the hazards of leakage and induced seismicity for a potential CO2 storage site in the southern San Joaquin Basin, CA. Total injection is scheduled for 12.3 MtCO2 with variable rates over 18 years followed by 100 years of monitoring. We extend our prior analysis from 2-D to 3-D to account for variations in rock properties and the state of stress with depth. The CO2 saturation and pressure fields are simulated in a 3-D reservoir model that is optimized to minimize the pressure change on faults and the overall size of the CO2 saturation plume. We estimate CO2 and brine leakage rates along faults and existing wells that intersect the storage formation using the NRAP OPEN-IAM tool. We construct a vertical stress profile for site from pilot well data and estimate the probability of fault slip using the Fault Slip Potential tool. Faults and existing wells that penetrate the storage reservoir allow for brine and CO2 leakage, but leakage rates to USDW are negligible. Faults that are well oriented for slip in the stress field and within the pressure plume of the injector present the greatest hazard of induced seismicity. In the optimal simulation case, the probability of slip on potentially active faults does not increase significantly over the storage period and decreases rapidly to pre-injection values during the monitoring period. This study improves our prior protocol for CO2 storage hazard assessment by considering how 3-D variations in rock properties impact the potential for leakage and slip on faults.

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Induced Seismicity Hazard Assessment for a Potential CO2 Storage Site in the Southern San Joaquin Basin, CA

Cited by 3 publications

References 25 publications

Optimizing Injection Well Trajectory to Maximize Storage Security and Minimize Geomechanical Risk

Optimizing Injection Well Trajectory to Maximize Storage Security and Minimize Geomechanical Risk

Optimizing Injection Well Trajectory to Maximize CO2 Storage Security and Minimize Geomechanical Risk

3-D Leakage and Seismic Hazard Assessment for a Potential CO2 Storage Site in the Southern San Joaquin Basin, CA

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