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

Abstract

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.