Hydrogeologic Modeling Aimed at Optimizing Injection Well Operation in a Hypothetical Multi-Injection Well Reservoir: Implications for Induced Seismicity

Abstract:

Recent studies in the field of induced seismicity have shown high injection rates as the predominant driver of the recent increase in U.S. mid-continent seismicity. In regions with critically stressed, optimally oriented preexisting faults, well operation and the ability of a pore pressure perturbation to reach one of these faults governs the likelihood of an induced seismic event. Past case studies of hypothetical injections have simulated the pressure perturbation of single well injection systems, without considering the effect of pressure perturbation superposition in a multi-well injection system. In some regions where seismicity is suspected to be induced, the spatial density of injection wells can be greater than 5 wells per 5 km², suggesting the effects of well superposition may be significant. In addition, induced earthquakes often occur on previously unrecognized faults, which leads us to aim towards minimizing the region of reservoir pressure perturbation above a designated critical pressure threshold. We test several well operational and hydrogeologic parameters that control the magnitude, timing and extent of pressure perturbation superposition in a hypothetical multi-injection well system. The parameters tested in the model are injection well spacing, injection rate as well as the permeability and storage coefficients of the injection reservoir. The magnitude, timing and extent of pressure perturbation superposition is highly dependent upon all tested parameters. Furthermore, optimal injection well spacing and optimal injection rates vary greatly based on hydrogeologic parameters. We compare the results of our hypothetical simulations to observed injection well spacing, injection rates and seismicity rates per unit area in regions prone to induced seismicity.