• Energy Research

Abstract The importance of carbon capture and storage in mitigating climate change has emerged from the results of techno-economic or integrated assessment modeling, in which scenarios of future energy systems are developed subject to constraints from economic growth and climate change targets. These models rarely include limits imposed by injectivity, ultimate amounts, or the geographic distribution of storage resources. However, they could if a sufficiently simple model were available. We develop a methodology for the fast assessment of the dynamic storage resource of a reservoir under different scenarios of well numbers and interwell distance. The approach combines the use of a single-well multiphase analytical solution and the superposition of pressure responses to evaluate the pressure buildup in a multiwell scenario. The injectivity is directly estimated by means of a nonlinear relationship between flow-rate and overpressure and by imposing a limiting overpressure, which is evaluated on the basis of the mechanical parameters for failure. The methodology is implemented within a tool, named CO2BLOCK, which can optimise site design for the numbers of wells and spacing between wells. Given its small computational expense, the methodology can be applied to a large number of sites within a region. We apply this to analyse the storage potential in the offshore of the UK. We estimate that 25–250 GtCO2 can be safely stored over an injection time interval of 30 years. We also demonstrate the use of the tool in evaluating tradeoffs between infrastructure costs and maximising injectivity at two specific sites in the offshore UK.

AbstractDisplaced faults crossing the reservoir could significantly increase the induced earthquake frequency in geo‐energy projects. Understanding and predicting the stress variation in such cases is essential to minimize the risk of induced seismicity. Here, we adopt the inclusion theory to develop an analytical solution for the stress response to pore pressure variations within the reservoir for both permeable and impermeable faults with offset ranging from zero to the reservoir thickness. By analyzing fault stability changes due to reservoir pressurization/depletion under different scenarios, we find that (1) the induced seismicity potential of impermeable faults is always larger than that of permeable faults under any initial and injection conditions—the maximum size of the fault undergoing failure is 3–5 times larger for impermeable than for permeable faults; (2) stress concentration at the corners results in the occurrence of reversed slip in normal faults with a normal faulting stress regime; (3) while fault offset has no impact on the slip potential for impermeable faults, the slip potential increases with the offset for permeable faults, which indicates that non‐displaced permeable faults constitute a safer choice for site selection; (4) an impermeable fault would rupture at a lower deviatoric stress, and at a smaller pressure buildup than a permeable one; and (5) the induced seismicity potential is overestimated and the injectivity underestimated if the stress arching (i.e., the poromechanical coupling) is neglected. This analytical solution is a useful tool for site selection and for supporting decision making during the lifetime of geo‐energy projects.