Assessing the feasibility of CO2 storage in the New Albany Shale (Devonian-Mississippian) with potential enhanced gas recovery using reservoir simulation

The feasibility of storing carbon dioxide (CO2) in geologic formations as a means to mitigate global climate change is being evaluated around the globe. One option that has received limited attention is to store CO2 in shale formations that are currently productive unconventional shale gas plays. While CO2 trapping mechanisms in saline aquifers are primarily structural, capillary, solubility, and mineral trapping, the mechanisms are fundamentally different in gas shales, and CO2 adsorption onto organic materials and clay minerals plays a key role. Shale gas formations have a high content of organic matter that may store significant amounts of adsorbed natural gas, ranging from 20% to 80% of original-gas-in-place (OGIP). Laboratory and theoretical calculations suggest that CO2 is adsorbed preferentially over methane (CH4) onto the organics and could displace the methane (with up to a 5:1 ratio by molecule). This mechanism could be the basis of a new method of carbon capture, utilization, and storage (CCUS) that stores the CO2 in gas shales with the potential added benefit of enhanced gas recovery (EGR). This investigation evaluates the hypothesis of CO2 storage with EGR using reservoir modeling of the Devonian and Mississippian New Albany Shale gas play in the Illinois Basin, USA. The shale was evaluated in terms of CO2 injectivity, storage capacity, and effectiveness, as well as the impact of CO2 injection on methane recovery. The modeling technique employs a dual-porosity, dual-permeability approach, incorporating horizontal wells with multi-stage hydraulic fractures, Darcian and diffusive flow, gas sorption/desorption, hysteresis effects, and CO2 dissolution. Our simulation results demonstrate that CO2 storage in the New Albany Shale is feasible. Approximately 4 x 10(4) metric tonnes of CO2 could be injected through one horizontal well (having four hydraulic fracture stages) within 5 years with minimal CO2 breakthrough (less than 1% of the injected CO2). Over 95% of the injected CO2 is effectively sequestered instantaneously with gas adsorption being the dominate storage mechanism. Residual trapping and solubility trapping sequester only similar to 0.4% and 1.1%, respectively, of the injected CO2. Sensitivity tests were conducted on several key geological parameters (total organic carbon content, natural fracture conductivity, and matrix permeability) and engineering parameters (stimulated rock volume and hydraulic fracture conductivity). Among the evaluated factors, CO2 storage effectiveness appears to be dominated by changes in the stimulated rock volume and the total organic carbon content. Incremental CH4 recovery from CO2 injection was not substantial (similar to 1%) in either the CO2 flood or the huff-n-puff scenario under the simulated reservoir conditions and well designs, possibly because the unstimulated tight shale rock between the CO2 injector and CH4 producer impeded effective mass and pressure communication, which prerequisites for successful EGR. However, in the huff-n-puff scenario, with a similar amount of CH4 produced, a noticeable amount of CO2 was sequestered simultaneously. Assumptions, approximations, and compromises were made in the current modeling work because of gaps in the current knowledge base about various aspects of the gas shale reservoirs. These limitations are discussed in an effort to prioritize future research on this topic using experimental and observational methods, modeling tools, and field tests. (C) 2013 Elsevier Ltd. All rights reserved.