Techno-economic assessment of industrial CO2 storage in depleted shale gas reservoirs

The long-term storage of carbon dioxide (CO2) via injection into deep geologic formations represents a promising technological pathway to reducing greenhouse gas emissions to the atmosphere. Geologic storage in deep saline aquifers has been studied extensively, and the injection of CO2 for enhanced oil recovery (EOR) from conventional (porous and permeable) formations has been practiced for decades. This study is focused on developing a preliminary assessment of the economic feasibility of storing CO2 in depleted unconventional natural gas-bearing shale formations. Using a surrogate reservoir model (SRM) and a flexible environment for techno-economic analysis, this paper presents site-scale estimates of long-term CO2 sequestration costs in depleted shale gas formations and discussion of the likely major cost drivers. This analysis focuses on the transportation of CO2 from industrial point sources in the Pennsylvania Marcellus Shale region, and the transition of Marcellus wells from production to CO2 injection. This approach couples techno-economic analysis with reservoir simulation models to estimate costs associated with transportation, injection, CO2 separation and post-injection monitoring of CO2 storage permanence from large industrial point sources in depleted shale-gas reservoirs. We also consider potential revenue from incremental CH4 recovery (effectively enhanced gas recovery) in reservoir scenarios where such production is significant. The techno-economic model boundary includes pipeline transport from an industrial source (excludes the cost of capture of CO2 at that source), site preparation and CO2 flooding operations, and long-term monitoring and post-injection site care (PISC) at the storage site. Under an operational scenario where a Marcellus shale gas well is in primary production for 42 years prior to the initiation of CO2 injection, it is estimated that CO2 could be transported and stored at a levelized cost of $40-$80 per metric tonne, in present value terms. These costs are shown to be highly sensitive to assumptions regarding well spacing, bottomhole pressure, CO2 transport distance and the future price of natural gas. In most of the scenarios considered, transportation and injection costs were dominant factors, while CO2 separation, pore space acquisition and post-injection site care/monitoring did not significantly influence levelized costs.