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.