Sensitivity and history match analysis of a carbon dioxide "huff-and-puff" injection test in a horizontal shale gas well in Tennessee

Due to improvements in well development, shale gas production has gained importance in recent years, especially in the United States. To improve gas production and develop a better understanding of shale reservoirs, researchers are conducting field tests to monitor CO2 storage and enhanced gas recovery. Reservoir simulations can then utilize these field results for sensitivity studies, uncertainty analysis, history matching, gas production forecasts, and CO2 storage capacity estimations. One such field test was performed for the Chattanooga Shale formation in Morgan County, Tennessee. Approximately 463 tonnes (510 tons) of CO2 was successfully injected into a hydraulically fractured horizontal well over a thirteen-day period in March 2014. The injection test was achieved in four steps: pre-injection, injection, soaking, and flowback. In this paper, those steps were modeled with a reservoir simulator to match the historic production and injection rates with gas component compositions and forecast the production for five years. The reservoir fluid was modeled as a multi-component gas, including CH4, C2H6, C3H8, N-2, and CO2. Langmuir constants, reservoir pressure, and fracture network volume were adjusted to match simulation results with observed production rates and gas composition. Results showed that, under the same reservoir conditions, each gas component behaves differently by way of compositional changes in production. CH4 behaves like N-2, while CO2 behaves like heavier hydrocarbons such as C2H6 and C3H8. CO2 plume results showed that, after injection, the produced CO2 is mostly derived from fractured limestone (i.e., Fort Payne Formation) because the injected CO2 is not adsorbed in limestone but rather by shale formations.