Abstract
Injection of carbon dioxide into a natural gas reservoir is a promising technology for reducing anthropogenic gas emissions and increasing ultimate recovery of natural gas. Computer simulation is an important, inexpensive tool for designing pilot projects and predicting optimal tradeoffs between maximum methane production and maximum sequestration.
To investigate the amount of carbon dioxide sequestered and the effect of carbon dioxide injection on gas recovery, different injection strategies were used for a thin, shaly sandstone reservoir situated in Northern West Virginia. Two injection scenarios were studied: (1) simultaneous CO2 injection and methane recovery from the very beginning of the project, and (2) primary production of natural gas to the economic limit, followed by injection of carbon dioxide for secondary gas recovery. Horizontal injectors were used to increase injectivity. A 160-acre inverted 5-spot well pattern was studied for a pilot test.
The simulation results show that the highest methane recovery was obtained when the reservoir was produced under primary recovery until the economic limit, followed by CO2 injection. The maximum amount of incremental gas recovery was less than 10% of the original gas in place (OGIP). Lower recovery factors for methane were obtained in the case when CO2 injection was injected early. However, the early CO2 injection accelerated methane recovery and improved CO2 retention in the reservoir. The simulations also showed that there was an optimum length for the horizontal injectors to sequester the maximum amount of CO2.
By varying operational parameters such as time of primary production, injector length, injection pressure, injection timing, and production well pressure we can evaluate different production schemes to determine an optimum recovery of methane vs. CO2 sequestration. The findings of this study can be useful for finding tradeoffs between methane production and CO2 sequestration.
