Enhanced Gas Recovery (EGR) with Carbon Dioxide Sequestration: A Simulation Study of Effects of Injection Strategy and Operational Parameters

Abstract

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:simultaneous CO2 injection and methane recovery from the very beginning of the project, andprimary 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. Introduction and Background The concentration of the CO2 in the atmosphere is increasing continuously; therefore many countries have pledged to reduce, by 2010, the emissions of greenhouse gases up to 8% relative to levels of 1990 (1). Consequently, CO2 must be captured and stored. Among storage options, the underground storage in depleted oil and gas reservoirs, and unminable coals are considered the most economical and have a low environmental impact. Depleted oil and gas reservoirs are very attractive options for CO2 sequestration due to good geological characterization, proven oil and gas field technology, and easy adaptation to CO2 storage. The International Energy Agency (IEA) estimates that 140Gt CO2 could be sequestered in depleted natural gas fields worldwide (2). A depleted natural gas reservoir, which contained initially mostly methane, typically yields more than two thirds of the initial gas in place through primary production. This is a high recovery, considering that an oil reservoir produces approximately one-third of the initial oil in place. This may be the reason why the CO2 enhanced gas recovery (EGR) has received relatively little attention. Only few references can be found in the petroleum literature (3–5). Meanwhile, the CO2 solvent flooding is one of the most successful Enhanced Oil Recovery (EOR) methods in U.S. and worldwide (6,7). CO2 EOR produces 300000bbl/day and is second among EOR methods (8). However, an insignificant amount of the CO2 injected is furnished by anthropogenic sources. A number of feasibility studies are being performed to investigate the use of CO2 generated by power plants. Several Federal agencies have major programs for CO2 sequestration (9).