Gas-Flaring Solution Enhances Oil Recovery and Electric Power Reliability

Abstract

Excess gas produced in reservoirs has traditionally been flared into the atmosphere as it is a byproduct of oil and gas recovery operations. Large volumes of gas are still flared in areas where there is a lack of infrastructure to collect and transport the gas. Gas injection into reservoirs has been shown to increase hydrocarbon production and is a method of Enhanced Oil Recovery (EOR). The proposed method for EOR would be to capture the gas that would otherwise be flared and re-inject it into the reservoir. This would further reduce overall gas flaring and increase production simultaneously. Re-injections sites are carefully chosen to ensure the gas injection yields the best production and is also economically viable. As the world increases the amount of variable renewable energy sources, solutions developed in the traditional energy industry can provide stability to the power grid and reduce the prices for consumers. In Texas, there is a large contribution to total energy production coming from both wind and solar, which have both daily and seasonal variability. A secondary objective is utilizing the potentially flared gas to generate electricity during the high-demand months of summer and winter. Since one of the main reasons for flaring gas is the lack of infrastructure to transport the gas, the ability to use the gas to generate electricity on-site has the potential to be an invaluable asset. Generators are built and connected to the already-in-place electrical grid, bypassing the need to build new pipelines to transport the gas. This solution provides for seasonal storage for associated gas and enhanced oil recovery at the same time. A model of an unconventional reservoir found in West Texas was built to study the feasibility of this project. Using reservoir simulation software, a single horizontal well with 50 fractures along the horizontal was placed in the reservoir model. The model has a porosity of 3.7% and a permeability of 7 nD in the horizontal direction and 0.7 nD in the vertical. The fractures have a half-length of 200 ft and a fracture zone permeability of 300 mD. The fluid properties and historical production were taken from a PVT report and production data provided. The model was then history-matched to get an accurate forecast. Three cases were tested with this model. The base case consisted of 30 years of normal depletion with no injection (Fig. 1) The second case consisted of cyclic injection for 30 years (Fig. 2). Fig. 3a and Fig. 3b show the reservoir pressure in relation to gas injection. In the third case, the injection after depletion consisted of 15 years of normal depletion and 15 years of cyclic injection. The injection cycle consisted of 3 months of production, 2 months of injection, and 1 month of soaking for both the second and third case. Naturally, this cycle would allow for excess electricity generation to meet the demand peaks in summer and winter. The base case produced a total of 205 MSTB, the second case produced 266 MSTB, and the third case produced 260 MSTB. The second case recovered the most oil with an average incremental of 12.9 barrels per 1 Mscf of gas injected.