Gas-Flaring Solution Enhances Oil Recovery and Electric Power Reliability
Authors: Gracian Luis Alberto , Arguello Ivan Miguel , Diyashev Iskander Rasimovich 
Published: May 2023

Excess gas produced from reservoirs during oil and gas recovery operations has traditionally been flared into the atmosphere. Large volumes of gas are still flared in areas where there is a lack of infrastructure to collect and transport the gas.

Gas injection is a method of Enhanced Oil Recovery (EOR) that has been shown to increase hydrocarbon production. The proposed method for EOR would be to use the associated gas that would otherwise be flared and re-inject it into the reservoir. This would reduce the overall gas flared and increase production simultaneously. Re-injections sites would be chosen carefully to ensure the gas injection yields the best production and is economically viable. As the world increases the use 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. Beyond EOR, a secondary objective would be utilizing the flared gas to generate electricity during the high-demand months during summer and winter. Since one of the main reasons for flaring gas is the lack of infrastructure to transport it, the ability to use it to generate electricity on-site can be an invaluable asset. Generators would be built and connected to the already-in-place electrical grid, bypassing the need to construct new pipelines to transport the gas. This solution provides simultaneous seasonal storage and EOR from the associated gas.

A model of an unconventional reservoir found in West Texas was built to study the feasibility of this project. Using reservoir simulation software, we analyzed a single horizontal well with 50 fractures along the horizontal was placed in the reservoir model. The fluid properties and historical production were taken from a PVT report and the production data provided. We then history-matched the model to the historical production data to get an accurate forecast. The model has a porosity of 3.7%, a permeability of 7 nD in the horizontal direction, and 0.7 nD in the vertical direction. The fractures have a half-length of 200 ft and a fracture zone permeability of 300 mD.

Two 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. 3aandFig. 3b show the reservoir pressure in relation to gas injection. The injection cycle consisted of 3 months of production, two months of injection, and one month of soaking. Naturally, this cycle would allow for additional electricity generation to meet the demand peaks during summer and winter.Figure 1Normal depletion. The first case shows normal depletion and cumulative oil production for 30 years.Figure 2Cyclic gas injection. Second case shows cyclic gas injection and cumulative oil production for 30 years.Figure 3aReservoir pressure with cyclic gas. Shows the relationship between reservoir pressure and cyclic gas injected.Figure 3bZoomed-in section. Shows the first three years of the Relationship between reservoir pressure and cyclic gas injected.

After 30 years, the base case produced 205 MSTB, and the second produced 266 MSTB. The second case recovered the most oil with an average incremental of 12.9 barrels per 1 Mscf of gas injected.