Gas injection is one of the most widely used processes in the oil industry and is considered a promising enhanced oil recovery (EOR) method. Factors such as the injected gas type, minimum miscibility pressure (MMP) of injected gas, reservoir and fluid characterization can all contribute to a successful gas injection application (Farzad & Amani, 2007, 2012). Using the continuous gas injection strategy, a total of twenty-four experimental runs have been conducted to evaluate the oil recovery performance of gas injection using CO2, CH4, and N2. Two core samples (1.5" W x 3" L) from the Barea Sandstone were saturated with condensate and black oil samples collected from the Eagle Ford Shale reservoir. The composition of the fluids was determined using gas chromatography, and the composition therefore aided in the calculation of the MMP. The experimental results showed CH4 provided the highest oil recovery factor (RF) of 83% in condensate oil under immiscible conditions, while CO2 and CH4 performed the best with an RF of 67% in black oil reservoirs under miscible conditions. The performance of the solvent is impacted by fluid light components content and the gas-oil ratio (GOR). Viscosity reduction is the main driving mechanism as the produced oil showed a reduction in viscosity due to miscibility.
This work aims to provide further insights into the gas injection performance in oil reservoirs by focusing on the reservoir fluid and injection gas compositions. The results of this work will improve our understanding of the recovery mechanisms in oil reservoirs and provide insights into the evaluation and optimization of the gas injection in oil reservoirs. Furthermore, the injected gas interaction with in-situ fluids helps to shed the light on subsurface gas storage mechanisms, which has significant implications for CO2 capture, utilization, and storage projects.
Over the past decade, the Eagle Ford Shale has become one of the major plays comprising 13.2% of the total U.S. oil production in 2022 (EIA, 2022). It is located in South Texas and encompasses twenty thousand square miles with a depth ranging from 5,000 ft in the northern shale area to below 14,000 ft in the southern shale area (NETL, 2019). While oil production in the Eagle Ford region has declined over the years, from a peak 1.7 Mb/d in 2015 to 1.15 Mb/d in 2022, it continues to lead in new-well production per rig with respect to the remaining shale regions in the U.S (EIA, 2022).
