He and his team collaborated with industry partners to explore improvements in efficiency and productivity, as even small percentage increases in hydrocarbon output can become large boosts in oil production. The largest domestic shale reservoirs are estimated to hold billions of gallons of oil apiece, with the Eagle Ford Shale alone spanning about 20,000 square miles.
The research group also emphasized the opportunity to repurpose shale wells as long-term storage hubs for the injected CO2. Other industries may supply the gas as a byproduct of their operations. Instead of releasing it to the atmosphere, where it would add to pollution, energy companies can leave much of it trapped beneath the surface for years, the researchers said.
“CO2 has a high attraction to attach to organic matter surfaces in shales,” Emami-Meybodi said. “If a goal is to sequester CO2 for the long term, the injection cycles can adjust to push the gas deeper into underground formations and optimize the storage.”
For their study, the researchers focused on the 400-mile-long Eagle Ford Shale, which stretches from south to east Texas and is among five major shale plays in the United States. Current extraction efforts, including hydraulic fracturing, typically capture less than 10% of oil in the Eagle Ford Shale, the researchers said.
They revised the injection methodology by intensifying the hydrocarbons’ exposure to CO2. In their optimization workflow, the researchers covered more surface area with the CO2 and adjusted the number of cycles, pressure, amount of injected CO2 and duration of the injections.
“We determined the modifications may let the injection method draw around 15% more of Eagle Ford’s oil hydrocarbons,” said Emami-Meybodi, who holds the Dr. Charles H. Bowman and Lynn A. Holleran Early Career Professorship in Petroleum and Natural Gas Engineering. “Injecting more CO2 generally enables greater reach into reservoirs and more effective mixing with embedded crude, helping to release more of the oil.”
Further, repurposing shale oil wells for CO2 storage could be a cost-effective way to temper greenhouse gases, said Ming Ma, co-author on the paper and a postdoctoral fellow in the John and Willie Leone Family Department of Energy and Mineral Engineering (EME) at Penn State. His contributions to the research included development of an in-house numerical model and writing code to simulate oil extraction under different approaches to injection.
“Our big hope is not only to see progress in the efficiency of hydrocarbon recovery from shale plays but also widespread utilization of abandoned shale wells to keep more CO2 out of the atmosphere,” Ma said. “Related work will include applying the new simulation to additional field data and more thoroughly assessing prospects for hydrocarbon recovery.”
Following the boom in shale well development — shale oil production is poised to peak in 2027, according to the EIA — the U.S. faces a surge in so-called “mature” shale plays with diminished production, said Emami-Meybodi, who directs the Subsurface Energy Recovery and Storage Joint Industry Partnership (SERS JIP) at Penn State. Mature and abandoned shale wells represent promising prospects for CO2 storage, he said.
“Every day a well is closed, you’re losing money by not producing oil, but if you’re storing CO2 there, it can generate revenue,” Emami-Meybodi added. “While carbon dioxide can pose a leak concern in most conventional wells, that’s less of an issue in the structure of shale wells.”
Qian Zhang, a doctoral student in EME at Penn State, also contributed to the paper. The research was supported by the American Chemical Society Petroleum Research Fund and the member companies of SERS JIP.