Lawmakers hear technical, economic case for CO2-enhanced oil recovery and pipeline buildout in Wyoming

Lon Whitman, director of the Enhanced Oil Recovery Institute, told the Joint Minerals, Business & Economic Development Interim Committee on June 20 that Wyoming has “significant stranded oil potential” and that industry economics determine whether enhanced oil recovery (EOR) projects move forward. Whitman said multiple studies indicate roughly 2 billion barrels of recoverable upside oil in the state and that CO2 EOR since 1986 produced about 173 million barrels of incremental oil, generating an estimated $1.16 billion in state tax revenue under conservative assumptions.

The briefing matters because CO2 EOR projects require large up‑front capital, dedicated CO2 supplies and pipelines, and they can change long‑term production and state revenues. Whitman framed EOR as a set of technical and commercial choices rather than a single policy fix.

Whitman described how EOR fits into production phases: primary yields roughly 15% of original oil in place; secondary methods such as water‑flooding can add another ~20%; and enhanced recovery techniques, including CO2, can add roughly a further 25% in many cases. “These are long‑term projects with long‑term revenue to the state,” he said, citing the Lost Soldier and Beaver Creek projects as multi‑decade examples. Whitman warned costs rise sharply with each stage and described typical EOR project items: capture and contract for CO2, a delivery pipeline or spur, field rework and specialized surface equipment.

On CO2 supply and pipelines he told the committee that most CO2 used for Wyoming EOR comes from large capture facilities tied to industrial plants. Whitman identified the Shoot Creek (ExxonMobil) capture facility and the Lost Cabin (Contango) facility as the main in‑state CO2 sources and described existing trunk pipeline lines that move CO2 from southwest to northeast Wyoming. He said existing infrastructure delivers on the order of hundreds of millions of cubic feet per day and that some proposed projects have letters of interest for CO2 delivery but need spur pipelines. “You can’t move forward with the project financing if you don’t have a CO2 agreement,” he said.

Whitman gave examples of private project economics. He said a set of nearby small fields can be combined into 1 CO2 project to become economic and that typical pipeline spur costs run roughly $1 million per mile in the examples he showed (he cited a 12‑inch, ~41.3‑mile spur at roughly $40 million). For one developer he cited CapEx figures of about $175 million (Raven Creek field) plus a spur pipeline cost of roughly $50 million and an initial CO2 purchase of 50 million cubic feet per day. Using an industry rule of thumb Whitman explained CO2 price roughly tracks a small percentage of WTI oil price and worked an example that put CO2 purchase costs near $63,000 per day (about $23 million per year) for a 50 million cfd contract at the oil prices used in his slide.

Committee members pressed Whitman on technical and operational details. Questions included whether water used in water floods is recycled (Whitman: “vast majority after their initial start up”), whether natural gas is sometimes reinjected for pressure maintenance (yes, if available), and how long fields can take to show a response — he said Beaver Creek injected CO2 for four years before a measurable oil response. Senator Cooper and others asked about reservoir studies and whether older fields had sufficient data; Whitman said many candidate fields have been studied but not all, and some that had past reservoir work would be better candidates.

Whitman also reviewed non‑CO2 EOR options under development in Wyoming: polymer‑augmented water floods, NGL (natural gas liquids) EOR pilots and an “enriched air” thermal technique. He described an NGL pilot supported by the Wyoming Energy Authority that aims to use nearby NGL pipeline supply to test solvent flooding and listed a small polymer and an enriched‑air pilot near Gillette that has state support.

On regulatory and bonding questions, Joe Scott of the Wyoming Oil and Gas Commission noted the commission’s primary regulatory touch points: unitization under “statute 30 five‑one 10,” injection and well work under Commission rules (Chapter 4), and the Class II underground injection control program the state runs under EPA primacy. Scott warned that the federal aquifer‑exemption process has been a source of delay when the injected zone is below 10,000 mg/L total dissolved solids and EPA concurrence is required, though he said recent federal staff changes had reduced timelines. He also highlighted bonding and idle‑well liability as major business constraints for smaller companies seeking to take over older fields.

Public comment raised water and safety concerns. A local resident said CO2 mixed with water can form carbonic acid, and urged the committee to require mitigation and baseline monitoring before expansion of CO2 projects. The committee asked staff to follow up on aquifer monitoring and whether baseline water testing approaches used for hydraulic fracturing should be applied to EOR projects.

The committee did not take formal policy action at the session; members directed staff to compile more detailed project lists and to return with follow‑up information on aquifer monitoring, pipeline routes and potential state support options for prioritized EOR projects.

Ending: Committee members said they will continue technical briefings through the interim and asked state agencies to provide targeted follow‑up on pipeline capacity, bonding pools and the status of capture projects so the Legislature can consider options if members decide to pursue targeted infrastructure or financial incentives.