EERC, the Energy & Environmental Research Center at the University of North Dakota, has launched a carbon capture research program aimed at extending recoverable volumes in the Bakken tight oil play. The program, announced through UND, positions CO2 injection as both an enhanced oil recovery method and a permanent storage pathway in the Williston Basin.

The framing — capture plus storage tied to incremental production — aligns with policy incentives established or expanded under recent federal legislation and with rising industrial demand for verified carbon offtake.

What does the program target?

The center's work focuses on the Bakken shale system and the underlying Three Forks formation beneath western North Dakota and eastern Montana. Researchers are evaluating how CO2, drawn from regional emitters such as coal-fired generation, fertilizer plants, and ethanol facilities, could be cycled into existing wellbores to displace residual oil and sequester greenhouse gases in formation pore space at the same time.

Each stored tonne, under that approach, serves a dual function: an EOR agent that boosts recovery from a mature play, and a credit-eligible tonne under federal storage provisions. The economics of the pair depend largely on the prevailing tax credit value and on the distance between capture source and injection well.

Why the Bakken, and why now?

The Bakken remains one of the largest producing tight oil plays in North America, with cumulative production dating to the modern horizontal era in 2007. Decades of development across McKenzie, Williams, Dunn, and Mountrail counties have left much of the core acreage in a depletion phase, and primary recovery factors still leave substantial volumes of original oil in place.

CO2 flooding introduces a displacement mechanism — miscible or near-miscible displacement that swells residual oil and reduces interfacial tension — that differs from the produced-gas and water injection trials the play has seen historically. The physics of applying it to organic-rich, overpressured shale has until now kept large-scale commercial pilots off operator capex lists.

Policy has shifted. The 45Q tax credit, expanded under the Inflation Reduction Act and now usable as a transferable instrument, has restored project-finance viability for paired CCUS-EOR developments that previously failed economic screens. North Dakota's existing Class II injection well inventory and growing CO2 pipeline studies in the state further support the technical case.

What happens next?

EERC has not publicly identified a field partner, a candidate injection site, or expected CO2 throughput. The next set of watch items for operators:

• Pilot announcement. A field demonstration agreement or an EPA Class VI permit filing would confirm progression past the laboratory stage.
• Source-sink matching. Industrial emitters within feasible pipeline distance of Williston acreage, concentrated along the upper Missouri corridor, will determine deliverable volumes and project IRR.
• Existing wells. Tens of thousands of horizontal penetrations across the play offer potential conversion candidates to injection service, subject to mechanical integrity and regulatory classification.
• Permitting clock. EPA Class VI review timelines, often running 18 months or longer, typically set the binding pace on commercial-scale authorization.

The program remains research-grade at present, with no commercial capex commitment attached. The first verifiable signal will be a pilot partner disclosure or a permit application — both likely to surface at UND industry briefings or at the next Society of Petroleum Engineers regional meeting.