By Uche Kelechi

In late 2021, as governments scrambled for credible net-zero pathways instead of slogans, a technical paper from the University of Oklahoma quietly reset the benchmark for how to judge carbon capture investments. 

Led by Nigerian petroleum engineer David N. Nnamdi, the study—“Economic Evaluation of CO₂ Capture, Transportation, and Storage Potentials in Oklahoma” (SPE-206106-MS)—cut through political rhetoric by mapping, tonne-by-tonne, which carbon capture, utilization and storage (CCUS) projects actually make financial sense once pipelines, storage reservoirs and U.S. 45Q tax credits are counted together.

Nnamdi who is a First Class graduate of the University of Lagos, he spent his early career at Niger Delta Petroleum Resources in Lagos, where he worked on reserves evaluation and field development planning and helped build internal forecasting and analysis tools used to appraise assets worth hundreds of millions of dollars. 

In parallel, he co-founded Sieger & Co, developing software for reserves estimation, incident management and oilfield data analytics.

At the University of Oklahoma, where he pursues advanced studies in petroleum engineering and data science, Nnamdi joined a U.S. Department of Energy funded project under the Carbon Utilization Storage Partnership (CUSP). His SPE paper focused on Oklahoma but the method reaches beyond a single state. Starting from 151 industrial emission sources, his team filtered down to 27 that met the 45Q tax credit thresholds, then to 12 priority sources based on volume, distance, capture cost and technical feasibility. On the storage side they condensed 245 active CO₂ injection wells into 21 effective clusters, and fed this full picture into SimCCS, an optimization tool that chooses which plants capture, which wells store and where pipelines should run to minimize cost over the project life.

The results matter for policy. Under a “capture everything” scenario that tries to use the full annual injection capacity of active EOR wells, around 2.14 million tonnes of CO₂ per year, the model found an overall unit cost of about 29.7 dollars per tonne, even after including the 45Q tax credit. That is a clear warning that simply bolting capture onto existing EOR infrastructure is not, by itself, a bankable climate solution. When the model was allowed to select only economically attractive projects, it settled on a much smaller network centered on a single gas processing plant and a few storage clusters, roughly 0.46 million tonnes per year of CO₂ and a total unit cost of about minus 4.6 dollars per tonne, effectively a profitable system once incentives are counted.

Another conclusion is about scale. Eligible emissions from major sources in Oklahoma are roughly 37 million tonnes of CO₂ per year, while existing EOR wells can only store about 2.14 million tonnes per year. The message for governments is straightforward: existing EOR capacity is nowhere near enough, and serious sequestration plans must develop saline aquifers and new dedicated storage wells or risk leaving most of the potential untapped.

For regulators and operators, the framework that Nnamdi helped build functions as a decision engine. It shows which projects cross from loss making to viable as tax credits change, where to prioritize pipeline corridors, and how to avoid spending public money on networks that will never pay back. Although the case study is set in Oklahoma, the same approach could be applied in the Niger Delta, the North Sea or any basin where governments are considering incentives for CCUS. From Lagos to Oklahoma, Nnamdi’s work shows that carbon sequestration policy will succeed or fail not in slogans, but in the details of which tonnes are captured, which reservoirs receive them and which projects clear the economic bar when everything is counted.