Yanrui Ning, Ali Tura, Colorado School of Mines
This study analyzes the economics of carbon capture utilization and sequestration (CCUS) projects, shows a state-wide CCUS deployment exercise, followed by simulation results of enhanced oil recovery (EOR) based CO₂ storage in an unconventional reservoir. After combining capture, transportation, sequestration costs, tax credits, and EOR revenue, the best economic projects are mapped. It is concluded that EOR is an effective method to offset costs and increase the profit margin of CCUS projects.
We consider an application in the Denver-Julesburg Basin (DJ Basin) since it is a high-priority carbon sink due to its stacked formations with unconventional hydrocarbon and aquifer reservoirs and covers substantial acreage close to the major CO₂ sources. CO₂-EOR is simulated based on one section of the DJ Basin Niobrara-Codell unconventional reservoirs. The simulation model integrated the geological static model with 3D hydraulic fracture stimulation, and then was history matched to production. It was found that if the same amount of CO₂ is injected following the same schedule, the most depleted reservoirs are best for CCUS projects due to the higher amount of incremental oil recovered and more CO₂ stored. Additionally, more oil can be enhanced and more CO₂ can be stored with the following: a shut-in period exists between injection and re-production, injection rates are high, more injection wells are used. With the same amount of CO₂, injection in one well can recover more oil, whereas injection in multiple wells can store more CO₂.
For our study, economic analysis shows that with an optimal CO₂-EOR simulation scenario it would be possible to generate $9.4 million dollars when the oil price is assumed to be $60/bbl and CO₂ credit is $35/ton. We also find that enhanced oil revenue is approximately 4.5 times higher than the revenue from carbon tax credits that could be claimed.
The potential of CO₂ leakage from legacy wells is also evaluated based on a separate study in the stacked overburden formations with the aquifer in the DJ Basin. The evaluated storage formation is Pierre sandstone aquifer, which is above the reservoir formations of Niobrara and Codell where all the oil-producing wells go through this sandstone. A one-square-mile layer cake model covering the storage formation of Pierre sandstone was built. The thickness is approximately 2000 ft, permeability is 8 mD and porosity is 14%. When the injector is injected with 1 million tons/year of CO₂ for 30 years and then shut in for another 50 years, it was discovered that up to 47.5 Mscf/year of CO₂ can be leaked via the legacy well that is about 1100 ft away from the injector. The leakage rate when considering varying formation properties, aquifer salinities and brine densities as well as more legacy wells is currently being studied.
We would like to thank the US Department of Energy (#DE-FE0031837) and the Carbon Utilization and Storage Project (CUSP) for their support of this study. We also thank the Los Alamos National Lab and the National Energy Technology Laboratory (NETL) for accessing the leakage risk assessment software NRAP-Open-IAM.