Effective multiphase flow and transport simulations are a critical tool for screening, selection, and operation of geological CO₂ storage sites. The relative permeability curve assumed for these simulations can introduce a large source of uncertainty. It significantly impacts forecasts of all aspects of the reservoir simulation, from CO₂ trapping efficiency and phase behavior to volumes of oil, water, and gas produced. Careful consideration must be given to this relationship, so a primary goal of this study is to evaluate the impacts on CO₂-EOR model forecasts of a wide range of relevant relative permeability curves, from near linear to highly curved. The Farnsworth Unit (FWU) is an active CO₂-EOR operation in the Texas Panhandle and the location of our study site. The Morrow ‘B’ Sandstone, a clastic formation composed of medium to coarse sands, is the target storage formation. Results indicate that uncertainty in the relative permeability curve can impart a significant impact on model predictions. Therefore, selecting an appropriate relative permeability curve for the reservoir of interest is critical for CO₂-EOR model design. If measured laboratory relative permeability data are not available, it must be considered as a significant source of uncertainty.

This paper summarizes the results of the risk analysis and characterization of the CO₂ and brine leakage potential of Farnsworth Unit (FWU) site wells. The study is part of the U.S. DOE’s National Risk Assessment Partnership (NRAP) program, which aims to quantitatively evaluate long-term environmental risks under conditions of significant geologic uncertainty and variability. To achieve this, NRAP utilizes risk assessment and computational tools specifically designed to quantify uncertainties and calculate the risk associated with geologic carbon dioxide (CO₂) sequestration. For this study, we have developed a workflow that utilizes physics-based reservoir simulation results as input to perform leakage calculations using NRAP Tools, specifically NRAP-IAM-CS and RROM-Gen. These tools enable us to conduct leakage risk analysis based on ECLIPSE reservoir simulation results and to characterize wellbore leakage at the Farnsworth Unit Site. We analyze the risk of leakage from both individual wells and the entire field under various wellbore integrity distribution scenarios. The results of the risk analysis for the leakage potential of FWU wells indicate that, when compared to the total amount of CO₂ injected, the highest cemented well integrity distribution scenario (FutureGen high flow rate) exhibits approximately 0.01% cumulative CO₂ leakage for a 25-year CO₂ injection duration at the end of a 50-year post-injection monitoring period. In contrast, the highest possible leakage scenario (open well) shows approximately 0.1% cumulative CO₂ leakage over the same time frame.

Geologic Carbon Storage (GCS) is a promising technology for storing large volumes of anthropogenic CO₂ effectively and permanently. Numerical simulations are an integral part of site selection and characterization for any potential GCS site. As part of the DOE-funded CarbonSAFE Rocky Mountains Phase I project, a regional GCS analysis was undertaken to understand the efficacy of storing CO₂ emissions from the power generation and heavy industry in central Utah’s favorable geology. In this study, the injection of CO₂ for geologic storage was simulated in the Navajo Sandstone Formation in Emery County, Utah. Carbon dioxide was sourced from regional power generation stations and heavy industries throughout Utah, with an emphasis on emissions reduction at the Hunter Power Plant near Castle Dale, Utah. A simulation grid was extracted from the project’s geological model encompassing an area around Price, Huntington, and Castle Dale in central Utah. The Navajo Sandstone Member of the Glen Canyon Group was the target of CO₂ injection with the overlying Carmel formation providing the primary seal. A suite of simulations was performed assessing the viability of this area for permanent CO₂ storage. Results indicate that the area can not only store 46 million metric tons of anthropogenic CO₂, meeting the project goals, but this area has the capacity to securely store at least 1.3 billion tons of CO₂, suggesting the injection site and surrounding geology are suitable locations for commercial-scale GCS.

The impact to underground sources of drinking waters (USDW) due to leakage through legacy wells is a big concern for geological carbon sequestration. The area of review (AoR) is defined as the region surrounding the storage project location where USDWs may be endangered by the injection activity. The storage reservoir developed under U.S. Department of Energy (DOE) funded San Juan Basin CarbonSAFE project is over-pressurized relative to the overlaying USDW, per U.S. Environmental Protection Agency (EPA) guidance, more sophisticated methods are required to delineate the AoR comparing to under-pressurized and hydrostatic scenarios. Based on Burton-Kelly’s risk-based AoR approach (Burton-Kelly M.E. et al., 2021), this study applies a new version of Semi-Analytical Leakage Solution for Aquifers (SALSA) model (Cihan A., User Guide for SALSA, Lawrence Berkeley National Laboratory, 2022) to carry out risk-based AoR delineation supporting the San Juan Basin CarbonSAFE storage project. The approach combines semi-analytical solutions for estimating storage formation brine leakage through a hypothetical leaky wellbore with the results of physics-based Computer Modeling Group (CMG) numerical reservoir simulations. A relationship of incremental brine leakage versus pressure buildup during the injection was derived. Risk-based AoR was delineated based on the incremental brine leakage map by applying certain leakage threshold criteria. Separate analyses are specifically designed for the heterogeneously distributed USDW condition at San Juan Basin CarbonSAFE site. The study shows that the threshold criteria for incremental brine leakage and the wellbore effective permeability strongly influence the delineated AoR size. Depending on the threshold criteria, the risk-based AoR can be much smaller comparing to the pressure front delineation method at San Juan Basin storage site while complying with EPA Class VI Underground Injection Control (UIC) Rule. Under the scenario where the leaky wellbore is open to a high permeability intermediate aquifer (thief zone) between the cap rock and USDW, the risk-based AoR is no larger than the areal extent of the CO2 plume in the storage reservoir because the pressure buildup in the storage reservoir beyond the CO2 plume is insufficient to drive brine up a hypothetical leaky wellbore into the USDW. However, even under the conservative assumption that the leaky wellbore is not open to a thief zone, the incremental leakage is less than 0.05 m3 over 30 years assuming the wellbore effective permeability 0.1 mD. A quantitative leakage risk assessment was also performed to evaluate the potential CO2 and brine leakage through the existing wells within the risk-based AoR. The leakage risk assessment was performed using the NRAP-Open-IAM tool developed by U.S. DOE’s National Risk Assessment Partnership. The calculations indicated no significant threat to regional groundwater due to leakage through the existing wells within the predicted area of review.This work provides helpful facilitation on corrective action strategy for the legacy wells inside AoR and leakage risk assessment for the San Juan Basin CarbonSAFE project. As a site-specific application, the risk-based AoR explores novel method and provide support for the long-term monitoring strategy of geological carbon storage. This study can be a supplementary to U.S. EPA guidance on AoR delineation for over-pressured reservoir system.