An Overview of Stewart Field Unit Project: A Field Case Study of CO2 Capture, Utilization, and Storage

Abstract

Abstract To achieve the net-zero emission goal of 2050, implementing carbon capture, utilization, and storage (CCUS) technology has proven to be crucial. The CCUS processes integrate multidisciplinary domains such as chemical, subsurface engineering, economics, and environmental science. Therefore, the entire value chain must be examined to understand the viability of a CCUS project. In Kansas, a CCUS opportunity is ongoing, which involves capturing CO2 directly from a nearby ethanol plant for CO2–enhanced oil recovery (EOR) and CO2 storage. This paper provides an overview of the Stewart Field Unit (SFU) CO2–EOR and CO2 storage project from the perspective covering direct industrial CO2 capture to underground usage and storage evaluation. First, we reviewed the techno-economics of industrial CO2 capture and utilization in Kansas to corroborate small-scale point-to-point economic evaluation of captured CO2 for CO2–EOR and storage. The FECM/NETL CO2 Transport Cost Model was used to estimate the CO2 capture and compression cost. Next, for the subsurface engineering aspect, we developed a field-scale compositional reservoir and flow model to simulate the primary, secondary, and CO2 injection phases of the SFU. The field-scale reservoir model incorporated hydraulic fractures that underwent compaction/dilation during the injection production phases, with severe near-wellbore damage as one of the underlying physical-chemical mechanisms. A representative equation of state was used and tuned using experimental fluid data. The model's primary, secondary, and tertiary recovery phases were historically matched successfully by modification of directional permeability, relative permeability curves, and near-wellbore damage. Furthermore, we proposed an economic framework to determine the sustainable economic profitability of the SFU project using the net present value (NPV) economic indicator. The cumulative recovery factors for primary, secondary, and tertiary stages are 11.5%, 29%, and 32%, respectively. Furthermore, it has been observed that 45% of the injected CO2 has been sequestered in the SFU. The low recovery rates during the CO2-EOR phases can be attributed to formation damage caused by water sensitivity, the formation of scales, and issues with wellbore integrity. A baseline case and two other CO2-WAG cases were forecasted after the conclusive historical match, focusing strategically on developing the field's eastern or western sections. The constraints on CO2 availability and the logistics of CO2 transportation necessitated this approach. These proposed regional WAG cases yielded an incremental oil recovery factor of approximately 1, 3, and 3.5% for the baseline, west, and east section scenarios, respectively. For both west and east section WAG cases, more than 40% of the injected CO2 would be stored in the formation. Consequently, economic analyses were carried out on the result to show the viability of the WAG projects with or without tax credit inclusion under the current economic conditions. The NPVs show that the SFU WAG project is only economically favorable, including a $80/metric ton tax credit for the cases studied. This research provides a comprehensive framework for assessing viable small-scale carbon capture, utilization, and storage projects in other geologically similar fluvial morrow formations.