Small Scale Field Test Demonstrating CO₂ Sequestration In Arbuckle Saline Aquifer And By CO₂-Eor At Wellington Field, Sumner County, Kansas

Technical Report · Sun Dec 31 00:00:00 EST 2017

DOI:https://doi.org/10.2172/1420310· OSTI ID:1420310

Holubnyak, Yevhen Eugene ^[1]; Watney, Lynn ^[1]; Hollenbach, Jennifer ^[1]; Bidgoli, Tandis ^[1]; Fazelalavi, Fatemeh Mina ^[1]; Doveton, John ^[1]; Victorine, John ^[1]; Birdie, Tiraz ^[2]; Nolte, Alex ^[3]; Tsoflias, Georgios ^[3]; Graham, Brandon ^[3]; Wreath, Dana ^[4]; Bruns, Jason ^[4]; Blazer, Brett ^[4]

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1. Univ. of Kansas, Lawrence, KS (United States). Center for Research & Kansas Geological Survey
2. TBirdie Consulting, Lawrence, KS (United States)
3. Univ. of Kansas, Lawrence, KS (United States). Dept. of Geology
4. Berexco, LLC, Wichita, KS (United States)

The objectives of this project are to understand the processes that occur when a maximum of 70,000 metric tonnes of CO₂ are injected into two different formations to evaluate the response in different lithofacies and depositional environments. The evaluation will be accomplished through the use of both in situ and indirect MVA (monitoring, verification, and accounting) technologies. The project will optimize for carbon storage accounting for 99% of the CO₂ using lab and field testing and comprehensive characterization and modeling techniques. Site characterization and CO₂ injection should demonstrate state-of-the-art MVA tools and techniques to monitor and visualize the injected CO₂ plume and to refine geomodels developed using nearly continuous core, exhaustive wireline logs, and well tests and a multi-component 3-D seismic survey. Reservoir simulation studies will map the injected CO₂ plume and estimate tonnage of CO₂ stored in solution, as residual gas, and by mineralization and integrate MVA results and reservoir models shall be used to evaluate CO₂ leakage. A rapid-response mitigation plan was developed to minimize CO₂ leakage and provide a comprehensive risk management strategy. The CO₂ was intended to be supplied from a reliable facility and have an adequate delivery and quality of CO₂. However, several unforeseen circumstances complicated this plan: (1) the initially negotiated CO₂ supply facility went offline and contracts associated with CO₂ supply had to be renegotiated, (2) a UIC Class VI permit proved to be difficult to obtain due to the experimental nature of the project. Both subjects are detailed in separate deliverables attached to this report. The CO₂ enhanced oil recovery (EOR) and geologic storage in Mississippian carbonate reservoir was sucessully deployed. Approximately 20,000 metric tons of CO₂ was injected in the upper part of the Mississippian reservoir to verify CO₂ EOR viability in carbonate reservoirs and evaluate a potential of transitioning to geologic CO₂ storage through EOR. A total of 1,101 truckloads, 19,803 metric tons—an average of 120 tonnes per day—were delivered over the course of injection that lasted from January 9 to June 21, 2016. After cessation of CO₂ injection, the KGS 2-32 well was converted to water injector and continues to operate. CO₂ EOR progression in the field was monitored weekly with fluid level, temperature, and production recording and formation fluid composition sampling. It is important to note that normally, CO₂ EOR pilots are less efficient than commercial operations due to lack of directional and precise well control, lack of surface facilities for CO₂ recycling, and other factors. As a result of this pilot CO₂ injection, the observed incremental average oil production increase was ~68% with only ~18% of injected CO₂ produced back. Decline curve analysis forecasts of additional cumulative oil produced were 32.44M STB to the end of 2027. Wellington Mississippian pilot efficiency by the end of forecast calculations is 11 MCF per barrel of produced oil. Using 32M STB oil production and $1,964,063 cost of CO₂, CO₂ EOR cost per barrel of oil production is ~$60. Simple but robust monitoring technologies proved to be very efficient in detecting and locating CO₂. High CO₂ reservoir retentions with low yields within an actively producing field could help to estimate real-world risks of CO₂ geological storage for future projects. The Wellington Field CO₂ EOR was executed in a controlled environment with high efficiency. This case study proves that CO₂ EOR could be successfully applied in Kansas carbonate reservoirs if CO₂ sources and associated infrastructure are available. Recent developments in unconventional resources development in Mid-Continent USA and associated large volume disposal of backflow water and the resulting seismic activity have brought more focus and attention to the Arbuckle Group in southern Kansas. Despite the commercial interest, limited essential information about reservoir properties and structural elements has impeded the management and regulation of disposal, an issue brought to the forefront by recent seismicity in and near areas of large volumes and rates of brine disposal. The Kansas Geological Survey (KGS) collected, compiled, and analyzed available data, including well logs, core data, step rate tests, drill stem tests, 2-D and 3-D seismic data, water level measurements, and others types of data. Several exploratory wells were drilled and core was collected and modern suites of logs were analyzed. Reservoir properties were populated into several site-specific geological models. The geological models illustrate the highly heterogeneous nature of the Arbuckle Group. Vertical and horizontal variability results in several distinct hydro-stratigraphic units that are the result of both depositional and diagenetic processes. During the course of this project, it has been demonstrated that advanced seismic interpretation methods can be used successfully for characterization of the Mississippian reservoir and Arbuckle saline aquifer. Analysis of post-stack 3-D seismic data at the Mississippian reservoir showed the response of a gradational velocity transition. Pre-stack gather analysis showed that porosity zones of the Mississippian and Arbuckle reservoirs exhibit characteristic amplitude versus offset (AVO) response. Simultaneous AVO inversion estimated P- and S-impedances. The 3-D survey gather azimuthal anisotropy analysis (AVAZ) provided information about the fault and fracture network and showed good agreement to the regional stress field and well data. Mississippian reservoir porosity and fracture predictions agreed well with the observed mobility of injected CO₂ in KGS well 2-32. Fluid substitution modeling predicted acoustic impedance reduction in the Mississippian carbonate reservoir introduced by the presence of CO₂. Seismicity in the United States midcontinent has increased by orders of magnitude over the past decade. Spatiotemporal correlations of seismicity to wastewater injection operations have suggested that injection-related pore fluid pressure increases are inducing the earthquakes. In this investigation, we examine earthquake occurrence in southern Kansas and northern Oklahoma and its relation to the change in pore pressure. The main source of data comes from the Wellington Array in the Wellington oil field, in Sumner County, Kansas, which has monitored for earthquakes in central Sumner County, Kansas, since early 2015. The seismometer array was established to monitor CO₂ injection operations at Wellington Field. Although no seismicity was detected in association with the spring 2016 Mississippian CO₂ injection, the array has recorded more than 2,500 earthquakes in the region and is providing valuable understanding to induced seismicity. A catalog of earthquakes was built from this data and was analyzed for spatial and temporal changes, stress information, and anisotropy information. The region of seismic concern has been shown to be expanding through use of the Wellington earthquake catalog, which has revealed a northward progression of earthquake activity reaching the metropolitan area of Wichita. The stress orientation was also calculated from this earthquake catalog through focal mechanism inversion. The calculated stress orientation was confirmed through comparison to other stress measurements from well data and previous earthquake studies in the region. With this knowledge of the stress orientation, the anisotropy in the basement could be understood. This allowed for the anisotropy measurements to be correlated to pore pressure increases. The increase in pore pressure was monitored through time-lapse shear-wave anisotropy analysis. Since the onset of the observation period in 2010, the orientation of the fast shear wave has rotated 90°, indicating a change associated with critical pore pressure build up. The time delay between fast and slow shear wave arrivals has increased, indicating a corresponding increase in anisotropy induced by pore pressure rise. In-situ near-basement fluid pressure measurements corroborate the continuous pore pressure increase revealed by the shear-wave anisotropy analysis over the earthquake monitoring period. This research is the first to identify a change in pore fluid pressure in the basement using seismological data and it was recently published in the AAAS journal Science Advances (Nolte et al., 2017). The shear-wave splitting analysis is a novel application of the technique, which can be used in other regions to identify an increase in pore pressure. This increasing pore fluid pressure has become more regionally extensive as earthquakes are occurring in southern Kansas, where they previously were absent. These monitoring techniques and analyses provide new insight into mitigating induced seismicity’s impact on society.

• Research Organization: Univ. of Kansas, Lawrence, KS (United States). Center for Research & Kansas Geological Survey
• Sponsoring Organization: USDOE Office of Fossil Energy (FE), Clean Coal and Carbon Management
• Contributing Organization: Berexco, LLC., University of Kansas Department of Geology, IRIS-PASSCAL, Lawrence Berkeley National Laboratory, Electric Power Research Institute, Paragon Geophysical Services, Inc., Trilobite Testing Services
• DOE Contract Number: FE0006821
• OSTI ID: 1420310
• Report Number(s): DOE-KGS-06821; DUNS 076248616
• Country of Publication: United States
• Language: English

Related Subjects

02 PETROLEUM
25 ENERGY STORAGE
29 ENERGY PLANNING, POLICY, AND ECONOMY
99 GENERAL AND MISCELLANEOUS
Carbon Storage
CO2-EOR
Carbon Capture Storage and Utilization
Carbon Sequestration
Geologic Carbon Storage
Class VI Permitting
Saline Aquifer Storage
Kansas Geological Survey
Energy Research
CO2 Injection