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The MRCSP Michigan Basin Large-Scale Injection Project is evaluating CO 2 storage and utilization in a complex of closed reservoirs at various stages of production and enhanced oil recovery (EOR) life-cycle. Since 2013, MRCSP has successfully injected and monitored the net storage of more than 600,000 metric tons of CO 2 out of the goal of 1 million metric tons. A number of monitoring technologies have been tested, and various modeling approaches are being applied to evaluate CO 2 migration, injectivity, capacity, and containment.

The Midwest Regional Carbon Sequestration Partnership (MRCSP) is leading an extensive study and monitoring effort of large-scale carbon dioxide (CO 2 ) injection and storage during enhanced oil recovery (EOR) in depleted oil fields in the Michigan Niagara Reef Trend. Detailed monitoring of caprock and reservoir zones is vital for understanding oil, gas, and water saturations and potential migration of CO 2 . Baseline and repeat pulsed neutron capture (PNC) logs were collected as part of the monitoring effort and study for these storage sites. An overview of the development and enhancement of best practices for PNC logging in complex EOR fields is presented.

Pressure and rate data are commonly recorded as part of a basic monitoring program in CCS projects. This paper discusses the application of multiple analytical techniques to interpret pressure and rate transient data from CO2 injection and storage operations. The techniques of interest, i.e., injection-falloff analysis, injectivity/productivity index analysis and pressure pulse arrival time analysis, are commonly used in the oil and gas industry to assess reservoir properties, but not well known in the CCS literature (especially the last two). Injection-falloff analysis involves log-log pressure derivative plotting for the falloff data and history-matching of the entire injection-falloff sequence to determine permeability. In the injectivity/productivity index analysis, rate-normalized pressure buildup is plotted against material balance time or ratio of cumulative injection to injection rate to determine the injectivity index (ratio of injection rate to stabilized pressure buildup) which can be related to the permeability-thickness product. The arrival time analysis identifies the arrival of a pressure disturbance (∼0.1 psi change from ambient) to determine the hydraulic diffusivity from which permeability can be estimated. The applicability of these techniques is demonstrated via illustrative examples from multiple wells in different pinnacle carbonate reefs undergoing CO2-EOR in Northern Michigan. The paper ends with a discussion of the relative merits of each interpretive technique, as well as recommendations that could be useful for other field projects.

Pulsed neutron capture (PNC) well logging technology was utilized in the large-scale, long-term CO2-EOR Midwest Regional Carbon Sequestration Partnership (MRCSP) to monitor CO2 breakthrough in the Michigan Niagaran reef trend. Comprehensive tool response modeling and assessment of pre- and post-CO2 injection PNC data were performed to evaluate oil, gas, and water saturation changes and potential CO2 breakthrough in monitored reefs. An examination of the different phases of the program and monitoring data are presented.

The Midwestern Regional Carbon Sequestration Partnership (MRCSP, www.mrcsp.org ) is improving understanding of potential carbon dioxide (CO 2 ) utilization and storage resources within a nine-state region of the United States that relies heavily on fossil energy. This paper describes two milestones achieved: completion of 10 years of carbon capture and storage (CCS) research, and the start of a large-scale injection test in conjunction with CO 2 -enhanced oil recovery (EOR). Lessons learned from regional characterization and small-scale field tests, as well as the approach that is being followed for the large-scale injection test (including characterization, monitoring, and modeling), are presented.

This report is for ESTCP Project CU-9908. The project demonstrated and validated two innovative prepump modifications to a conventional bioslurper system: an in-well "dual drop tube" extraction system and a modified aboveground knockout tank design. These modifications are meant to reduce operation and maintenance costs associated with the simultaneous extraction of fuel with groundwater by a conventional system, which utilizes a single drop tube in-well vacuum extraction system without a prepump knockout tank. The "dual drop tube" consists of two in-well vacuum drop tubes separated by a fuel isolation sleeve, which extends 1 to 3 feet both above and below the end of the main drop tube. This tubular sleeve prevents the extraction of fuel by the main drop tube, while allowing groundwater and soil gas to enter. A smaller vacuum drop tube, located outside the sleeve, is used to remove accumulating fuel separately, using the bioslurper system pump vacuum and a separate storage vessel. Conventional systems promote extensive emulsification of fuel with groundwater and foam formation resulting from fuel-water mixtures moving through the vacuum manifold system and liquid ring vacuum pump. The "dual drop tube" and prepump knockout tank separators were operated both alone and in series at eight field sites (2- to 5-week demonstrations) and cost and performance data were obtained by a long-term demonstration (15 weeks) at NAS Fallon, Nevada. The dual drop tube separator removed all emulsions and foam and 99% of TPH from the vacuum pump discharge. Cost data are included in the report.

Volume I of this Application Guide for Bioslurping provides an overview and summary of Volume II of this Application Guide. Volume I provides principles and practices of bioslurping in an abbreviated fashion so that a remedial project manager (RPM) can make preliminary decisions rather quickly. By reading Volume I, RPMs may determine whether this technology is feasible for remediation of a site contaminated with light, non-aqueous phase liquid (LNAPL). Volume II of this document provides the reader with a detailed description of the bioslurper system, testing procedures, and system design, installation, operation, monitoring, and approach for site closure.

During the last three years, geologic storage of carbon dioxide (CO 2 ) in saline formations has been demonstrated in three distinct geologic settings by the Midwestern Regional Carbon Sequestration Partnership (MRCSP), one of the seven regional partnerships funded by the U.S. Department of Energy. MRCSP ( www.mrcsp.org ) covers a large region across nine Midwestern and Mid-Atlantic states, with several geologic provinces including: The Michigan and Appalachian Basins, the Cincinnati Arch Province, and the coastal sedimentary layers. Given the long history of coal production, much of the region is heavily dependent on coal-fired plants for electricity, and, therefore, subject to significant economic impact from carbon-emission constraints. The sedimentary formations or geologic structures across the region provide diverse options to mitigate the emissions through geologic storage of CO 2 . The validation for the storage potential comes through field assessments of injectivity and containment at three locations: One each in the Appalachian and Michigan Basins and one in the uplifted Cincinnati Arch region. All three field projects were conducted in a series of steps that contribute towards development of best practices for carbon capture and storage (CCS) validation that are applicable to the MRCSP region and elsewhere. Although specific practices are highly site dependent, the general steps include initial regional geologic assessment, site characterization through seismic surveys and drilling of test wells, permitting, outreach, development of a CO 2 supply system, injection and monitoring operations, and post-injection monitoring and site closure. Collectively, the regional mapping and three field demonstrations provide significant insight into geologic storage feasibility over a range of rock types and properties. Two of the tested sites indicate injection and storage rates exceeding 1000 tonnes/day/well. Such rates suggest that commercial-scale applications should be possible with a reasonable number of wells. The regional mapping of these zones also indicates that the tested layers are likely to be continuous over a large area, and, therefore, have potential for large-scale, long-term injection operations required for the numerous CO 2 sources in the region.

The Midwest Regional Carbon Sequestration Partnership (MRCSP) is conducting large-scale CO 2 injection into carbonate reefs in northern Lower Michigan, using CO 2 -enhanced oil recovery (EOR) fields as test beds for understanding geoscience issues and developing best practices. Depleted oil and gas fields are of regional importance as they are increasingly seen as a significant opportunity for geologic storage in Midwestern USA. The demonstration and concurrent technology transfer are aimed at promoting this early deployment option for carbon capture utilization and storage (CCUS). Three types of reef are being evaluated: late stage reefs that have already undergone significant CO 2 -EOR, active stage reefs with ongoing CO 2 -EOR, and newly targeted reefs that are in primary production. Initial modeling and monitoring results, as well as feasibility assessments of using technologies such as tracer studies, vertical seismic profiling, microseismic monitoring, borehole gravity survey, and remote sensing, are guiding the design of the long-term monitoring, verification, and accounting (MVA) program.