699F4977-FCB7-461E-B7D0-846DC1BEF6AF@3x

Announcements

Location: New Haven, West Virginia

The objective of the American Electric Power (AEP) Mountaineer project (DOE-NETL Cooperative Agreement DE-AC26-98FT40418) was to assess the potential for geologic storage of CO2 in the Ohio River Valley and to determine the feasibility of on-site capture and CO2 storage at a coal-fired power plant. An extensive program of drilling, sampling, and testing a deep well combined with a seismic survey was used to characterize the local and regional geologic features at AEP’s 1300-megawatt Mountaineer Power Plant outside of New Haven, West Virginia. Feasibility and design assessment activities included an assessment of the CO2 source options; development of the injection and monitoring system design; preparation of regulatory permits; and continued stakeholder outreach. The onsite injection wells are among a few wells to reach the post-injection site care stage among carbon storage projects, which involves post-injection monitoring, modeling, and reporting needed to demonstrate secure and permanent storage. Injection and storage of CO2 into deep rock formations represents a feasible option to reduce greenhouse gas emissions from coal-burning power plants concentrated along the Ohio River Valley area.

Location: Decatur, IL

The goal of the Illinois Basin Decatur Project was to conduct a large-scale demonstration of deep saline geological storage and to validate the capacity, injectivity, and containment of the Mt. Simon sandstone. The project was supported by the U.S. Department of Energy (DE-FC26-05NT42588) and the Illinois Department of Commerce and Economic Opportunity. The MGSC partnered with Archer Daniels Midland Company (ADM) and Schlumberger Carbon Services to inject 1 million metric tons of CO2 over a three-year injection period at the ADM plant location in Decatur, Illinois. Operational injection started on November 17, 2011 and was completed successfully on November 26, 2014 with a total volume of 999,215 tonnes. An extensive Monitoring, Verification, and Accounting program has been undertaken and is focused on the 0.65 km2 (0.25 mi2) project site. This includes surface monitoring techniques such as monitoring surface deformation, soil gas sampling, and shallow groundwater sampling. Subsurface monitoring techniques used included seismic surveying, temperature and pressure monitoring, fluid monitoring, and well logging. Monitoring was initiated in 2009 and concluded in 2017 after the three-year injection and three-year post-injection periods.

Location: Fayette County, IL

The Loudon Oil Field site was one of three Enhanced Oil Recovery (EOR) field validation tests conducted by the MGSC to assess potential for CO2 storage in oil in the Illinois Basin. The project was supported by the U.S. Department of Energy (DE-FC26-05NT42588) and the Illinois Department of Commerce and Economic Opportunity. CO2 was injected at the Loudon Oil Field test site in Fayette County, IL into the Cypress Sandstone, a 1,500 feet deep sandstone formation. A cumulative 43 tons of CO2 was injected, and the oil production rate peaked at 8 bopd with sustained oil rate of 1–2 bopd above the pre-CO2 injection rate. Baseline, injection, and post-injection monitoring were conducted until two years after the initial CO2 injection.  

Posey County, IN The MGSC Mumford Hill Field site was one of three Enhanced Oil Recovery (EOR) field validation tests conducted by the MGSC to assess potential for CO2 storage in oil in the Illinois Basin. The project was supported by the U.S. Department of Energy (DE-FC26-05NT42588) and the Illinois Department of Commerce and Economic Opportunity. CO2 was injected at the Mumford Hills Field test site in Posey County, IN through an existing well into the Clore Formation, an oil-bearing sandstone interval at about 1,900 feet deep. A cumulative 6,950 tons of CO2 was injection at a rate of 20–35 tons per day and increased oil production in surrounding wells. Approximately 0.5% of the injected CO2 was produced at the surface through September 2011, and 99.5% of the injected CO2 was stored. Baseline, injection, and post-injection monitoring were conducted until one year after the CO2 injection termination.

Hopkins County, KY

The MGSC Sugar Creed Field site was one of three Enhanced Oil Recovery (EOR) field validation tests conducted by the MGSC to assess potential for CO2 storage in oil in the Illinois Basin. The project was supported by the U.S. Department of Energy (DE-FC26-05NT42588) and the Illinois Department of Commerce and Economic Opportunity. CO2 was injected at the Sugar Creek Field test site in Hopkins County, IL into the Jackson Sandstone, an oil-bearing sandstone at a depth of 1,850 feet deep. A cumulative 7,230 tons of CO2 was injection at a rate of 20–30 tons per day, and CO2 was produced at the surface at relatively low rates. Oil production increased in surrounding wells nearly 10 bopd above pre-injection rates. Baseline, injection, and post-injection monitoring were conducted until one year after the CO2 injection termination.

Location: Rabbit Hash, KY

The MRCSP East Bend injection test was one of two injection tests conducted under the MRCSP Phase II (DOE-NETL Cooperative Agreement DE-FC26-05NT42589). The primary objective of the MRCSP East Bend injection test was to assess CO2 sequestration potential in the Mt. Simon sandstone, which is the largest potential geologic storage reservoir in the U.S. In addition, the test was aimed at providing information to help better understand the regional trends in the Mt. Simon as it is present across much of the Midwest. The injection site was located at Duke Energy’s East Bend Generating Station in Rabbit Hash, KY in proximity to a concentration of large, modern coal-fired power plants along the Ohio River and on the Cincinnati Arch. A total of 910 metric tons of liquid CO2 was injected over two days at a rate of 5 barrels per minute (1,200 metric tons/day or 400,000 metric tons/year). While the test volume was small, the test demonstrated good permeability and injectivity. A simple 2-year monitoring program mainly based on groundwater monitoring showed containment of CO2 with no evidence of leakage into shallower zones. This was the first injection of CO2 into the Mt. Simon Sandstone.

Location: Shadyside, Ohio

The MRCSP R.E. Burger injection test was one of two injection tests conducted under the MRCSP Phase II (DOE-NETL Cooperative Agreement DE-FC26-05NT42589). FirstEnergy’s R.E. Burger Power Plant is located in the Ohio River Valley, one of the nation’s largest power generation corridors and a central location in the Appalachian Basin. The main objectives of this test site were to explore geologic storage targets in this area of the Appalachian Basin and develop CO2 sequestration technology through drilling of a deep test well and conducting CO2 injection tests. Ultimately, less than 50 metric tons of CO2 was injected at this site due to the low injectivity of the sandstone reservoirs. However, valuable knowledge was gained that has led to a better understanding of the regional geology and greater familiarity with CO2 sequestration technologies. The negative finding in this well led to a more detailed storage potential assessment in Ohio’s Appalachian Basin, resulting in the emphasis on dolomitic vuggy carbonates, as a primary storage target in deep mature basins.

Location: Otsego County, MI

MRCSP Phase III Large-Scale Injection Project translated the lessons learned in Phases I and II into development and operation of a commercial-scale CCUS and Enhanced Oil Recovery project in northern Michigan. The public/private consortium, funded through the U.S. Department of Energy Regional Carbon Sequestration Initiative (DE-FC26-05NT42589), brings together nearly 40 industry partners and 10 states. The project injected more than one million tons of CO2 into oil fields in the Northern Niagaran Pinnacle Reef Trend in Otsego County, MI for geologic sequestration and enhanced oil recovery. This commercial-scale test provided additional real-world knowledge that has been used to further refine technologies and methods, reduce uncertainties, and demonstrate safety and effectiveness to increase public acceptance. Between 2013 and 2019, the MRCSP project stored 1,732,500 metric tons of CO2 and monitored the production of 1,167,000 barrels of oil.

Location: Eastern Ohio

The Ohio Coal Development Office (OCDO) Geologic Characterization Projects (CDO-D-1007a and OOE-CDO-D-13-22) focused on a sub-regional investigation for the Appalachian Basin region of Eastern Ohio. The key objectives were to review existing data and collect new data from deep wells to identify and evaluate potential CO2 storage reservoirs within Ordovician-Cambrian carbonate and sandstone intervals. Injection tests showed multiple formations were susceptible to injection, and detailed mapping and capacity estimates narrowed down candidate storage areas. Of the nine formations evaluated in the study area, the Maryville formation, the Upper Copper Ridge dolomite, the basal Cambrian sandstone, and the Lower Copper Ridge dolomite have the highest storage capacity potential. Additionally, a first of its kind caprock feasibility study established that the primary caprocks are sufficient to prevent CO2 leakage from the reservoir into higher formations. The regional analysis was the first step towards successful carbon storage in Ohio.

Location: Eastern Ohio

The Ohio Coal Development Office (OCDO) Enhanced Oil Recovery Projects (OOE-CDO-D-13-24 and OER-CDO-D-15-08) focused on an evaluation of technical and economic feasibility of CO2-EOR in the Clinton Sandstone of Eastern Ohio and the Knox Dolomite Group of North-Central Ohio. CO2 sequestration potential in the 30 major oilfields of Ohio was found to be 878 million metric tons based on replacement of void space created by historical oil and gas production. Numerous methodologies such as machine learning, statistical correlations, first-of-a-kind laboratory experiments, and numerical simulations were used to develop the knowledge base necessary to link operators of coal-fired power plants with small producers. Key accomplishments include the ability to identify fractures from well-log data and quantify their impact on CO2-EOR, the prediction of permeability and optimal operating pressure for CO2 floods with greater accuracy, a better understanding of CO2-oil interactions, and a framework for calculating risks from wellbore integrity issues. Detailed mapping of power plants and proximal oilfields helped identify promising candidates for a CCUS project and showed several feasible economic scenarios. CO2 was successfully injected into one well in the Clinton sandstone formation and one well in the Copper Ridge dolomite formation. This demonstrated acceptable injectivity and provided useful lessons on operational and cost issues associated with site preparation and monitoring.

Location: Offshore New York, New Jersey, Pennsylvania, Delaware, and Maryland

The goal of the Mid-Atlantic U.S. Offshore Carbon Storage Resource Assessment Project (Department of Energy Award Number DE-FE0026087) was to assess offshore carbon storage potential for the mid-Atlantic United States (i.e., New York, New Jersey, Pennsylvania, Delaware, and Maryland). Various publicly available data sets were compiled to define geologic characteristics for Cretaceous- and Jurassic-age sandstone sequences of three mid-Atlantic offshore sub-regions: the Georges Bank Basin, the Long Island Platform, and the Baltimore Canyon Trough. Estimates of CO2 storage capacity indicated a total of 150 to 1136 megatons (Mt), and preliminary reservoir simulations resulted in successful injection of 1 Mt CO2/year sustained for 30 years in single injection wells. This suggests mid-Atlantic U.S. offshore formations can store decades of CO2 from industrial sources in the region. Offshore geologic risk factors include soft sediment deformation, unit continuity, sedimentological and structural features, seismicity, and hydrates. CO2 storage risks include inadequate seals, migration/leakage, and chemical interactions leading to decreased storage. Government, industry, and environmental groups provided addressed next steps needed for future carbon storage project planning and implementation offshore of the mid-Atlantic United States. This project represents an important first step by building the knowledge infrastructure and providing a strong technical basis on which future carbon storage efforts can be built.

Location: Northern Michigan

The objective of the CarbonSAFE Northern Michigan Basin project (Department of Energy Award Number DE-FE0029276) was to take the first step in developing an integrated commercial geologic CO2 storage complex in the Northern Michigan Basin through the Phase I pre-feasibility study. This includes demonstrating that the storage sites within the complex have the potential to store more than 50 million metric tons (MMT) of industrially sourced CO2 emissions safely, permanently and economically. A high-level sub-basinal evaluation focused on assessing the lateral extent, thickness, structure, properties, and CO2 storage capacity for two saline reservoirs: the St. Peter sandstone and Bass Islands dolomite. Additionally, a catalog of Niagaran reefs was used in collaboration with the regional characterization work completed by the MRCSP to identify top targets for CO2-EOR. This study also included an evaluation of risks and identification of land usage. All the collected and interpreted data was integrated with CO2 source locations to identify potential regions for commercial-scale carbon capture and storage (CCS). The modeling analysis demonstrated 50 MMT of CO2 could be injected into the St. Peter Sandstone and that 82 reefs were needed to reach a goal of a combined commercial storage volume. Lastly, the project successfully formed a CCS coordinate team which consisted of industry partners, geoscience experts, legal and regulatory experts, outreach coordinators, and financial analysis experts. The team consisted of all critical expertise needed to develop a commercial CCS project in the region.

Location: Eastern Ohio

The CarbonSAFE Central Appalachian Basin project (Department of Energy Award Number DE-FE0029466) provided an integrated prefeasibility study of the Central Appalachian Basin. The project focused on Eastern Ohio, where storage potential has been previously defined in Cambrian-Ordovician age carbonate and sandstone formations. Phase I began the process of taking into account all the technical, socio-economic, scientific, and legislative aspects related to implementation of a carbon capture and storage (CCS) project in this area. Source suitability was assessed by identifying electricity generation and/or industrial sources large enough to provide CO2 emissions for a commercial-scale storage project. Because of its importance to Ohio’s economy, sources that use coal were a focus of this assessment. Geological suitability was assessed through the identification of geologic areas that can safely and permanently store CO2 for a commercial-scale CCS project (i.e., 50 million metric tonnes over 30 years). This assessment found sufficient CO2 storage capacity, high injectivity within the storage zone, presence of a thick and competent geologic seal (caprock), and low risk for tectonic activity and CO2 leakage. Project definition and integration factors including project dimensions, infrastructure requirements, mineral and property rights, economics, regulatory/political/technology issues, permitting, public outreach, and project liability were evaluated.

Location: Macon County, IL

The CarbonSAFE IL Macon County project, funded by the U.S. Department of Energy (DE-FE00029381), focuses on establishing the feasibility of a commercial-scale geological storage complex in Macon County, IL, that could store 50 million tonnes or more of industrially sourced CO2. The initial characterization involves developing and analyzing datasets of formation parameters for the target reservoir, the Mt. Simon sandstone, to evaluate the suitability of the potential site and address knowledge gaps. This includes drilling a stratigraphic test well in the Forsyth Oil Field to collect new data and establish the potential storage capacity. Static and dynamic models will be used to examine the performance of the site, refine storage estimates, and understand risks. A technical and non-technical risk assessment will be conducted to identify steps to reduce subsurface uncertainty and non-technical issues that will need to be addressed by future work. In addition, social attitudes toward the project will be monitored; permitting requirements, legal issues, and contractual issues will be outlined; source networks will be strengthened; and project partners will be assembled. The studies and outcomes of this phase will be part of the project’s knowledge sharing activities and will contribute to developing best practice manuals for deploying commercial-scale carbon capture and storage (CCS).

Location: Jackson County, MI

The Chemically Enabled CO2-Enhanced Oil Recovery (EOR) in Multi-Porosity, Hydrothermally Altered Carbonates in the Southern Michigan Basin Project (DOE-FOA-0001988) focuses on experimental design, field testing, and development of CO2-EOR in the Trenton Black River play. The research concept involves integration of multiple data types to evaluate fields in the study area that have the lowest technical and environmental risk and optimal setting for EOR. Laboratory experiments will be used to optimize a CO2 flood composition specific to hydrothermal dolomite rock properties, and subsequently design and simulate injection scenarios that offer wettability alteration, foaming, and reduced surface tension. This work will improve oil recovery from matrix porosity and mitigate the impact of fracture zones. The optimized design will be implemented and tested in a Trenton/Black River field. The results will provide strategies to improve oil recovery in complex carbonate formations in the Michigan Basin as well as in other carbonate plays. The key risks include working with data vintages; data availability; assessment of complex HTD systems, including thief zones and conformance issues; wellbore integrity of old wells; and cost and sourcing of CO2 for field tests. The identified risks will be mitigated through the developed methodologies and partnerships under laboratory experiments, characterization, and machine learning tasks, and by field test planning. The project will help reinvigorate depleted oil fields in HTD type reservoirs in the Michigan Basin, with technical transferability to other similar basins. While project funding will initiate CO2-EOR infrastructure in the Midwest, it will also lay the groundwork for future work.

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