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Chemically Enabled Carbon Dioxide Enhanced Oil Recovery in Multi-Porosity, Hydrothermally Altered Carbonates in the Southern Michigan Basin
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The goal of this research project is to conduct a comprehensive laboratory experiment, computer modeling, and field testing-based evaluation of chemically enabled carbon dioxide enhanced oil recovery (CO2-EOR) in the Southern Michigan Basin (MB)—with a focus on the conventional Trenton/Black River (TBR) play. This work will be conducted in the complex multi-porosity (i.e., matrix, vuggy, and fracture porosities) and/or hydrothermally altered dolomite (HTD) reservoirs developed along fault systems. The results of this research will help to provide strategies to improve oil recovery in complex carbonate formations and development plans for historical plays, thus increasing the likelihood of the application of EOR methods for similar reservoirs and numerous operators across a wide range of reservoirs and fields.


Battelle Memorial Institute – Columbus, OH 43201


The TBR is a giant play (>100,000 Bbl/day production at its peak) in southern Michigan with a great potential for undiscovered hydrocarbons. The United States Geological Survey (USGS) estimates recoverable reserves of 824 MMBO and 1.4 TCF of gas from the TBR in the MB that have yet to be discovered, making the TBR a significant resource for future development. The complex, multi-porosity (i.e., matrix, vuggy, and fracture porosities) and/or HTD TBR reservoirs which are developed along fault systems are especially challenging for EOR due to heterogeneities and compartmentalization, the presence of thief zones, and the lack of conformance. Injection of pure carbon dioxide (CO2) alone may not be effective in recovering stranded oil, and the addition of surfactants and other chemicals may assist in overcoming challenges posed by multi-porosity reservoirs. This project will address these challenges through advanced field characterization, integrated physics-based machine learning and data analytics, laboratory tests to determine the right additives to CO2, and optimized field tests for CO2-EOR performance.


These results will be used to conduct scale-up assessment, CO2 source analysis, and economic analysis, which will lead to a field development plan for the HTD play. Project results will demonstrate the feasibility of advancing CO2-EOR with chemical additives to overcome heterogeneous porosity in the TBR in southern Michigan and provide a path forward for future development. The project will help reinvigorate depleted oil fields in HTD type reservoirs in the MB, with technical transferability to other similar basins.

Accomplishments (most recent listed first)
  • As McCann 1-20 well was deemed not suitable for the project, West Bay Exploration was engaged as a new partner, and they are in discussion with EPA to understand how the pre-existing permits (expired) could be leveraged to expedite Field Injection Tests. (For example, modification typically does not have to go through public review like a new permit).
  • Working with West Bay, Battelle determined that the Fischhaber 2-35 and Marshell 1-35 in the Lee 26 field were suitable for our testing plans as they have preexisting class II permits.  Characterization for the Lee 26 field included stratigraphic evaluation, petrophysical modeling to estimate porosity, permeability, and reservoir volume, as well as 3D seismic interpretation to identify local faults or fractures that may be providing structural control on production characteristics within the field.  
  • Production data for the Lee 26 field was provided by West Bay, and a simplified tank model was built of the target reservoir. The tank model was used to generate a production history match. The history match was then used to simulate a water-based repressurization scenario, which provided initial estimates of rate and total fluid volumes needed to reach 1000 psi reservoir pressure. 
  • Local availability and characterization of water, brine, and NGLs was investigated.
  • Connections have been made to CO2 suppliers within the region, and initial estimates for CO2 volume, cost, pumping, and storage rental have been secured.
  • Thirteen 1.5-inch diameter core samples were obtained from the Napoleon field.
    • CT scans were conducted. The analysis indicated many small and large vugs present in the core samples, but no obvious fractures. 
    • Mercury Porosimetry tests were conducted. Intrusion volume of mercury versus applied pressure were obtained, and the pressures were converted into pore throat sizes. 
    • Oil/water relative permeability tests were conducted using one composite core mount composed of three core samples. The results showed an absolute permeability of 53 mD, which is close to the true reservoir average permeability.
    • Imbibition tests were conducted for two core samples to determine the oil recovery variation with time. 
  • Previously collected and analyzed image logs from the Napoleon field were integrated into the database. This required splitting the images into multiple segments and depth aligning them with wireline logs to ensure appropriate matching. Fracture analysis of the image logs is ongoing. 
  • A preliminary monitoring plan was updated and developed which will include downhole pressure monitoring, wellhead monitoring including pressure and injection rates, repeat fluid sampling, and repeat logging of pulsed neutron capture, temperature, and sonic logs.
Current Status

Spectral pulsed neutron logs are being collected to determine fluid saturation changes within the reservoir, and deep shear wave acoustic logs are being collected to assess the presence of faults and fractures.

Ongoing technical work includes developing static and dynamic models of the field to estimate rate and volume for CO2 and water injection, as well as laboratory testing to determine the injection style (water-alternating-gas, foam, or pure CO2 flood), minimum miscibility pressure, and optimal injection pressure.
As results are obtained from lab testing and dynamic modeling, firm estimates for CO2 and water needs will be leveraged to establish CO2 supply and pumping contracts.

Project Start
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DOE Contribution


Performer Contribution


Contact Information

NETL – Kyle Clark ( or 304-285-5052)
Battelle Memorial Institute – Dr. Neeraj Gupta ( or 614-424-3820)
Battelle Memorial Institute - Matt Young ( or 614-424-3263)