skip to main content
OSTI.GOV title logo U.S. Department of Energy
Office of Scientific and Technical Information

Title: CO 2 Storage and Enhanced Oil Recovery: Bald Unit Test Site, Mumford Hills Oil Field, Posey County, Indiana

Abstract

The Midwest Geological Sequestration Consortium (MGSC) carried out a small-scale carbon dioxide (CO 2) injection test in a sandstone within the Clore Formation (Mississippian System, Chesterian Series) in order to gauge the large-scale CO 2 storage that might be realized from enhanced oil recovery (EOR) of mature Illinois Basin oil fields via miscible liquid CO 2 flooding.

Authors:
 [1];  [1];  [1];  [1];  [1]
+ Show Author Affiliations
  1. Illinois State Geological Survey, Champaign, IL (United States)
Publication Date:
Research Org.:
Illinois State Geological Survey, Champaign, IL (United States)
Sponsoring Org.:
USDOE Office of Fossil Energy (FE)
OSTI Identifier:
1058966
Report Number(s):
DOE/NT/42588-03
DOE Contract Number:
FC26-05NT42588
Resource Type:
Technical Report
Country of Publication:
United States
Language:
English
Subject:
02 PETROLEUM; 58 GEOSCIENCES; 54 ENVIRONMENTAL SCIENCES; 42 ENGINEERING; 47 OTHER INSTRUMENTATION; 97 MATHEMATICS AND COMPUTING; CO2; EOR; storage; miscible; pilot

Citation Formats

Frailey, Scott M., Krapac, Ivan G., Damico, James R., Okwen, Roland T., and McKaskle, Ray W. CO2 Storage and Enhanced Oil Recovery: Bald Unit Test Site, Mumford Hills Oil Field, Posey County, Indiana. United States: N. p., 2012. Web. doi:10.2172/1058966.
Copy to clipboard
Frailey, Scott M., Krapac, Ivan G., Damico, James R., Okwen, Roland T., & McKaskle, Ray W. CO2 Storage and Enhanced Oil Recovery: Bald Unit Test Site, Mumford Hills Oil Field, Posey County, Indiana. United States. doi:10.2172/1058966.
Copy to clipboard
Frailey, Scott M., Krapac, Ivan G., Damico, James R., Okwen, Roland T., and McKaskle, Ray W. Fri . "CO2 Storage and Enhanced Oil Recovery: Bald Unit Test Site, Mumford Hills Oil Field, Posey County, Indiana". United States. doi:10.2172/1058966. https://www.osti.gov/servlets/purl/1058966.
Copy to clipboard
@article{osti_1058966,
title = {CO2 Storage and Enhanced Oil Recovery: Bald Unit Test Site, Mumford Hills Oil Field, Posey County, Indiana},
author = {Frailey, Scott M. and Krapac, Ivan G. and Damico, James R. and Okwen, Roland T. and McKaskle, Ray W.},
abstractNote = {The Midwest Geological Sequestration Consortium (MGSC) carried out a small-scale carbon dioxide (CO2) injection test in a sandstone within the Clore Formation (Mississippian System, Chesterian Series) in order to gauge the large-scale CO2 storage that might be realized from enhanced oil recovery (EOR) of mature Illinois Basin oil fields via miscible liquid CO2 flooding.},
doi = {10.2172/1058966},
journal = {},
number = ,
volume = ,
place = {United States},
year = {Fri Mar 30 00:00:00 EDT 2012},
month = {Fri Mar 30 00:00:00 EDT 2012}
}
Copy to clipboard
Technical Report:
View Technical Report (114.42 MB)
DOI:  10.2172/1058966
Save / Share:
Export Metadata
Save to My Library
You must Sign In or Create an Account in order to save documents to your library.

  • ; ; ; ...

  • ; ;
    Geologic carbon storage (GCS) is a crucial part of a proposed mitigation strategy to reduce the anthropogenic carbon dioxide (CO 2) emissions to the atmosphere. During this process, CO 2 is injected as super critical carbon dioxide (SC-CO 2) in confined deep subsurface storage units, such as saline aquifers and depleted oil reservoirs. The deposition of vast amounts of CO 2 in subsurface geologic formations could unintentionally lead to CO 2 leakage into overlying freshwater aquifers. Introduction of CO 2 into these subsurface environments will greatly increase the CO 2 concentration and will create CO 2 concentration gradients that drivemore » changes in the microbial communities present. While it is expected that altered microbial communities will impact the biogeochemistry of the subsurface, there is no information available on how CO 2 gradients will impact these communities. The overarching goal of this project is to understand how CO 2 exposure will impact subsurface microbial communities at temperatures and pressures that are relevant to GCS and CO 2 leakage scenarios. To meet this goal, unfiltered, aqueous samples from a deep saline aquifer, a depleted oil reservoir, and a fresh water aquifer were exposed to varied concentrations of CO 2 at reservoir pressure and temperature. The microbial ecology of the samples was examined using molecular, DNA-based techniques. The results from these studies were also compared across the sites to determine any existing trends. Results reveal that increasing CO 2 leads to decreased DNA concentrations regardless of the site, suggesting that microbial processes will be significantly hindered or absent nearest the CO 2 injection/leakage plume where CO 2 concentrations are highest. At CO 2 exposures expected downgradient from the CO 2 plume, selected microorganisms emerged as dominant in the CO 2 exposed conditions. Results suggest that the altered microbial community was site specific and highly dependent on pH. The site-dependent results suggest a limited ability to predict the emerging dominant species for other CO 2-exposed environments. This study improves the understanding of how a subsurface microbial community may respond to conditions expected from GCS and CO 2 leakage. This is the first step for understanding how a CO 2-altered microbial community may impact injectivity, permanence of stored CO 2, and subsurface water quality. Future work with microbial communities from new subsurface sites would increase the current understanding of this project. Additionally, incorporation of metagenomic methods would increase understanding of potential microbial processes that may be prevalent in CO 2 exposed environments.« less

  • ; ;
    Geologic carbon storage (GCS) is a crucial part of a proposed mitigation strategy to reduce the anthropogenic carbon dioxide (CO 2) emissions to the atmosphere. During this process, CO 2 is injected as super critical carbon dioxide (SC-CO 2) in confined deep subsurface storage units, such as saline aquifers and depleted oil reservoirs. The deposition of vast amounts of CO 2 in subsurface geologic formations could unintentionally lead to CO 2 leakage into overlying freshwater aquifers. Introduction of CO 2 into these subsurface environments will greatly increase the CO 22 concentration and will create CO 2 concentration gradients that drivemore » changes in the microbial communities present. While it is expected that altered microbial communities will impact the biogeochemistry of the subsurface, there is no information available on how CO 2 gradients will impact these communities. The overarching goal of this project is to understand how CO 2 exposure will impact subsurface microbial communities at temperatures and pressures that are relevant to GCS and CO 2 leakage scenarios. To meet this goal, unfiltered, aqueous samples from a deep saline aquifer, a depleted oil reservoir, and a fresh water aquifer were exposed to varied concentrations of CO 2 at reservoir pressure and temperature. The microbial ecology of the samples was examined using molecular, DNA-based techniques. The results from these studies were also compared across the sites to determine any existing trends. Results reveal that increasing CO 2 leads to decreased DNA concentrations regardless of the site, suggesting that microbial processes will be significantly hindered or absent nearest the CO 2 injection/leakage plume where CO 2 concentrations are highest. At CO 2 exposures expected downgradient from the CO 2 plume, selected microorganisms emerged as dominant in the CO 2 exposed conditions. Results suggest that the altered microbial community was site specific and highly dependent on pH. The site-dependent results suggest a limited ability to predict the emerging dominant species for other CO 2 exposed environments. This study improves the understanding of how a subsurface microbial community may respond to conditions expected from GCS and CO 2 leakage. This is the first step for understanding how a CO 2-altered microbial community may impact injectivity, permanence of stored CO 2, and subsurface water quality. Future work with microbial communities from new subsurface sites would increase the current understanding of this project. Additionally, incorporation of metagenomic methods would increase understanding of potential microbial processes that may be prevalent in CO 2 exposed environments.« less

  • ; ; ; ...
    The technology for CO 2 Enhanced Oil Recovery (CO 2 EOR) has significantly advanced since the earliest floods were implemented in the 1970s. At least for the Permian Basin region of the U.S., the oil recovery has been now been extended into residual oil zones (ROZs) where the mobile fluid phase is water and immobile phase is oil. But the nature of the formation and fluids within the ROZs has brought some challenges that were not present when flooding the MPZs. The Goldsmith-Landreth project in the Permian Basin was intended to first identify the most pressing issues of the ROZsmore » floods and, secondly, begin to address them with new techniques designed to optimize a flood that commingled the MPZ and the ROZ. The early phase of the research conducted considerable reservoir and fluid characterization work and identified both technical and commercial challenges of producing the enormous quantities of water when flooding the ROZs. It also noted the differing water compositions in the ROZ as compared to the overlying MPZs. A new CO 2 gas lift system using a capillary string was successfully applied during the project which conveyed the CO 2 to the deeper and differing ROZ reservoir conditions at Goldsmith and added a second capillary string that facilitated applying scale inhibitors to mitigate the scaling tendencies of the mixing ROZ and MPZ formation waters. The project also undertook a reservoir modeling effort, using the acquired reservoir characterization data, to history match both the primary and water flood phases of the MPZ and to establish the initial conditions for a modeling effort to forecast response of the ROZ to CO 2 EOR. With the advantage of many profile logs acquired from the operator, some concentration on the original pattern area for the ROZ pilot was accomplished to attempt to perfect the history match for that area. Several optional scenarios for producing the ROZ were simulated seeking to find the preferred mode of producing the two intervals. Finally, the project attempted to document for the first time the production performance of commingled MPZ and ROZ CO 2 EOR project at the nearby Seminole San Andres Unit. The analysis shows that over 10,000 bopd can be shown to be coming from the ROZ interval, a zone that would have produced no oil under primary or water flood phases. A similar analysis was done for the GLSAU project illustrating that 2000 bopd of incremental EOR oil is currently being produced. The results of the modeling work would suggest that 800 bopd can be attributed to the ROZ alone at GLSAU.« less

  • ; ; ; ...
    Tight oil formations such as those in the Bakken petroleum system are known to hold hundreds of billions of barrels of oil in place; however, the primary recovery factor for these plays is typically less than 10%. Tight oil formations, including the Bakken Formation, therefore, may be attractive candidates for enhanced oil recovery (EOR) using CO 2. Multiphase fluid behavior and flow in fluid-rich shales can vary substantially depending on the size of pore throats, and properties such as fluid viscosity and density are much different in nanoscale pores than in macroscale pores. Thus it is critical to understand themore » nature and distribution of nano-, micro-, and macroscale pores and fracture networks. To address these issues, the Energy & Environmental Research Center (EERC) has been conducting a research program entitled “Improved Characterization and Modeling of Tight Oil Formations for CO 2 Enhanced Oil Recovery Potential and Storage Capacity Estimation.” The objectives of the project are 1) the use of advanced characterization methods to better understand and quantify the petrophysical and geomechanical factors that control CO 2 and oil mobility within tight oil formation samples, 2) the determination of CO 2 permeation and oil extraction rates in tight reservoir rocks and organic-rich shales of the Bakken, and 3) the integration of the laboratory-based CO 2 permeation and oil extraction data and the characterization data into geologic models and dynamic simulations to develop predictions of CO 2 storage resource and EOR in the Bakken tight oil formation. A combination of standard and advanced petrophysical characterization techniques were applied to characterize samples of Bakken Formation tight reservoir rock and shales from multiple wells. Techniques included advanced computer tomography (CT) imaging, scanning electron microscopy (SEM) techniques, whole-core and micro x-ray CT imaging, field emission (FE) SEM, and focused ion beam (FIB) SEM. Selected samples were also analyzed for geomechanical properties. X-ray CT imaging yielded information on the occurrence of fractures, bedding planes, fossils, and bioturbation in core, as well as data on bulk density and photoelectric factor logs, which were used to interpret porosity, organic content, and mineralogy. FESEM was used for characterization of nano- and microscale features, including nanoscale pore visualization and micropore and pore throat mineralogy. FIBSEM yielded micro- to nanoscale visualization of fracture networks, porosity and pore-size distribution, connected versus isolated porosity, and distribution of organics. Results from the characterization activities provide insight on nanoscale fracture properties, pore throat mineralogy and connectivity, rock matrix characteristics, mineralogy, and organic content. Laboratory experiments demonstrated that CO 2 can permeate the tight matrix of Bakken shale and nonshale reservoir samples and mobilize oil from those samples. Geologic models were created at scales ranging from the core plug to the reservoir, and dynamic simulations were conducted. The data from the characterization and laboratory-based activities were integrated into modeling research activities to determine the fundamental mechanisms controlling fluid transport in the Bakken, which support EOR scheme design and estimation of CO 2 storage potential in tight oil formations. Simulation results suggest a CO 2 storage resource estimate range of 169 million to 1.5 billion tonnes for the Bakken in North Dakota, possibly resulting in 1.8 billion to 16 billion barrels of incremental oil.« less