Exploration and Production Technologies
Carbon Dioxide-Enhanced Oil Production from the Citronelle Oil Field in the Rodessa Formation, South Alabama Last Reviewed 12/24/2013


The goal of this project is to conduct a carbon dioxide (CO2) injection test at the Citronelle oilfield in Mobile County, AL. The project will introduce CO2-enhanced oil recovery (CO2-EOR) for tertiary recovery from Alabama’s uniquely structured sandstone reservoirs, providing oilfield operators and CO2 producers with improved estimates of oil yields from EOR, and the capacity of the depleted reservoirs to sequester CO2. The research will improve the reliability of computer simulations of oil yield from CO2-EOR, calculations of sequestration capacity, and the rate at which CO2 can be introduced into underground formations. The simulations of the Citronelle field will be integrated with computer visualizations of the migration of oil, water, and CO2 with the results made accessible to reservoir engineers, geologists, utility planners, and researchers studying carbon sequestration.

University of Alabama at Birmingham, Birmingham, AL
Alabama Agricultural and Mechanical University, Normal, AL
Denbury Resources Inc., Plano, TX
Geological Survey of Alabama, Tuscaloosa, AL
Southern Company, Birmingham, AL
University of Alabama, Tuscaloosa, AL
University of North Carolina at Charlotte, Charlotte, NC

Carbon dioxide-enhanced oil recovery is a well-established method for increasing oil recovery from the Permian Basin oilfields of Texas and New Mexico and from the Williston Basin in North Dakota and Montana. Denbury Resources has also been successful in applying the technique in Mississippi oilfields. Typically, ten percent of the original oil present in a reservoir at the start of production can be recovered using CO2-EOR. A recent study by Advanced Resources International of Arlington, VA, estimated that 64 million additional barrels of oil could be recovered from the Citronelle field using this technology. When oil production is complete, the reservoir and adjacent formations can provide sites for storage of CO2 produced from the combustion of fossil fuels in power plants and other industrial processes that generate large quantities of CO2. Southern Company is evaluating the capacity of such reservoirs as possible sites for permanent sequestration of CO2 that has been separated from coal and natural gas combustion products produced by its power plants.

The Citronelle field is an ideal site for CO2-EOR and sequestration from both reservoir engineering and geological perspectives. The field is mature and waterflooded, with existing infrastructure, including deep wells, and consists of fluvial-deltaic sandstone reservoirs in a simple structural dome. Presence of the regionally extensive Ferry Lake Anhydrite seal, four-way structural closure, and lack of faulting make the field naturally stable with respect to CO2 storage. However, the geology of the heterogeneous siliciclastic rocks in this field is very different from fields where CO2-EOR has been applied commercially, such as in the carbonate strata of the Permian and Williston basins. The proposed demonstration will introduce CO2-EOR for tertiary recovery from Alabama’s uniquely structured energy resources and thus realize benefits to the nation from additional petroleum production.

A successful demonstration of the technology in this project could lead to new commercial CO2-EOR and sequestration efforts across the nation (including reservoir types where CO2-EOR has thus far not been applied) offering a potential two-for-one solution to the United States' energy security and environmental concerns.

The initial principal focus (January 1, 2007 to August 31, 2008) was on selection and preparation of the test site and, thorough studies of its geology, environmental conditions (air, soil, and vegetation), seismic imaging, and produced fluids, establishing the background conditions prior to CO2 injection. The petrology, sedimentology, and stratigraphy of the Rodessa Formation in the vicinity of the test site were determined and documented at an unprecedented level of detail. Realistic and informative reservoir simulations and visualizations were performed. The environmental and ecological background conditions surrounding the site are well documented. Seismic signals have been recorded under both baseline water flood conditions and during CO2 injection. The minimum miscibility pressure and absence of precipitation from oil in the presence of CO2 were established and an economic analysis identified the optimum CO2 slug size for water-alternating-gas oil recovery under specified CO2 cost and oil price constraints. All indications were that the pilot test would provide an unequivocal demonstration of CO2-enhanced oil recovery and essential data and simulations on which to base a commercial CO2 flood in the Citronelle Field. The CO2 storage capacity of depleted oil reservoirs and saline formations in Citronelle Dome was estimated by static calculations to be between 0.5 and 2 billion short tons of CO2, sufficient to sequester the CO2 from a nearby 1500 MW (electric) coal-fired power plant for 35 years.

CO2 injection began at the end of November 2009. After resolution of some initial difficulties in pumping, injection of CO2 continued without significant interruption at an average rate of 31 tons/day from January 27 to September 25, 2010, in good agreement with the average of 35 tons/day anticipated by reservoir simulations. Injection of the 8000 tons of CO2 allocated for the test was completed. Oil produced from three wells in the test pattern (B-19-7, B-19-8, and B-19-9) was gathered, along with production from five other wells to the north and east, at Tank Battery B-19-8. Produced oil from well B-19-11 in the test pattern goes to Tank Battery B-19-11, along with production from three other wells to the west and south. Incremental oil recovery was predicted to be 20,000 stock tank barrels, an increase of 60 percent over the yield expected from conventional secondary oil recovery by water flood.

A parametric study of WAG recovery, using the MASTER 3.0 reservoir simulator, showed that a properly designed WAG recovers as much oil as continuous CO2 injection. Using the simulation results, three-dimensional animations were programmed showing the evolution of fluid saturations in Donovan Sands 14-1 and 16-2 during two CO2 injections of 7500 tons each, followed by water. The animations nicely capture the mobilization of oil by CO2, development of the oil bank, the role of water in mobilizing the bank, and the residual oil left unrecovered.

Shear-wave velocities were measured to depths of 12,500 feet using the Refraction Microtremor technique. Wireless geophones were placed along two straight paths spanning 30,100 and 25,600 feet south and southwest, respectively, of the injection well. Shear-wave velocities recorded before and during CO2 injection suggested a 10 percent increase in stress associated with CO2 injection in the geologic layers above the injection zone. An interesting systematic increase in the dependence of shear-wave velocity at depth below ~4500 feet was observed during injection of the CO2 and water.

A pressure-transient test in the injector conducted in November and December 2011 provided strong evidence for the presence of a 600 to 1000 foot vertical fracture intersecting the injection well. The presence of a fracture was completely unexpected, because the injection well had never been intentionally hydraulically fractured and the hydrocarbon-bearing sands at Citronelle are free of natural fractures. Although the direction of the fracture cannot be determined from the results of the pressure-transient test, a fracture in the direction of maximum horizontal compressive stress in the southeastern U.S. would explain the early excessive breakthrough of CO2and loss of oil production from the fourth producer in the inverted five-spot (Well B-19-11). The avoidance or management of hydraulic fracturing will be an important component of the reservoir management plan during a commercial CO2 flood.

Two problems were experienced upon returning to water injection following completion of the CO2 injection in September 2010: (1) excessive erosion-corrosion of the downhole power-oil pumps by particles and scale mobilized by the CO2 and (2) loss of injectivity to water. Once the erosion-corrosion problem was solved by replacing the power-oil pumps with pumps having longer stroke and fabricated using harder materials, attention focused on understanding the loss in injectivity to water following the injection of CO2, an issue that has significant bearing on the design of a commercial CO2 flood at Citronelle.

An injection profile test run in the injector in January 2012 showed that the loss in injectivity to water (following CO2 injection) is due to reduced injectivity in only one of the two target sands. Injectivity to water decreased from approximately 130 to only 24 bbl water/day in the upper sand (Sand 14-1) and remained approximately the same, at 30 to 45 bbl water/day, in the lower sand (Sand 16-2). The ability to mitigate formation damage due to interaction of CO2, water, minerals, and brine solutes will be a critical factor in the decision to conduct WAG recovery at Citronelle should CO2 supply be limited.

Approximately 23,000 bbl of incremental oil assignable to EOR have been recovered from three of the wells in the inverted five-spot as of the end of September 2013. Although this has been offset by the loss in production from Well B-19-11, the overall net incremental oil production is positive, at 3500 bbl.

A series of tests is underway to determine the cause of the loss in injectivity to water. The first (conducted from July to November 2012) was to treat injected water with surfactant. The decline in oil production experienced at Tank Battery B-19-8 from March to July 2012 was reversed by the surfactant, with oil production remaining steady at approximately 40 bbl oil/day from August 2012 to date. The injectivity to water, however, did not improve. Production at Tank Battery B-19-11 remains on the declining path established following breakthrough of CO2 at Well B-19-11, evidently through the fracture identified by Eric Carlson in the pressure-transient test results. Production at Tank Battery B-19-11 has not shown significant response to any changes in conditions at the injector, including the return from CO2 to water injection at the end of September 2010.

The injector was treated with a heavy hydrocarbon solvent and asphaltene dispersant on November 13, 2013. The objective was to determine whether the loss in injectivity to water may have been due to heavy ends left near the wellbore after the CO2 extracted lighter components. The solvent and dispersant treatment had no significant effect on the water injection rate.

Current Status (December 2013) 
The following additional tests to explain the low injectivity to water after CO2 injection are being planned for December 2013 and January 2014.

  • Acid treatment to determine whether carbonate precipitation or plugging by mobilized acid-soluble particles is responsible for the low injectivity to water in Sand 14-1. Acidification will be followed by an injection profile test to determine any change in the distribution of water between the two target sands.
  • A step-rate test to determine the opening stress of the fracture at the injector and an evaluation of the feasibility of implementing “smart wells” in which pressure is actively controlled to minimize opening of fractures and bypassing of CO2.

Project Start: January, 1 2007
Project End: January 31, 2014

Anticipated DOE Contribution: $4,692,957
Performer Contribution: $4,053,321 (46 percent of total)

Contact Information 
NETL – Chandra Nautiyal (chandra.nautiyal@netl.doe.gov or 281-494-2488)
University of Alabama at Birmingham – Peter Walsh (pwalsh@uab.edu or 205-934-1826)
If you are unable to reach the above personnel, please contact the content manager.

Additional Information

Quarterly Research Progress Report [PDF-5.2MB] October - December, 2013

Quarterly Research Progress Report [PDF-5.18MB] July - September, 2013

Quarterly Research Progress Report [PDF-2.83MB] January - March, 2012

J.C. Pashin and R.A. Esposito, "Citronelle Dome: A Giant Opportunity for Multi-Zone Carbon Storage and Enhanced Oil Recovery in the Mississippi Interior Salt Basin of Alabama," Annual Convention and Exhibition of the American Association of Petroleum Geologists, Long Beach, CA, April 1-4, 2007.

R.A. Esposito, J.C. Pashin, and P.M. Walsh, "Citronelle Dome: A Giant Opportunity for Multi-Zone Carbon Storage and Enhanced Oil Recovery in the Mississippi Interior Salt Basin of Alabama," 2007 Annual Convention of the Gulf Coast Association of Geological Societies and the Gulf Coast Section of the Society for Sedimentary Geology, Corpus Christi, TX, October 21-23, 2007.

R. A. Esposito, J. C. Pashin, and P. M. Walsh, "Citronelle Dome: A Giant Opportunity for Multi-Zone Carbon Storage and Enhanced Oil Recovery in the Mississippi Interior Salt Basin of Alabama," accepted for publication in Environmental Geosciences, June 2008.

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