Field examples continue to show the value of carbon dioxide injection for enhancing oil production.
The Permian basin of West Texas and Eastern New Mexico remains the most active area, but this technology has potential for other regions of the world, as noted at last December’s annual CO2 flooding conference in Midland, Tex.
The conference was the 12th held and with about 350 attending, the largest in attendance to date. Over the years, attendance at the conference has fluctuated, largely reflecting oil price swings.
In the last 4 years, the CO2 conference has added a carbon management workshop, with the last one held in Houston prior to the Midland venue.
The heightened worldwide interest in managing carbon emissions with geologic storage of CO2 may provide the industry new incentives for converting this waste product into a valuable asset for recovering additional oil from mature reservoirs.
The Society of Petroleum Engineers-Permian Basin Section and University of Texas of the Permian Basin were two of the conference sponsors.
Flood examples
Although CO2 EOR is a proven technology, the process requires extensive engineering and usually involves a phased development as well as close monitoring and multiple adjustments during a flood’s life.
The Denver Unit in Wasson field in West Texas is a prime example of a CO2 flood that continues to evolve. Wasson, discovered in 1935, held an estimated 4 billion bbl of oil initially in place and produces primarily from a 300-ft thick San Andres carbonate.
Prior to the formation of a waterflood unit in 1964, primary oil production from the wells in the unit area peaked at about 50,000 b/d in 1946. Waterflooding led to a new peak oil production plateau of about 150,000 b/d from 1972-80 prior to the onset of a production decline.
To arrest the decline, Shell Oil Co., then operator of the unit, in 1984 initiated CO2 injection in the eastern part of the unit. Unlike waterflooding, CO2 injection did not create another peak but did lower the decline rate. The initial response to CO2 injection leveled the production to 35,000-40,000 b/d. Occidental Permian Ltd. now operates the unit, which currently produces about 29,000 bo/d attributed to CO2 injection.
Maintaining these production levels required the unit to undergo various changes as more was learned about the process, according to a presentation at the Midland conference. Changes included:
- Changing the continuous CO2 injection in the eastern part to water-alternating-gas (WAG) injection and expanding the CO2 injection to the western and central part of the unit in 1989.
- Stopping CO2 injection in the southern part of the unit and in nonperforming patterns in the central area in 1992.
- Revising the approved CO2 slug sizes in the eastern area to 60% from 40% hydrocarbon pore volume in 1994, to 80% in 1996, and to 100% in 2001. The increases in slug size allow CO2 to enter more portions of the moderate and low-permeability layers.
- Changing from an inverted nine-spot pattern in the eastern area to a semi-infill line drive in 1996.
- Developing the transition zone in the eastern area in 1996.
- Continuing to optimize the chase water volumes and WAGs based on pattern maturity.
Other areas
Outside the Permian basin some other CO2 EOR activity includes Denbury Resources Inc. expanding CO2 EOR to new fields in Mississippi, Anadarko Petroleum Corp. continuing phased development of CO2 injection in Salt Creek field in Wyoming, and Apache Canada Ltd. evaluating pilot projects that inject acid gas in previously waterflooded pinnacle reefs in Alberta. A project is also slated for Croatia.
The North Sea is another area with potential projects. BP PLC has proposed a CO2 EOR project in Miller field, off UK, and Shell and Statoil ASA have announced a feasibility study on Draugen field, off Norway. Both these North Sea projects would use CO2 from newly built onshore power plants.
New CO2 sources are vital for expanding CO2 EOR. Even the expansion of projects in the Permian basin is limited by constraints in CO2 supply.
