CO2 FLOODING INCREASES RECOVERY

Primarily based on the following PTTC workshops:

“Carbon DioxideInjection for Enhanced Oil Recovery,” held on September 17, 1997, in Liberal, KS (North Midcontinent Region)

“Carbon DioxideFlooding,” held on March 13, 1998, in Jackson, MS (Eastern Gulf Region)

“CO ₂ Injection Fundamentals,” held on August 5, 1998, in Hobbs, NM (Southwest Region)

BOTTOM LINE

The results from ongoing carbon dioxide (CO ₂) flooding projects may help increase the profitability of future efforts. If crude oil prices are above a threshold level, there is significant recovery potential for improved oil recovery from CO ₂ flooding in the US.

PROBLEM ADDRESSED

CO ₂ flooding, when properly applied, has proven to be a viable enhanced oil recovery process in many geographic locations. To reduce risks and increase profitability, operators should look at the data and experiences of others to learn how to: determine if a reservoir is an attractive candidate, estimate potential recovery, choose an injection strategy, design well and surface equipment, and monitor and adapt flood strategies.

KEY WORDS:

Carbon Dioxide Flooding, Miscible Flooding, Screening Criteria, WAG Injection

TECHNOLOGY OVERVIEW

CO ₂ projects are major long-term investments. Budget realities preclude operators from performing these fullscale flooding studies on all reservoirs. Operators must first identify the most likely candidates, and then perform in-depth studies on them before deciding.

Screening Criteria. Miscible CO ₂ flooding typically is restricted to reservoirs deeper than 2,000 ft., with API oil gravity greater than 22-25º and remaining oil saturations greater than 20%. Correlations and minimum miscibility pressure (MMP) data will show if miscible flooding can be used in a given reservoir. Even if full miscibility is not achieved, a project may still prove worthwhile.

While CO ₂ flooding is not sensitive to lithology, it is sensitive to reservoir characteristics. Reservoirs that have performed well under waterflooding typically will perform well with CO ₂ flooding; waterfloods with poor sweep efficiencies or large injection losses are not good candidates. In addition, injectivity must be adequate, averaging 4% of hydrocarbon pore volume per year. Some unfavorable conditions include: large gas caps, excessive fractures, thin pay, wide spacing, high MMP, and thief zones. Knowing the flooding technique’s performance in analog reservoirs is crucial.

WAG Injection Strategy. With its high mobility, channeling and early breakthrough are possible in CO ₂ projects. This is commonly addressed with water-alternating-gas (WAG) injection, which helps control breakthrough despite a few inherent challenges. Lately, operators have injected CO ₂ slugs, switching to WAG injection after breakthrough. Foams or other agents also help control mobility. In early flood projects, operators applied a standard WAG process to all patterns. Field experience shows that it is more effective to closely monitor individual performance and tailor the WAG process to each pattern.

Predicting Economic Performance. For a tertiary flood, operators can expect to recover about 10% of the original-oil-in-place (OOIP). For a secondary flood, output could be doubled or tripled. When OOIP is not known, oil recovery typically is 25% of cumulative oil production. The maximum oil production rate, realized some years after flooding starts, usually is 10% of the waterflood injection rate. For instance, 5,000 barrels of water per day (bwpd) equate to a peak rate of 500 barrels of oil per day (bopd). Purchased CO ₂ requirements typically are 5 to 6 thousand cubic feet (mcf) per barrel, with injected ratios sometimes considerably higher.

Shell’s “CO ₂ Flood Scoping Package” predicts results in reservoirs by using dimensionless recovery curves calibrated to the project. Assuming a given WAG injection program, the curves relate cumulative injection and oil production levels. The input requirements are not as complex as those for true simulators. It uses experience based cost data to estimate project economics. Another software package, “CO ₂ Prophet,” developed by Texaco as part of a DOE Class I project, forecasts oil production using streamtube concepts. It requires more reservoir data and an understanding of engineering concepts.

Practical Insights. Operators can control costs and reduce CO ₂ purchases by staging floods and recycling CO ₂ without processing it. Corrosion problems increase, but injection treatments can control them. For injection systems, existing lines for water can be used, but new lines for CO ₂ should be installed. Bare steel tubing may be used for long WAG cycles. Economical treatments exist for asphaltene and parrafin problems.

FIELD RESULTS

Little Creek Field, Mississippi. Little Creek Field had undergone CO ₂ flooding operations beginning in 1973. When purchased by JP Oil in 1996, production was more than 900 bopd, but high costs made operations uneconomic. JP reduced electrical costs by 25%, lowered CO ₂ costs, and trimmed taxes and labor. Overall, operating costs were reduced 16% (from $11.28 to $9.47 per barrel) and production increased 17% in the first year alone.

Postle Field, Oklahoma. Mobil began CO ₂ flooding in November 1995. As of mid-1998, Mobil was injecting 90plus million cubic feet per day (mmcfd) of CO ₂ , with expansions planned. Production increased from 1,900 to 6,000 bopd. Mobil’s success stimulated interest in the Kansas’s Morrow reservoirs. Other reservoirs, such as the Lansing-Kansas City and Arbuckle, also may be amenable. An existing CO ₂ pipeline is within 50 to 100 miles of several fields.

CO ₂ Initiative in Kansas
The Tertiary Oil Recovery Project (TORP) in Kansas and other industry programs are implementing a CO ₂ initiative. Consultants are evaluating reservoir characteristics, the condition of wells, and the MMP of oil in fields to assess potential recovery. With the investment required to bring CO ₂ into Kansas, pilot tests first must be conducted, and various consortia involving industry and state/federal governments are seen as a likely solution.

CONNECTIONS:

Don Green and Paul Willhite, Co-directors
Tertiary Oil Recovery Project, 4008 Learned Hall
University of Kansas, Lawrence, KS 66045-2936
Phone 785-864-3001, Fax 785-864-49676, E-mail green@cpe.engr.ukans.edu, E-mail willhite@cpe.engr.ukans.edu

Shell CO ₂ Flood Scoping
Charles Fox, Shell CO ₂ Co.
200 N. Dairy Ashford, Houston, TX 77079
Phone 281-544-3840, Fax 281-544-3841, E-mail cefox@shellus.com, or shellco2@shellus.com

CO ₂ Prophet
Crisa West, University of Texas, Permian Basin
Center for Energy and Economic Diversification
1400 N. FM 1788, Midland, TX 79706
Phone 915-522-2449, Fax 915-552-2433

William Martin III, JP Oil Co. Inc.
1604 N. Pinhook, Lafayette, LA 70508
Phone 318-234-1170, Fax 318-234-9891, E-mail martinwe@jpoil.com

F. David Martin, President
Strategic Technology Resources LLC
8620 Beverly Hills Ave. NE, Albuquerque, NM 87122
Phone 505-822-0937, Fax 505-822-0942, E-mail martin@newmexico.com

Reid Gregg, Petroleum Recovery Research Center
801 Leroy Pl., Socorro, NM 87801 
Phone 505-835-5685, Fax 505-835-5210, E-mail gregg@prrc.nmt.edu

William A. Flanders, Transpetco Engineering
625 Market St., Suite 100, Shreveport, LA 71101 
Phone 318-222-6212, Fax 318-222-1640

For information on PTTC’s regional resource centers and activities contact:

Eastern Gulf: Ernest A. Mancini, Professor of Geology,
University of Alabama
Box 870338, 202 Bevill Bldg., Tuscaloosa, AL 35487
Phone 205-348-4319, Fax 205-348-0818, E-mail emancini@wgs.geo.ua.edu

North Midcontinent: Rodney Reynolds, Project Manager,
Energy Research Center, and Petroleum Engineer,
Tertiary Oil Recovery Project, University of Kansas,
1930 Constant Ave., Lawrence, KS 66047
Phone 785-864-7398, Fax 785-864-7399, E-mail reynolds@cpe.engr.ukans.edu

Southwest: Robert Lee, Director,
Petroleum Recovery Research Center New Mexico Tech,
801 Leroy Pl., Socorro, NM 87801
Phone 505-835-5685, Fax 505-835-5210, E-mail lee@prrc.nmt.edu

Disclaimer: No specific application of products or services is endorsed by PTTC. Reasonable steps are taken to ensure the reliability of sources for information that PTTC disseminates; individuals and institutions are solely responsible for the consequences of its use.

The not-for-profit Petroleum Technology Transfer Council is funded primarily by the US Department of Energy’s Office of Fossil Energy, with additional funding from universities, state geological surveys, several state governments, and industry donations.

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Toll-free 1-888-THE-PTTC; Fax 713-688-0935; E-mail hq@pttc.org; web www.pttc.org