By William Culham, REGA, Inc; Douglas M. Lorenz, Texaco, E&P (formerly of REGA); and Thomas C. Chidsey, Jr., Utah Geological Survey

Phase I for this DOE Class II project, entitled "Increased Oil Production Utilizing Secondary/ Tertiary Recovery Techniques on Small Reservoirs in the Paradox Basin, Utah," was designed to characterize five shallow-shelf carbonate reservoirs in the Pennsylvanian (Desmoinesian) Paradox Formation and choose the best candidate for a pilot demonstration for either a waterflood or carbon dioxide (CO₂) flood project. Phase I also included reservoir simulations, economic assessments, and recommendations for Phase II, which will be a pilot CO₂-flood field demonstration. Phase I was completed August 31, 1998. Phase II began on September 1, 1998, and will run through August 31, 2002. The Phase II field demonstration, monitoring of field performance, and associated validation activities will take place in the Paradox Basin of southeastern Utah within the Navajo Nation.

Figure 1 Location of project fields (dark shaded areas with names in bold type) in southwestern Paradox Basin in the Navajo Nation, San Juan County, Utah.

RESERVE AND RECOVERY DETERMINATIONS FOR PROJECT FIELDS
Primary recovery and original oil in place (OOIP - Table 1) were determined for the project fields from volumetric reserve calculations, material balance calculations, and decline curve extrapolations, as well as refined geologic characterization. These volumetric calculations were made by evaluating well logs and reservoir areal extent (as defined by seismic reflection data), coupled with reservoir geometry. Material balance and decline curve calculations utilized the field's production and pressure histories. Knowing the OOIP and the primary recovery, the amount of oil left behind was calculated. Lastly, utilizing the results from the simulation studies of Anasazi and Runway Fields, sweep efficiencies for CO₂ flooding and the ultimate enhanced recovery were estimated for all project fields (Table 1). Using the average predicted oil recovery of 71.8 percent (percent recovery of oil remaining in place after primary recovery) for the Runway and Anasazi reservoirs, the projected addition to reserves if CO₂ is also applied to project fields is over 8.2 million stock tank barrels (STB) of oil.

ECONOMIC ASSESSMENT OF CO₂ FLOOD, ANASAZI FIELD
Phase II will implement and complete a CO₂ flood in the Anasazi reservoir. Using reservoir-simulation-based performance predictions and current CO₂-flood implementation costs, detailed economic assessments were conducted for a number of different CO₂-flood options. These sets of studies indicated that:

1. A CO₂ flood of the Anasazi reservoir has robust economics. With DOE participation, the project would have a ROR of 62 percent, a payout of 35 months, a PI of 15 to 1, and a discounted (10 percent) NPV in excess of $12.5 million. Even without DOE participation, the economics remain robust with a ROR of 48 percent, a payout of 39 months, a PI of 8 to 1, and a discounted NPV of over $11.0 million. The capital requirements would be $3.146 million.
2. Leasing the compressor on a five-year contract basis is better economically than purchasing the compressor. Leasing improves the NPV by approximately $1 million.
3. The benefit from separating CO₂ from the produced gas so the hydrocarbons can be used for fuel and sales is offset by the large capital investment required for a CO₂ membrane separation facility. Thus, re-injection of all produced gas without processing is economically more attractive than implementing a CO₂ flood with gas processing.
4. The difference between minimum and maximum cost options for installation of flow/injection lines and the CO₂ supply is approximately $1.0 million; however, the economics are positive for both options. With DOE cost sharing, the ROR is 56 percent with a PI of 11.5 to 1.
5. The ROR and PI are not significantly different for a process using blowdown after six years of CO₂ injection versus the continuous CO₂ injection case. However, the NPV is substantially less with blowdown (approximately $1.4 million). The lower NPV is a result of lower oil recovery for the blowdown case (800,000 STB less than the continuous injection case).

Production data and injection gas requirements, including CO₂ make-up purchases, were used to assess the financial merits of a CO₂ flood with a total injection rate of 8 million cubic feet of gas per day commencing January 1, 2000. The economic assessment, using two compressor options, was conducted assuming the following conditions: (1) leased compressor (option 1, $19,500; option 2, $23,500 [same compressor with a different engine]), (2) CO₂ supply line construction using the minimum costs option ($825,000), (3) no gas processing, and (4) cost sharing by DOE. This assessment demonstrates that CO₂ flooding provides both an adequate flood response with either of the compressor options, an acceptable economic ROR of 32 percent, and a payout of 36 months. A discounted (10 percent) NPV of $5.9 million could be realized by implementing a CO₂ flood under the proposed conditions.

If the CO₂ flood performs as predicted, it is a financially beneficial process for increasing the reserves of the Anasazi reservoir; however, the ROR and NPV are very sensitive to oil prices (Figures 2 and 3). Therefore, the economic assumption should be recalculated before installation of injection facilities.

1. A CO₂-injection project should be implemented in the Anasazi reservoir.
2. A field injectivity test using CO₂ should be conducted on the Anasazi No. 6H-1 well, a project well in the western part of the field, to establish long-term injection rate data before committing to further Phase II work.
3. After the CO₂ source is obtained for Anasazi Field, the economic assumption should be recalculated to see if the project is still economically feasible at current prices.
4. The main injection compressor should be leased rather than purchased to provide the most operating flexibility and least financial risk.
5. Produced gas processing is not required for a single-field CO₂-flood implementation case. It is not required from a reservoir processing standpoint, nor is it justified economically.
6. Horizontal well injectivity should be predicted from the appropriate well-test models after calibration with vertical well-test data.

CONCLUSIONS
Phase I of the project showed that a CO₂ flood was technically superior to a waterflood and was economically feasible. For Anasazi Field, an optimized CO₂ flood is predicted to recover 4.21 million STB of oil. This represents an increase of 1.65 million STB of oil over predicted primary depletion recovery by January 1, 2012. The projected 4.21 million STB of oil production represents about 90 percent of the OOIP in the mound complex and 37 percent of the OOIP of the total system modeled.

The field demonstration will include: conducting a CO₂ injection test(s), obtaining a CO₂ source and fuel gas for the compressor, recalculating project economics, drilling a development well(s) (vertically or horizontally), purchasing and installing injection facilities, monitoring field performance, and validation and evaluation of the techniques. Such a demonstration should prove (or disprove) CO₂-flood viability, and thus help determine whether the technique can be applied to numerous small carbonate-buildup reservoirs in the Paradox Basin and similar reservoirs in other basins throughout the U.S.

The Class Act Winter 2000 Edition Volume 6/1