By Mohan Kelkar, The University of Tulsa

The Glenn Pool Field, a field which has been producing for over 90 years and which has been subjected to water flooding since 1956, was selected for improving its production through various technologies under DOE's Class I Program. The project was divided into two budget periods. Overall, the technologies that proved to be effective include: integrated approach to describe reservoirs, geological description using discrete genetic intervals (DGIs), use of productivity index to grade various parts of the reservoir, geostatistics, and flow simulation. The technologies which proved to be only marginally effective or ineffective include: use of microresistivity logs for detailed geological description, cross borehole tomography, and drilling of deviated holes using a surface steered drilling assembly.

BACKGROUND

The Glenn Pool Field is located in portions of Tulsa and Creek Counties of Oklahoma. The field was discovered in 1905, and it is estimated as having produced 330 million barrels of oil (MMBO) from the Middle Pennsylvanian (Desmoinesian) age Bartlesville Sandstone. Glenn Pool Field, like other fields developed in the Bartlesville Sandstone, is located on the Northeastern Oklahoma Platform. Figure 1 shows the area of study for this project. The Self Unit indicated in the figure was the subject of first budget period investigation, whereas the gray area surrounding the Self Unit was the subject of the second budget period.

Figure 1 Location of Glenn Pool Field.

BUDGET PERIOD I

In the first budget period, our effort concentrated on the Self Unit, a 160-acre unit, located in the southeast portion of the Glenn Pool Field (see Figure 1). This unit, with original oil in place of 13 MMBO, has so far produced about 21 percent of OOIP. We applied several new technologies to improve the reservoir description of this unit. These technologies included integration of geological, geophysical, and engineering data, geological description using DGIs, modern logs, cross borehole tomography, geostatistics, and reservoir flow simulation.

Very limited core and log data were available from the unit. To compliment the existing information, a new vertical well was drilled, and additional core data as well as modern suite of logs, including micro borehole imaging, were acquired on a new well. Using the newly drilled well as a source well, three cross borehole seismic surveys were conducted. With the help of updated geological models as well as cross borehole seismic data, a detailed reservoir description was constructed and, using a commercial flow simulator, various scenarios were investigated to improve the performance of the field. The cross borehole data did not add significant new information. A combination of recompletion and stimulation of most wells followed by increasing the water injection rate in the field was observed to be the most optimal change to improve the flow performance of the Self Unit.

The proposed reservoir management plan was implemented, and the unit performance was monitored for more than three years. At the base level, the Self Unit was producing between 15 to 17 bbl/day. The initial increase in the incremental oil production was predicted to be in the range of 15 to 32 bbl/day (see Figure 2). The cases in Figure 2 represent the use of different relative permeability curves. The same figure also shows the actual production. As can be seen, the actual production fell within the predicted uncertainties. In short, we were able to correctly predict the performance of the reservoir. Although in terms of actual production, this increase is not much, note that it still represents about a 150 percent increase in the production. Further, the field is more than 90 years old and has been subjected to many technologies in the past. If we can cost-effectively increase production from such a mature field, we should be able to do better in other, relatively younger fields. The economic evaluation indicated finding cost of oil is in the range of $4.80 to $6.00 per barrel. This cost can be reduced substantially (to about $2 to $3 per barrel) if we use only the cost-effective technologies and eliminate the use of other technologies.

Figure 2 Incremental production rate for the Self-Unit for various cases.

BUDGET PERIOD II

In Budget Period II, we extended our efforts to other parts of the Glenn Pool Field (see Figure 1). The main idea in the second budget period is to apply conventional technology to develop a reservoir management plan. Unlike the first budget period, where modern technologies such as micro-resistivity logs and cross borehole tomography data were collected, in the second budget period, the analysis relied on more conventional data. Any use of modern technology was restricted to the analysis and interpretation of the data.

In addition to the existing logs and core data, six new gamma-ray logs were acquired to compliment the existing data. There was a suspicion that the upper structure may have developed a secondary gas cap. To check this, three cased-hole neutron logs (TDT) were conducted. No evidence of secondary gas cap was observed.

Since it was difficult to study all parts of the reservoir in great detail, we graded the reservoir based on a method of potential index mapping. This mapping involves evaluating various areas in the reservoir based on the permeability, thickness, porosity, and saturation as well as prior access to that area by already existing wells. A reservoir with high conductivity and high storativity is given a high productivity index. Depending on whether the area of interest is drained by already existing wells, a potential index is calculated. A region with a high potential index is investigated further, whereas a region with a low potential index was eliminated from further consideration. In addition to potential index mapping, we also examined the primary and secondary recovery production from various units. Based on the grading of various parts of the reservoir, we high-graded certain areas of the field.

We investigated various scenarios for improving the performance of the high-graded areas. For one area, we observed that drilling of a deviated producing well will result in the most improvement in the production. For other areas, we observed that recompletion and stimulation of upper intervals will result in the most improvement in the production.

Based on our evaluation, we decided to drill a deviated well, which would be completed in the upper and middle part of the Glenn sand. The deviated producing well will be supported by three injectors: one in the north and two in the south. To achieve the drilling in a cost-effective manner, we employed a relatively new technology of surface steered drilling, which is much cheaper than conventional deviated-hole drilling. Unfortunately, drilling of a deviated hole proved to be much more challenging than anticipated. We lost the drilling assembly twice. During the second time, we could not fish it, and the hole had to be abandoned. As a result, our reservoir management plan during the second budget period could not be validated. Because of budget constraints, another attempt at drilling a deviated hole could not be made. Hopefully, private owners will take the initiative and, with favorable oil prices, drill deviated wells in the same field to validate the concept.

SUMMARY

Looking back at the project, we can conclude that, although the project ended on a sour note, we were able to demonstrate that cost-effective technologies can be used to improve the performance of marginal oil fields. We evaluated various technologies and determined their cost-effectiveness for future use. We also demonstrated the usefulness in describing the reservoir using integrated information so that we will be able to better predict the future performance of the reservoir. The success is further satisfying by the fact that Glenn Pool Field is 90 years old. If we can demonstrate that the field can be rejuvenated with cost-effective technologies, there are many younger fields where the technologies would be much more useful.

REFERENCES

1. Kuykendall, M. D., and Matson, T. E.: "Glenn Pool Oil Field, Northeast Oklahoma Platform," American Association of Petroleum Geology - Treatise of Petroleum Geology Atlas of Oil and Gas Fields: Stratigraphic Traps III, pp. 155-188 (1992).
2. Kelkar, M., Kerr, D. and Liner, C.: "Integrated Approach Towards the Application of Horizontal Wells to Improve Waterflooding Performance", Final DOE Report under Contract No. DE-FC22-93BC14951 (September, 1999).

The Class Act Winter 2000 Edition Volume 6/1