Case History of the University Block 9 (Wolfcamp) FieldA Gas-Water Injection Secondary Recovery Project
Authors: Cone Clifford 
Published: December 2007

On the whole, the Wolfcamp has responded well to this system of alternating gas injection and water injection - better than it would have responded to natural depletion or waterflooding. Operations are expected to improve substantially with injection rates scheduled on the basis of simulated reservoir material balancing rather than stock-tank material balancing.

Introduction
The University Block 9 (Wolfcamp) reservoir, located 8 miles south of Andrews, Tex., was discovered in 1953. The limestone, domal feature at a depth of 8,400 to 8,500 ft was discovered as a result of seismic work in the area. A pressure-maintenance, miscible-displacement, peripherally patterned project was begun shortly after unitization in 1960, and the alternate gas-water injection phase of operations has been continued to the present time. Thus far, the project has yielded more than 2 1/4 times the estimated primary reserves and has been a very successful and profitable operation. The results of the field performance should be beneficial to others considering similar secondary recovery projects.

Geological and Reservoir Descriptions
The Wolfcamp reservoir of the University Block 9 field (Fig. 1) was discovered by the Atlantic Refining Co.'s No. 1-A University "9AGH". Located on the eastern edge of the Central Basin Platform, the domal, limestone feature (Fig. 2) appears to have been deposited as a combination of draping and carbonate buildup over the underlying Pennsylvanian shelf carbonates. Of the three Wolfcamp zones, the lowest zone is the most productive. It consists of 4 to 45 ft of organic limestone with intercrystalline-to-vugular porosity and has an oil-water contact at approximately 5,370 ft subsea. The nonproductive middle zone is composed of 10 to 40 ft of shaly limestone with irregularly deposited shale stringers. The productive upper zone consists of approximately 10 ft of limestone with intercrystalline porosity. In 1957–58 an engineering committee made a study of the reservoir for secondary recovery purposes. They made material balance and volumetric calculations to determine the original reserves of oil and volume of the reservoir. Statistical analyses of cores, capillary pressure data, reservoir fluid, and well logs were used pressure data, reservoir fluid, and well logs were used to determine the basic reservoir data applied in the material balance and volumetric calculations. Respective material balance and volumetric calculations were 90.32 million and 90.70 million reservoir bbl for reservoir volume, and 50.8 million and 51.0 million STB for original oil in place.
Primary Performance Primary Performance The reservoir performance from the initial pressure of 3,500 psig to the saturation pressure of 1,775 psig indicated a performance typical of fluid-expansion drive. Below the bubble-point pressure the reservoir performed by solution-gas drive with no evidence of performed by solution-gas drive with no evidence of water encroachment. The reservoir performance with respect to water production, GOR, bottom-hole pressure, and oil production is shown in Figs. 3 and 4. pressure, and oil production is shown in Figs. 3 and 4.
JPT
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