A Case History Comparison of Predicted and Actual Performance of a Reservoir Producing Volatile Crude Oil
- J.C. Cordell | C.K. Ebert
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- November 1965
- Document Type
- Journal Paper
- 1,291 - 1,293
- 1965. Society of Petroleum Engineers
- 1 in the last 30 days
- 513 since 2007
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A case history of the depletion performance of a reservoir producing volatile crude oil is presented and compared with prior predictions of performance. The predicted performance was published by Jacoby and Berry in 1957. The history concerns a field in North Louisiana discovered in late 1953, producing from the Smackover lime at approximately 10,000 ft. The volatile-oil reservoir covers 1,600 acres and is developed with 11 wells. Cumulative production to Jan. 1, 1965, is 2,317,000 bbl of oil and 20,375 MMcf of gas. The reservoir pressure has decreased from an original value of 5,070 to 700 psia. The reservoir is now 90 per cent depleted. The principal factors of comparison are recovery and GOR. The volatile-oil material balance prediction is within 10 per cent of actual performance, while the recovery predicted by the conventional material balance method is only 37 per cent of actual recovery. The greater accuracy of the volatile-oil material balance is due to the consideration of oil recovered from the gas phase. Performance of a volatile-oil reservoir can be predicted with a high degree of accuracy using the volatile-oil method.
Jacoby and Berry described a method to improve performance predictions of a volatile-oil reservoir and specifically discussed a field in North Louisiana which produces from the Smackover lime. The purpose of our paper is to compare the actual performance of this field with performance predicted using the volatile-oil method described by Jacoby and Berry and with the conventional Schilthuis-type material balance prediction.
The producing reservoir under study is an anticlinal structure lying north of an east-west trending fault. The fault forms the south limit of the field. The remaining limits of the reservoir are controlled by a water-oil contact at 10,267 ft and by pinch-out of porosity and permeability development. The 10,000-ft reservoir is of the Mesozoic Era, Upper Jurassic system and is commonly called the Smackover lime. The matrix material of the Smackover lime is a hard, dense limestone with porosity and permeability development resulting from oolitic deposition. The formation grades into a dense limestone lacking porosity and permeability where oolitic deposition is scarce. All wells in the field were cored. Porosities in the individual wells varied from 9.8 to 20 per cent (average 13.6 per cent) with permeabilities varying from 20 to 1,019 md (average 174 md). Net pay was based on a minimum porosity of 5 per cent and a minimum permeability of 1 md as indicated by core analysis data. Average water saturation based on capillary pressure tests is 28.29 per cent. Fig. 1 is an isopach of the net oil pay, which in the individual well is composed of several porous and permeable lime stringers. Pressure and production data indicate that the individual stringers in the 11 wells within the zero line of the isopach were in communication either through wellbores or vertical fractures. The seven wells to the north and west of the common reservoir shown are also completed in the Smackover lime; however, performance history indicates they are not in communication with the main 11-well reservoir. The 11-well reservoir will hereafter be designated the Main Reservoir.
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