Effective Displacement of Oil by Gas Injection in a Preferentially Oil-Wet, Low-Dip Reservoir
- Jaffar A.N. Shehabi (The Bahrain National Oil Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- December 1979
- Document Type
- Journal Paper
- 1,605 - 1,613
- 1979. Society of Petroleum Engineers
- 5.2 Reservoir Fluid Dynamics, 4.1.5 Processing Equipment, 5.3.4 Reduction of Residual Oil Saturation, 5.6.1 Open hole/cased hole log analysis, 5.1 Reservoir Characterisation, 5.4.2 Gas Injection Methods, 5.7.2 Recovery Factors, 5.1.2 Faults and Fracture Characterisation, 4.1.2 Separation and Treating, 4.1.9 Tanks and storage systems, 5.2.1 Phase Behavior and PVT Measurements
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Gas injection as a means of pressure maintenance has been employed in the Bahrain field Second Pay Limestone B reservoir for the last 39 years. This paper describes aspects of the gas injection program and the method used to paper describes aspects of the gas injection program and the method used to calculate recovery of oil by gas, which has been found to be much greater than that by water drive.
Gas injection as a means of maintaining pressure and improving oil recovery has been employed in the Bahrain field Second Pay Limestone B reservoir for the last 39 years. This reservoir is oil-wet. Maintaining reservoir pressure was the primary objective in the beginning. The pressure response was almost immediate and probably conformed very closely to a simple material balance, because all producing zones on the highly faulted Bahrain structure were still close to virgin conditions. Early gas breakthrough became a matter of concern with respect to total field productivity and ultimate recovery. However, wells in the gas area were kept on production, at an optimum rate governed by tubing submergence. It gradually was realized that even with early breakthrough, a satisfactory oil recovery factor was being obtained. Attention then focused on determining actual recovery and explaining the mechanism involved. The most recent reservoir study showed a 50% recovery factor in the gas-invaded volume, as compared to 20 to 25% in the water-invaded volume. it also was found that because of fluid transfer to other zones, the required injection rate for the Limestone B is 70,000 Mcf/D (1.98 x 106 m3/d) instead of the 40,000 Mcf/D (1.13 x 106 m3/d) calculated for the Limestone B alone. This paper describes some pertinent aspects of the reservoir, the gas injection program, and the methods used to calculate the recovery factor.
The Bahrain field structure is a highly faulted, elongated anticline (Fig. 1). Structural dips in the oil-producing horizons are in the order of 5 deg. The Bahrain zones, of middle Cretaceous age, are the most important oil-producing group found in this field. They are divided into eight separate zones, with zonal separation varying from 7 to 50 ft (2.13 to 15.24 m). Three types of lithology are present: limestone, siltstone, and sandstone. At the crest of the structure, the gross productive interval was 525 ft (160 m) and original net oil pay thickness was 325 ft (99 m). The most important zone within this group, and the subject of this paper, is the Second Pay Limestone B. The reservoir rock is a soft, porous, sugary limestone with limited fractures and vugs. Gross thickness varies slightly from 102 to 116 ft (31 to 35.4 m), all of which is considered net pay. Average porosity and permeability are 25% and 62.8 md, respectively. There are no impermeable streaks to affect vertical permeability. The middle 50 ft (15.24 m) has the highest porosity and permeability. The basal 30 to 40 ft (9.14 to 12.19 m) is slightly different in character and appears to have a lower specific productivity index.
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