Forty-Seven Years' Gas Injection in a Preferentially Oil-Wet, Low-Dip Reservoir
- C.R.K. Murty (Bahrain Natl. Oil Co.) | N. Al-Saleh (Behrain Natl. Oil Co.) | B.A. Dakessian (Chevron Overseas Petroleum Inc.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- March 1987
- Document Type
- Journal Paper
- 363 - 368
- 1987. Society of Petroleum Engineers
- 4.1.5 Processing Equipment, 1.2.3 Rock properties, 4.6 Natural Gas, 5.5 Reservoir Simulation, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 5.7.2 Recovery Factors, 5.6.1 Open hole/cased hole log analysis, 5.1.2 Faults and Fracture Characterisation, 5.2.1 Phase Behavior and PVT Measurements, 5.4.2 Gas Injection Methods, 2.2.2 Perforating, 3 Production and Well Operations, 4.1.2 Separation and Treating, 5.2 Reservoir Fluid Dynamics
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Summary. Crestal gas injection has been used since 1938 for pressure maintenance in a preferentially oil-wet reservoir in the Bahrain field. This paper updates the gas injection history through July 1984, presents the benefits of gas injection, and discusses the finding that recovery in the gas-contacted area was greater than in water-invaded blocks.
This is an update of two previous papers by Cotter and Shehabi.
The Mauddud is the major oil-producing reservoir of the Bahrain field situated in an anticlinal feature of the Middle Cretaceous period. This is a highly undersaturated, low-dip, and preferentially oil-wet reservoir. Crestal gas injection has been used in the central block of the reservoir since 1938 for pressure maintenance, making it the first improved recovery project in the Arabian Gulf region. Numerous low-relief faults place the prolific Mauddud in juxtaposition with overlying, and underlying reservoirs. This provides additional production outlets for fluids. Initially, 0.2 PV of rich Arab-zone gas were injected from 1938 to 1973; this has been followed by lean Khuff gas. As of July 1984, 77% of the productive central block had been contacted by gas: the volumetric contact is 32%. Recovery in the contacted block is by a combination of gas drive and gravity drainage, whereas in the noncontacted north and south blocks, it is by water drive. Performance to date indicates much higher recovery in the Performance to date indicates much higher recovery in the gas-contacted central block than in the water-invaded north and south blocks. Reservoir analysis, including simulation, indicated improved oil recovery with higher gas injection. Accordingly, gas injection rates were increased by 40%, and more recently, an aggressive workover program was initiated to lower perforations and reduce free gas production. This has resulted in a rise in reservoir pressure, thus production. This has resulted in a rise in reservoir pressure, thus reversing peripheral water encroachment and maintaining oil production with no decline since mid-1983. As a result of the attractive response to gas injection in the central block. gas injection will be initiated soon in both the north and south blocks. This paper, while reviewing the gas injection history, presents the benefits of gas injection and describes the methods used to calculate the recovery factor in both gas-contacted and waterinvaded areas.
Lithologically, the reservoir rock is moderately soft to hard, fine-to-medium grained, fossiliferous. detrital, clean limestone. Much of the original rock has been altered by recrystallization and leaching. Leaching resulted in the creation of vugs and interconnecting channels. This makes the Mauddud formation an excellent reservoir with high porosity and uniform permeability. The reservoir has a porosity and uniform permeability. The reservoir has a fairly uniform thickness, averaging 110 ft [33.53 m], all of which is considered net pay. This reservoir is a highly faulted. elongated anticline with dips as low as 5 degrees [0.09 rad]. There are numerous faults in the crestal area with fewer on the flanks and on the north and south plunges. The displacement of the majority of the faults is less than 30 ft [9.14 m]. Because the thickness of the reservoir is 110 ft [33.53 m], it is in juxtaposition with other zones across the faults and possibly in communication with them. Fig. 1 is a structural possibly in communication with them. Fig. 1 is a structural cross section drawn cast/west across the reservoir. The two major faults with displacement above 50 ft [15.24m ] separate the central block from the north and south blocks. These faults, plus the extended distance from the crestal injection location. prevent the expansion of the gas cap into these remote areas.
Rock Properties. Rock and fluid properties of the reservoir were reported earlier by Cotter. Essentially, he reported the average porosity and permeability as 25% and 40 to 60 md, respectively. There are no impermeable intervals to affect vertical permeability. Shehabi concluded, from laboratory investigation of preserved cores, that the reservoir is preferentially oil-wet. Because of the very rare occurrence of an oil-wet system worldwide, serious doubts are expressed and deliberated whenever such data are presented. To reconfirm the earlier observations, new laboratory studies were conducted recently for wettability determination. This time the studies were made on "fresh" (not cleaned before testing) core samples by Aniott's method. The results indicate a wettability index to oil of 0.60 and to water of 0.002.
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