Engineering Studies of G-1, G-2, and G-3 Reservoirs, Meren Field, Nigeria
- G.C. Thakur (Gulf Oil Exploration and Production Co.) | R.B. Haulenbeek (Gulf Oil Exploration and Production Co.) | A. Jain (Gulf Oil Exploration and Production Co.) | W.P. Koza (Gulf Oil Exploration and Production Co.) | S.D. Jurak (Gulf Oil Exploration and Production Co.) | S.W. Poston (Gulf Oil Co. (Nigeria) Ltd.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- April 1982
- Document Type
- Journal Paper
- 721 - 732
- 1982. Society of Petroleum Engineers
- 1.6 Drilling Operations, 4.1.5 Processing Equipment, 5.5.2 Core Analysis, 1.2.3 Rock properties, 5.5.8 History Matching, 3 Production and Well Operations, 5.1.2 Faults and Fracture Characterisation, 4.1.2 Separation and Treating, 4.6 Natural Gas, 5.1 Reservoir Characterisation, 4.2 Pipelines, Flowlines and Risers, 5.4.2 Gas Injection Methods, 5.2.1 Phase Behavior and PVT Measurements, 6.5.2 Water use, produced water discharge and disposal, 5.5 Reservoir Simulation, 2.4.3 Sand/Solids Control, 5.6.4 Drillstem/Well Testing, 1.6.9 Coring, Fishing, 5.2 Reservoir Fluid Dynamics, 2.2.2 Perforating
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This paper describes an engineering study of two large reservoirs in the G sands of Meren field, offshore Nigeria. The purpose of this study was to investigate various operating schemes for optimizing oil recovery from each of these gravity-segregated reservoirs. Geologic evaluation, material-balance calculations, and three-phase, two-dimensional (2D) (areal and cross-sectional) reservoir simulation models were used.
Meren field is on the western edge of the Niger River delta about 110 miles southeast of Lagos (Fig. 1). It lies about 8 miles offshore in approximately 40 ft of water. Production has been from Sands E, G, H, J, and K; however, of the 362 MMSTB of oil and 239 Bscf of gas produced from Oct. 1968 through Jan. 1981, approximately half has been from Sand G.
The work presented here is an engineering study of two major producing intervals in Sand G. Specifically, the fault blocks referred to as A and C (Fig. 2) are believed to act as a single producing unit containing both Sands G-1 and G-2. Similarly, the fault block referred to as B is believed to act as a single producing reservoir containing both Sands G-2 and G-3.
Production from the G-1/G-2 reservoir began in Nov. 1968, and by July 1, 1979, about 81 MMSTB of oil and more than 55 Bscf of gas were produced. This production, with represents about 29% recovery of the original 281 MMSTB of oil in place, has caused the average reservoir pressure to decline from 2,660 to 1,750 psig. During this time, 23 completions have produced through 17 wells.
Production from the G-2/G-3 reservoir began in March 1970, and by April 1, 1979, about 50 MMSTB of oil and about 28 Bscf of gas were produced. This production, which represents about 18% recovery of the original 276 MMSTB of oil in place, has caused the average reservoir pressure to decline from 2,560 to 2,033 psig. Thirteen completions have produced through 12 wells.
The drive mechanism for both reservoirs is primarily solution gas with gravity segregation, although a large aquifer contributes to pressure support. The reservoirs are characterized as massive, clean sands with high porosity (averaging between 27 and 32%) and high horizontal and vertical permeabilities (averaging nearly 1,500 and 750 md, respectively).
The purpose of this study has been to evaluate different pressure-maintenance plans in the reservoirs. Work proceeded in several stages. First, the reservoirs were characterized through extensive computer-processed log evaluation, routine and special core analyses on the recently completed Meren Well 57, and a complete review and update of reservoir geology and the associated structure and isopach maps. Second, the McEwen1 material-balance equation was used to obtain the reservoir characteristics and aquifer properties, which in turn were used to provide a preliminary estimate of water-injection requirements and an estimate of ultimate recovery with a pressure-maintenance program. Finally, the reservoirs were simulated using a three-phase, black oil model. A cross-sectional simulation was used to verify the applicability of an areal representation of the reservoirs. A two-dimensional areal simulation study of each reservoir then was conducted to match past performance history and predict reservoir performance under a variety of operating schemes.
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