G-2 and G-3 Reservoirs, Delta South Field, Nigeria: Part 2 - Simulation of Water Injection
- G.C. Thakur (Gulf Research and Development Co.) | P.L. Stanat (J.S. Nole and Assocs. Inc.) | M. Aruna (Nigerian Natl. Petroleum Corp.) | S. Poston (Texas A&M U.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- January 1982
- Document Type
- Journal Paper
- 148 - 158
- 1982. Society of Petroleum Engineers
- 4.1.5 Processing Equipment, 5.5 Reservoir Simulation, 5.6.4 Drillstem/Well Testing, 4.1.2 Separation and Treating, 4.3.4 Scale, 2.4.3 Sand/Solids Control, 5.2.1 Phase Behavior and PVT Measurements, 5.2 Reservoir Fluid Dynamics, 4.6 Natural Gas, 2.2.2 Perforating, 5.1.2 Faults and Fracture Characterisation, 3.1.6 Gas Lift, 6.5.2 Water use, produced water discharge and disposal, 2 Well Completion, 4.2 Pipelines, Flowlines and Risers, 5.5.8 History Matching, 5.1 Reservoir Characterisation
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This paper describes a two-dimensional, three-phase, black-oil simulation of the G-2 and G-3 reservoirs in the Delta South field offshore Nigeria. The purpose of these studies was to investigate, from an engineering standpoint, various operating schemes for optimizing the oil recovery from each of these highly gravity-segregated reservoirs.
The G-2 and G-3 sands are two major reservoirs in the Delta South field. The field is offshore Nigeria in approximately 10 to 16 ft of water (Fig. 1). Production from these reservoirs began in March 1968. By the end of March 1978, about 61.3 MMSTB of oil and more than 64 Bscf of gas were produced from the G-2 reservoir, and about 92 MMSTB of oil and more than 75 Bscf of gas were produced from the G-3 reservoir. These productions represent about 2 1% of the original oil in place (OOIP) for G-2 and 29% of OOIP for G-3. During this period, the average reservoir pressures for G-2 and G-3 declined from 3,936 to 2,665 psig and 3,829 to 2,343 psig, respectively.
The G-2 reservoir is at an average depth of 8,920 ft subsea. It is underlain by the G-3 reservoir, but the two are separated by a shale barrier. The two reservoirs are similar in structure and in rock and fluid properties.
The drive mechanism for these reservoirs is primarily gravity segregation. These reservoirs are characterized as massive, clean sands with high porosity (about 28% for G-2 and 26.5% for G-3) and high horizontal and vertical permeabilities (kh=2,000 md and kv=1,000 md).
This paper presents the results of the current G-2 and G-3 reservoir studies, which are extensions of previous work. First, a history match of 10 years of production performance was made. Later, several prediction cases were run under a variety of operating conditions. This study was undertaken to update the previous match, including the past performance data through March 1978. We believe that, by including more history match data, we have obtained a better reservoir characterization. Although about 20 prediction cases were run for each study, only four pertinent cases for G-2 and five for G-3 are included.
Gulf's two-dimensional, black-oil model in an areal mode has been used for this study. The use of this areal model is believed sufficient in describing the reservoir and fluid flow behavior and is justified since the fluids will be segregated because of the high k v/kh ratio (about 0.5:1 were kh=2,000 md). In this cases, gravity/capillary equilibrium exists throughout the thickness. However, there are some limitations in using an areal model for this study: (1) the well coning effects are represented by well pseudorelative permeability curves and not with grid blocks in the vertical direction, (2) the well completions are represented by modifying the well relative permeability curves, and (3) any well coning effect matched using pseudorelative permeability curves may not be strictly valid for future predictions. These limitations, however, do not seem to be very important for the G-2 and G-3 reservoirs.
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