Simulation of Water Injection in a Barrier-Bar-Type, Oil-Rim Reservoir in Nigeria

Abstract

Weber, K.J., SPE-AIME, Koninklijke/Shell Exploratie en Produktie Laboratorium Klootwijk, P.H., SPE-AIME, Shell Internationale Petroleum Mij. B.V. Konieczek, J., Shell Internationale Petroleum Mij. B.V. van der Vlugt, W.R., Shell Internationale Petroleum Mij. B.V. A three-dimensional model study was conducted on a typical Niger Delta reservoir in a low-relief, rollover structure associated with growth faulting. Detailed description of sedimentological characteristics and subsequent reservoir subdivision were essential for successful well-by-well history matching, which accounted for cusping and coning of gas and water. Predictions will almost double recovery. Predictions will almost double recovery. Introduction The Niger Delta is a large arcuate delta of a highly destructive, wave-dominated type and has been growing gradually since the Eocene. A sequence of undercompacted marine clays, overlain by deltaic deposits in turn covered by continental sands, is present throughout. The deltaic interval was formed by imbricated superposition of numerous regressive cycles that built out toward the sea. In the deltaic interval, growth-fault-associated rollover structures trapped hydrocarbons. The reservoirs are the sandy parts of sedimentary cycles ranging from 50 to 300 ft thick. The thinnest, most simple cycles are those composed of a marine clay overlain by delta fringe sediments. The laminated sand-silt-shale sediments deposited by longshore currents in water ranging from 30 to about 50 ft deep are called "barrier-face" deposits here. In shallower water, the current, tidal, and wave energy result in the deposition of long bars of clean, well sorted sand, called "barrier bars." The thickest cycles usually are composed mainly of fluviatile deposits - e.g., a series of superimposed "point bars." The barrier bar is the most common reservoir type, and the Obigbo North D1.30A reservoir, the subject of this study, is typical. The Obigbo North Field lies about 18 km (11 miles) northeast of Port Harcourt. The field was discovered in 1963. In A-Fault Block, 11 oil reservoirs can be differentiated. Reservoir D1.30A at about 7,250 ft subsea with 90.6 million STB oil initially in place (STOIIP) is the second largest. A-Block is a simple, unfaulted, rollover anticline. The low-relief, dome-shaped Reservoir D1.30A (Fig. 1) initially contained an oil ring of 130-ft column (25 deg. API gravity) between gas and water; gas volume in the primary gas cap was 33.8 Bscf. Gross reservoir thickness primary gas cap was 33.8 Bscf. Gross reservoir thickness varies from 40 to 85 ft. The reservoir seems to pinch out toward the south - i.e., toward the sea, away from the growth fault. Permeability is high, but variable. Production from D1.30A began in Oct. 1965. So far, the reservoir has been produced mainly by gas-cap expansion and (segregated) solution gas drive, with limited natural water influx. Its depletion character, demonstrated by an average reservoir pressure decline of 55 psi/% STOIIP produced (at 10 million bbl cumulative psi/% STOIIP produced (at 10 million bbl cumulative production) and the absence of pressure buildup during a production) and the absence of pressure buildup during a closed-in period in 1967-68, indicated the need for some form of pressure maintenance. In 1971, the first reservoir study was conducted with a two-dimensional, areal model to investigate the merits of alternative pressure-maintenance schemes. Based on this study, a peripheral waterflood was recommended, and a pilot water injection subsequently was initiated in April pilot water injection subsequently was initiated in April 1974 to determine injectivity and method of water injection (Well 22). The more comprehensive study discussed here was conducted to provide the technical basis for project optimization when extending the pilot test to a project optimization when extending the pilot test to a full-scale injection project. P. 1555