Repressuring Improves Production in Mapiri Field
- G.J. Clarke (Mene Grande Oil Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- September 1958
- Document Type
- Journal Paper
- 35 - 37
- 1958. Original copyright American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Copyright has expired.
- 2.4.3 Sand/Solids Control, 4.1.6 Compressors, Engines and Turbines, 5.2.1 Phase Behavior and PVT Measurements, 4.1.9 Tanks and storage systems, 1.14 Casing and Cementing, 4.6 Natural Gas, 5.4.2 Gas Injection Methods, 1.2.3 Rock properties
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Early production history of the U2 sand, Mapiri field, indicated that solution gas drive was the predominant producing mechanism, and by mid-1954 the reservoir pressure had dropped from the original 4,100 psi to below 3,000 psi for a production of approximately 3.25 million bbl, or 11 per cent of the oil initially in place. At this time it was predicted that the ultimate recovery by primary depletion would be only 5.9 million bbl or 19.6 per cent. Repressuring by gas injection was then initiated, and the reservoir pressure was raised to the original value of 4,100 psi by the end of 1957. It is planned to maintain the reservoir pressure at this level until depletion, at which time it is estimated that the recovery will be 32.4 per cent or 9,725,000 bbl, an increase of 3,825,000 bbl over recovery by primary depletion.
The performance to date has followed closely that predicted in 1954, and has indicated that gas has reentered solution in the oil leg, and that a sharp flood front has been formed. GOR's are consequently close to the solution ratio, and no serious channelling or gas breakthrough has occurred.
Among the few major reservoirs in the Mapiri field, the U2 sand (Fig. 1), which lies at an average depth of 10,200 ft, was recognized at an early date as having good possibilities for a future gas injection project. This formation is a channel-type sand of Miocene-Oligocene age, in which the channel runs roughly north-south with the net sand thickness exceeding 60 feet in the center. The average thickness is 23.5 ft. Near the edges the thickness drops rapidly, being virtually unproducible in areas with less than 10 ft of net sand. The oil leg has a closure of about 600 ft and the water-oil contact is shown at an average depth of 9,450 ft below MSL.
The sand is a fine to coarse-grained sandstone, hard, quartzitic and massive with some secondary cementation. It is heterogeneous with variations in vertical and horizontal permeability, and individual lenses vary widely in thickness. The porosity varies considerably both vertically and horizontally and the weighted average for the reservoir is approximately 12 per cent.
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