Adverse Effects of Water Injection Into Thick Sand Reservoirs Containing Thin, Highly Permeable Lenses
- S.R. Mchaney (Mene Grande Oil Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- March 1962
- Document Type
- Journal Paper
- 253 - 256
- 1962. Original copyright American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Copyright has expired.
- 5.8.5 Oil Sand, Oil Shale, Bitumen, 5.4.2 Gas Injection Methods, 2.2.2 Perforating, 2.4.3 Sand/Solids Control, 5.1.2 Faults and Fracture Characterisation, 6.5.2 Water use, produced water discharge and disposal, 1.6 Drilling Operations, 4.3.4 Scale, 1.2.3 Rock properties, 4.6 Natural Gas, 5.2.1 Phase Behavior and PVT Measurements, 5.1.1 Exploration, Development, Structural Geology, 5.7.2 Recovery Factors
- 0 in the last 30 days
- 246 since 2007
- Show more detail
- View rights & permissions
Engineering studies for pressure maintenance by water injection were completed in 1956 on four reservoirs located in the Oveja field of Eastern Venezuela. Injection into the reservoirs began in Nov., 1957. Severe channeling of injected water occurred in the reservoirs, causing the suspension of water injection. Channeling is attributed to selective encroachment of the injected water through thin, highly-permeable sand sections. The J3 sand, OM-100 reservoir, is presented as a case history of the existing problem. Preliminary reservoir data indicated good sweep efficiencies and high recovery by water injection. Flood studies on core samples yielded recoveries in the 45 to 60 per cent range. Predicted recoveries by pressure depletion and pressure maintenance were 10.5 and 18.1 per cent, respectively. Water injection into the J3 sand was discontinued in Nov., 1960, when it became apparent that continued injection would be detrimental to ultimate recovery. The volumetric size of the water-encroached pattern was 30 per cent of total reservoir volume. Channeled water extended into updip wells, and continued injection would extend these channels in an updip direction. The remedial approach to depletion is planned for two phases: (1) wet wells will be produced at increased rates to prevent extension of water encroachment; and (2) gas will be injected into the secondary gas cap for pressure maintenance. Preliminary studies indicate an ultimate recovery of 26 million bbl by gas injection, which represents 14 per cent of the oil originally in place.
The Oveja field is located in the southern portion of the Greater Oficina area of Eastern Venezuela. The field was discovered in 1952 with the drilling of a wildcat well, Mundo-1, which has been renamed OM-100. Subsequently, field development included 88 wells for drainage of the I J3, L1L and L4 sands. Water encroachment through thin sections of highly permeable sand contained in thick sand deposits has yielded adverse effects to pressure maintenance by water injection in all of the afore-mentioned sands. Injection of water into the J3, L1L (southern reservoir) and L4 sands has been discontinued. A fourth injection project, L1L sand (northern reservoir), is currently being studied for possible discontinuation. Water injection into the I2L-3 sand was never initiated because of observed adverse effects in the other reservoirs. The problem of water encroachment, as displayed in the J3 sand, will be considered in this paper. The J3 sand is selected for presentation because the encroachment pattern is more severe than in the other sands.
Geological and Reservoir Data
The Oveja sand deposits are channel deposits with closure to the south formed by the main Oveja fault. The structure and isopach maps presented in Figs. 1 and 2 disclose a 20 dip to the northeast and sand pinch-outs occurring to the east and west. Reservoir boundaries are completed to the north by a southwest-to-northeast major fault and the water-oil contact at 3,438-ft subsea.
Surface area overlying the J3 sand covers 2,216 acres and the average net sand thickness is 44 ft, giving a total reservoir volume of 97,500 acre-ft. Volumetric calculations indicate that the pool originally contained 185 million STB of oil, a volume which has been confirmed within a small percentage by material-balance calculations.
|File Size||353 KB||Number of Pages||5|