Conversion of Steam Injection to Waterflood, East Coalinga Field
- B.I. Afoeju (Shell Oil Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- November 1974
- Document Type
- Journal Paper
- 1,227 - 1,232
- 1974. Society of Petroleum Engineers
- 3 Production and Well Operations, 2.4.3 Sand/Solids Control, 1.14 Casing and Cementing, 4.1.5 Processing Equipment, 5.4.1 Waterflooding, 2.2.2 Perforating, 5.4.6 Thermal Methods, 5.6.9 Production Forecasting, 1.10.1 Drill string components and drilling tools (tubulars, jars, subs, stabilisers, reamers, etc), 6.5.2 Water use, produced water discharge and disposal, 5.8.5 Oil Sand, Oil Shale, Bitumen, 5.2.1 Phase Behavior and PVT Measurements, 4.3.4 Scale, 1.2.3 Rock properties, 4.1.9 Tanks and storage systems
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The Section 27 Zone I steam drive project in this California field was started in early 1963. Originally designed and operated as a five-spot steam drive, the project has gradually been converted to a five-spot waterflood. Injected water has been able to displace significant quantities of oil, aided by the improved oil mobility resulting from heat retained in the reservoir.
The Section 27 Zone I drive project is located in the East Coalinga field in Fresno County, Calif. The project was started in Jan. 1963 with a pilot consisting of six injectors enclosing two interior producers to form a double five-spot pattern (see producers to form a double five-spot pattern (see Fig. 1). Production response from the pilot was very encouraging and by the end of 1964 the project had been expanded to 60 injectors and 93 producers in an irregular five-spot pattern encompassing an area of 530 acres. The project suffered its first major setback in early 1965 when casing failures induced by thermal stresses were detected in 23 steam injectors. These were old primary production wells that had been converted to steam injectors. Steam injection was reduced while repairs were carried out in the 23 injectors by cementing inner strings. Owing to extremely poor injectivity and production performance, steam injection into all but one northern performance, steam injection into all but one northern area injector was suspended in June 1966. By this time steam and hot water breakthrough had occurred in many central area producers as a result of the presence of high-permeability alluvial channel sands presence of high-permeability alluvial channel sands that were found to be accepting most of the steam in injectors where they were present. Attempts to plug off the channel sands with cement and silica gel were unsuccessful. In 1966 eight central area wells were converted from steam to water injection to evaluate cold-water scavenging as a follow-up to steam injection. In Aug. 1966, water injection was extended around all but the downdip eastern edge of the project. enclosing a total area of 700 acres within the project. On the basis of encouraging performance by producers surrounding the eight water injectors and producers surrounding the eight water injectors and supported by Shell Development Co. model studies, all but the 13 injectors in the downdip high-viscosity area were converted to water injection in Oct. 1967. Better injection profiles were obtained with water, and efforts in plugging the thief channel sands in water injectors were successful in more than half the attempts made. Economic considerations led to the conversion of the 13 remaining steam injectors to water injection at the end of 1969.
The Temblor (middle Miocene) Zone I reservoir consists of an easterly dipping (14 degrees) homocline with well depths varying from 900 ft on the updip western edge of the project to 2,200 ft in the downdip eastern edge, averaging about 1,500 ft. The reservoir is confined on the north, east and south to edge water and on the west by subcropping of the sands. approximately 1 mile updip of the project area. The gross thickness of the reservoir is about 300 ft, of which an average of only 50 ft is considered net oil sand. Geologically, the gross interval is subdivided into 10 distinct reservoir layers (see Fig. 2).
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