Production Technology Experience in a Large Carbonate Waterflood, Denver Unit, Wasson San Andres Field
- W.K. Ghauri (Shell Oil Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- September 1980
- Document Type
- Journal Paper
- 1,493 - 1,502
- 1980. Society of Petroleum Engineers
- 6.5.2 Water use, produced water discharge and disposal, 4.2.3 Materials and Corrosion, 2 Well Completion, 5.6.5 Tracers, 5.2.1 Phase Behavior and PVT Measurements, 5.8.7 Carbonate Reservoir, 5.1.1 Exploration, Development, Structural Geology, 3.1 Artificial Lift Systems, 3.1.1 Beam and related pumping techniques, 4.1.5 Processing Equipment, 2.4.3 Sand/Solids Control, 5.6.4 Drillstem/Well Testing, 4.3.4 Scale, 2.2.2 Perforating, 3 Production and Well Operations, 4.1.2 Separation and Treating, 5.5 Reservoir Simulation, 4.6 Natural Gas, 5.4.1 Waterflooding, 1.14 Casing and Cementing, 5.6.1 Open hole/cased hole log analysis, 1.6 Drilling Operations, 3.2.4 Acidising, 1.10 Drilling Equipment, 5.7.2 Recovery Factors, 5.2 Reservoir Fluid Dynamics
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Shell Oil Co. currently is operating a large waterflood project in the Permian San Andres dolomite reservoir in west Texas. The project comprises 900 producers and 360 injectors. In addition to major infill drilling programs, a substantial remedial and reconditioning program has been carried out. Highlights of production technology experience are presented.
The Denver Unit waterflood project in the Wasson San Andres field in West Texas ranks among the largest supplemental recovery projects currently operating in the U.S. (Fig. 1). Shell Oil Co. is the operator and holds the major working interest. The paper has evolved through several phases of infill development drilling and flood pattern modifications that have been carried out in the course of conducting the waterflood project.
The paper is divided into two parts. The first deals with a brief history of the waterflood with the objective of providing the project setting for the production technology practices currently being followed. The emphasis is placed not on the statistical data per se but rather on the evolutionary process through which present procedures have been developed, as well as their interrelationship with the geologic, petrophysical, and reservoir aspect as as they pertain to the project. The second part describes the specific practices of well completion, well stimulation, injection profile control, artificial lift, flood surveillance, and related drilling, remedial, and reconditioning operations now being used and how they have contributed to the enhancement of ultimate recovery from the project.
The Wasson San Andres field was discovered in 1936. The bulk of primary development at 40-acre (162 000-m2) well spacing was completed by the early 1940's. Supplemental recovery operations were initiated with unitization and commencement of water injection in 1964 (Fig. 2).
The producing horizon is the Permian San Andres dolomite formation at an average depth of 5,200 ft (1585 m). Gross oil pay thickness varies between 200 and 500 ft (60 and 150 m). The structure is an anticline capped by dense dolomite and underlain by an essentially inactive aquifer. Solution-gas drive has been the primary producing mechanism. Table 1 shows a summary of basic project data. The oil reservoir has an original gas cap. Although some production has occurred from the gas cap, primarily before unitization, Shell's policy during waterflooding operations has been to leave the gas cap unexploited to conserve reservoir energy and prevent waste by the migration of oil into the gas cap.
When unitization was effected in 1964, the geologic concept of the reservoir was a simplistic one and was markedly different from the rather complex model that has evolved today. The original definition of the San Andres reservoir was based on gross geologic correlations of reservoir-quality rock and the assumption that this rock largely was interconnected over the entire extent of the unit.
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