Case History of Radioactive Tracers and Techniques in Fairway Field
- Tom G. Calhoun II (Calhoun Engineering) | Gary T. Hurford (Hunt Oil Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- October 1970
- Document Type
- Journal Paper
- 1,217 - 1,224
- 1970. Society of Petroleum Engineers
- 1.6.9 Coring, Fishing, 4.3.4 Scale, 6.5.2 Water use, produced water discharge and disposal, 4.6 Natural Gas, 5.4.1 Waterflooding, 5.1 Reservoir Characterisation, 4.1.5 Processing Equipment, 5.2.1 Phase Behavior and PVT Measurements, 5.3.2 Multiphase Flow, 5.7.2 Recovery Factors, 4.1.2 Separation and Treating, 5.4.2 Gas Injection Methods, 5.1.1 Exploration, Development, Structural Geology, 5.6.5 Tracers
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Radioactive isotopes have been useful in tracing the configuration of the gas displacement fronts in the Fairway alternate gas-water miscible recovery project. Variations in sweep patterns with changing reservoir pressure gradients, source of gas breakthrough, and indications of pressure gradients, source of gas breakthrough, and indications of miscibility can be inferred from tracer responses in this field.
The Fairway (James Lime) oil reservoir, containing approximately 421 million STB of oil initially in place at original reservoir pressure of 5,226 psia, was discovered in July, 1960, at a depth of about 10,000 ft. Productive limits of the field, enclosing approximately Productive limits of the field, enclosing approximately 23,000 acres with an average pay thickness of about 70 ft, were established in 1963. The field, now fully developed on 160-acre spacing with 152 wells, is currently producing 36,000 BOPD under pressure maintenance by alternate gas-water injection. The Fairway (James Lime) reservoir is a reef deposition with three major porous intervals - Upper A zone, Lower A zone and C zone - which are lithologically related to various stages of reef development. The three major zones are connected vertically in several areas of the reservoir, although the zones are distinctly separated by dense lime over most of the field. Average permeabilities of the three zones vary widely - 42.5 md in the Upper A, 22.6 md in the Lower A and 3.2 md in the C zone - even though average porosities of all three zones range from 12 to 13 percent. The James Lime oil in the main field area is an undersaturated 48 degrees API gravity crude with a solution GOR of 1,350 to 1,600 cu ft/bbl. Saturation pressure varies with depth, and ranges from about 3,950 psia at the average oil-water contact of9,550 ft to 4,350 psia at the structural high of9,280 ft. Laboratory psia at the structural high of9,280 ft. Laboratory tests show that the James Lime oil is miscible with dry gas at about 4,800 psi. The irreducible water saturation varies from about 10 percent to about 30 percent, depending on rock type. There is evidence that the Lower A zone may be oil wet as a result of the presence of residual bitumen in the pore spaces. The western gas cap area of the James Lime reservoir, which exhibits different fluid characteristics and behaves as a separate reservoir, is beyond the scope of this paper.
Alternate Gas-Water Injection Plan
Initial economic studies indicated that pressure maintenance by alternate gas-water injection at the miscibility pressure of 4,800 psia would be the optimum recovery program. The miscible recovery program was expected to increase recovery efficiency to 50 percent, which is 13 percent more than the expected percent, which is 13 percent more than the expected waterflood recovery factor of 37 percent. The initial injection plan was based on alternating gas and water injection into several parallel lines of injection wells running generally northwest-southeast, parallel to the reef core trends. The A zone and C parallel to the reef core trends. The A zone and C zone were to be operated as separate reservoirs insofar as possible. Plans were to begin the program by injecting into the A zone an initial gas slug equal to 3 to 5 percent of the hydrocarbon pore volume in the area of injection in the first line of injection wells on the east side of the reservoir. Initial gas slugs in the first line of injectors were to be followed by initial water slugs equal to approximately 50 percent of the preceding gas slugs. After placement of the initial preceding gas slugs. After placement of the initial slugs, subsequent smaller gas and water slugs were to be injected alternately at an approximate 1:1 gas-water injection ratio. The initial gas slugs were larger than subsequent slugs of water and gas, on the theory that a miscible bank of gas could be maintained in contact with the oil. Gas injection into the first line of injection wells was begun in March, 1966, shortly after the entire field was unitized in Oct., 1965.
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