A Field Test of Soluble-Oil Flooding At Higgs Unit
- R.K. Knight (Union Oil Co. of California) | P.J. Baer Jr. (Union Oil Co. of California)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- January 1973
- Document Type
- Journal Paper
- 9 - 15
- 1973. Society of Petroleum Engineers
- 5.3.4 Reduction of Residual Oil Saturation, 1.6.9 Coring, Fishing, 6.5.2 Water use, produced water discharge and disposal, 5.2.1 Phase Behavior and PVT Measurements, 5.6.5 Tracers, 5.6.4 Drillstem/Well Testing, 5.4.7 Chemical Flooding Methods (e.g., Polymer, Solvent, Nitrogen, Immiscible CO2, Surfactant, Vapex), 1.6 Drilling Operations, 4.1.5 Processing Equipment, 5.4.1 Waterflooding, 2.2.2 Perforating, 5.2 Reservoir Fluid Dynamics, 5.3.2 Multiphase Flow, 5.4.9 Miscible Methods, 2.4.3 Sand/Solids Control, 5.6.1 Open hole/cased hole log analysis, 5.1.1 Exploration, Development, Structural Geology
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This pilot field test in West Texas demonstrated that tertiary oil can be mobilized and recovered by the soluble-oil flooding process. Such a tertiary application can be economic, provided the residual oil saturation after waterflooding is high enough, but application at the beginning of waterflooding has a greater economic potential.
Laboratory studies have indicated that the use of soluble oil could recover substantial quantities of oil not recoverable by waterflooding. Field testing of these materials in oil recovery processes has been previously reported. Considering the potential of previously reported. Considering the potential of the process and the developing need for tertiary oil, plans were made to field test the Uniflood* process plans were made to field test the Uniflood* process at Higgs Unit, near Abilene, Tex. The Higgs Unit (Fig. 1) encompasses 350 acres in Jones County, Tex. The productive zone is the Bluff Creek sand of Permian age, at an approximate depth of 1,870 ft. The primary life of the field extended from discovery (Well 6) in March, 1951, until water injection was started in Wells 1, 3, and 7 in Oct., 1964.
In the original developmental drilling of the field, no cores were taken. Because none of the wells penetrated the entire production interval (it was suspected that there was a water-oil contact on the western flank of the sand body), no accurate determination of reservoir size was available. It was estimated that the reservoir consisted of 1,200 acre-ft, containing an average of 908 STB of oil per acre-ft (about 1,090,000 bbl total). Primary oil production was about 334,000 bbl and secondary recovery to Jan. 1, 1969, totaled about 244,000 bbl. The waterflood was developed as a peripheral flood, with injection into Wells 1, 2, 3, 7, and 11. Wells 4, 5, and 6, the first-line producers, showed poor response and watered out early in the flood. poor response and watered out early in the flood. (Well 4 had been used for salt-water disposal before the waterflood program was begun.) Wells 4 and 6 were inactivated when they watered out, and Well 5 was plugged and abandoned because of collapsed casing. The second-line producers, Wells 8, 9, and 10, responded to the waterflood, as did the two remaining producers, Wells 12 and 13. The unit production history from 1962 through 1971 is production history from 1962 through 1971 is presented in Fig. 2. presented in Fig. 2. Pattern Selection Pattern Selection To make the best use of the existing waterflood pattern and to insure the confinement of injected pattern and to insure the confinement of injected chemicals, it was decided to redrill Well 5 and use it as the pilot-area injector. The continued water injection on the west and south sides of the field would help to move mobilized oil toward Wells 8 and 9 and possibly toward Well 4. In addition, drilling a new well would provide an opportunity to core and log the hole and to measure reservoir thickness, porosity, oil saturation, and permeability - factors porosity, oil saturation, and permeability - factors that had only been estimated previously.
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