Effect of Overburden Pressure on Flow Capacity in A Deep Oil Reservoir
- H.H. Ferrell (Continental Oil Co.) | Martin Felsenthal (Continental Oil Co.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- September 1962
- Document Type
- Journal Paper
- 962 - 966
- 1962. Original copyright American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Copyright has expired.
- 5.2.1 Phase Behavior and PVT Measurements, 6.5.2 Water use, produced water discharge and disposal, 5.1.1 Exploration, Development, Structural Geology, 4.1.2 Separation and Treating, 4.3.4 Scale, 5.5.2 Core Analysis, 2.4.3 Sand/Solids Control, 5.1.2 Faults and Fracture Characterisation, 5.2 Reservoir Fluid Dynamics, 5.4.1 Waterflooding
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Brine flow capacity of a 9,000-ft deep, loosely consolidated sandstone reservoir was only about one-seventh as high as that predicted fro in routine relative-permeability data. It was found that the discrepancy between predicted and actual flow capacities was due to compression of the reservoir rock by the overburden. A close agreement was obtained when calculating reservoir brine flow capacity by five methods: (1) laboratory relative-permeability tests conducted at high confining pressure, (2) actual injectivity data, (3) combination of routine relative permeabilities with productivity-increase data, (4) pressure fall-off analysis and (5) water-influx data. The findings of this study should be applicable to other similar reservoirs. The third method listed should be particularly useful to the engineer for predicting injection rates in general. Overburden pressure affects reservoir oil and gas flow capacity in much the same way as it does brine flow capacity.
While trying to supplement the aquifer water drive in the Third Grubb reservoir of the San Miguelito field, Ventura County, Calif., it was noted that injection rates were only about one-seventh as high as the ones predicted from routine relative permeabilities. This discrepancy prompted the present study. It was found that the water treatment was adequate and that the wellbores of the injection wells were undamaged, thus leaving the effect of net confining pressure as a possible explanation. The net confining pressure is defined as the difference between the external and internal pressure acting on the formation. The external pressure is caused by the weight of the overburden, while the internal pressure is the counteracting force exerted by the fluids contained in the pore spaces. Although effect of confining pressure on permeability has been previously reported, this is the first known application of such data to a water-injection project.
The Third Grubb zone is located in the San Miguelito field, which is a faulted anticline located along the Ventura field trend some four-miles northwest of Ventura, Calif. Production is from sandstone layers of the Repetto formation which are interbedded with shales and siltstones typical of the Pliocene in the area. Most of the sandstone is loosely consolidated and occurs in layers 1/2- to 3-ft thick. The reservoir is bounded on the north and east by faulting and to the south and west by the water-oil contact. As seen in the structure map (Fig. 1), structural relief is high with an average dip of 45 degrees. Rock and fluid characteristics are summarized in Table 1, and reservoir permeability distribution is shown in Fig. 2. The zone was discovered in 1950, and development was completed by the end of 1953. Reservoir performance is illustrated in Fig. 3. The predicted (dashed) curves were constructed by the Schilthius material-balance method using laboratory kg/ko data. The actual (solid) curves are typical for a field having a strong aquifer water drive. A pilot water flood was initiated in 1955, and since that time many treatments have been attempted to increase the low injection rates.
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