Determining Residual Oil Saturation Behind a Waterflood-A Case History

Abstract

Thorough analysis of cores and logs from a well drilled behind a waterflood in a permeable sand indicates a residual oil saturation, under reservoir conditions, of not more than 25 percent, and possibly as low as 20 percent. This is in good agreement with laboratory flood tests of cores. Introduction and Background Actual cumulative oil production from a sandstone reservoir subjected to waterflood has fallen significantly short of that predicted by experienced engineers having available a considerable amount of core analysis, electric logs, reservoir pressure history, etc. The engineers estimated oil originally in place by the volumetric method, and determined values of individual factors in a manner customarily used. The reservoir rock is a slightly consolidated, very porous, high-permeability sand deposited as an offshore sand bar. The structure is a slightly dipping monocline with the bar-type sand grading upstructure into a lagoonal sand facies of lower permeability and then into shale. About 72 percent of the initially oil-filled reservoir was in the main bar sand facies. An extensive gas cap overlies about 40 percent of the oil reservoir area, Similarly, water underlies about 54 percent of the area of the oil reservoir, which has a gross oil column of 60 ft. Field development averages 14 acres/well in the oil zone. Oil gravity is 38 degrees to 39 degrees API and oil viscosity was 0.52 cp initially at reservoir conditions. Nearly since inception, the field has been operated as a unit. When reservoir pressure had declined only 85 psi from 1,400 psi initially, a gas-injection pressure-maintenance program was started, with part pressure-maintenance program was started, with part of the produced gas being reinjected into the gas cap. Later, this was supplemented with injection of water outside the oil/water contact. Still later, the peripheral water injection rate was increased peripheral water injection rate was increased significantly and water injection at the gas/oil contact was undertaken to minimize displacement of oil into the gas cap. Pressure in the oil zone has been maintained within 200 psi of original pressure. Similarly, injection of both water and gas into the gas cap has restored pressure there to within 100 psi of original pressure. pressure. For a few years wells having high GOR's or water cuts in excess of 60 to 80 percent were shut in and the field allowable was produced from other wells. However, movement of the waterflood front across the reservoir indicated that the oil recovery per acre foot was much lower than had been expected. In a search for pockets of oil that might have been bypassed, an extensive testing program was undertaken in wells in the flooded-out area. Thirty such wells were tested; they involved 27 sand intervals that previously had been produced, and 20 sand intervals that previously had been produced, and 20 sand intervals that previously had not been perforated. In these latter previously had not been perforated. In these latter case, old perforations were packed off or squeeze cemented to isolate the new zones being evaluated. All these wells were produced for at least a few weeks to insure the adequacy of the test. All 47 well zones tested produced at very high water cuts and none of them yielded any significant amount of commercially recoverable oil. The areal coverage of the reservoir by these test wells is such that there is little likelihood that significant pockets of bypassed oil were missed. As part of the evaluation program, a well was drilled, cored, and logged in the flooded area. P. 1237

Development of mature oil fields — A review

“…Hence, oil remaining in place as a target for tertiary recovery may be much less than what was estimated by conventional methods of determining porosity and subtracting cumulative oil production. Later Elkins and Poppe (1973) evaluated a field case to estimate the residual oil saturation left for the tertiary oil recovery. They reported that the reduction in porosity due to compaction should be recognized and pressure coring is important in the evaluation of unconsolidated field cases.…”

Material balance approach for determining oil saturation at the start of carbon dioxide enhanced oil recovery

“…1. S orw = 24.0 percent, determined from core analysis and well logs, the field was not defined (Elkins and Poppe, 1973).…”

Discussion of The 1984 Natl. Petroleum Council Studies on EOR

“…This increased the calculated oil recovery efficiency from 35 to 55% of oil in place. 20 Essentially every factor affecting porosity and water saturation discussed here tends to overcalculate oil in place unless it is properly considered.…”