This field produces 8000 cp 100 API oil by natural water drive from an unconsolidated sand reservoir about 100 feet thick. Nearly all wells produced 10–50% sand initially, declining later to 0.1–2%, regardless of completion method. Apparently this production of sand created inter-connecting "worm hole" porosity extending at least between wells on porosity extending at least between wells on 10-acre spacing. Some of the evidence for this during primary production was:near-gauge caliper surveys of open hole sections after production of large volumes of sand;rapid movement of injected water and tracers between wells; andproduction of Jelflake lost circulation material from two wells following its use in workover and deepening of a third well. Air was injected below the oil-water contact in an edge well as a partial test for spontaneous ignition in a peripheral fireflood. In about four months some offset wells were converted to flowing after breakthrough of "air" devoid of oxygen but also containing very little carbon dioxide. When produced "air" reached high oxygen containing test was stopped. Later a structurally high 'Well was ignited. Extremely rapid travel of carbon dioxide to 2 offset wells was also indicative of inter-connected "worm hole" porosity created by production of sand. The fireflood stimulated two offset wells such that total field production increased from 100- to 170 BOPD previously to a maximum 400 BOPD six months later and averaged 310 BOPD for the 16 months of air injection. Cumulative average air-oil ratio was 6 Mcf/bbl. Although the test was physically successful, abnormally high physically successful, abnormally high producing well operating expense precluded producing well operating expense precluded continuing operation and expansion of the project. project Introduction The Southeast Pauls Valley Field, Garvin County, Oklahoma, producing from the oil Creek Sand at a depth of 4300 feet, 'Was discovered in March, 1955. Since it produces very viscous oil from unconsolidated sand, operating problems have been severe.

First response to large-scale water flooding in the fractured very low permeability Spraberry sand has led to a new unique cyclic operation. Capacity water injection is used to restore reservoir pressure. This is followed by many months production without water injection and the cycle repeated. Expansion of the oil, rock and water during pressure decline expels part of the fluids but capillary forces hold much of the injected water in the rock. At least with reservoir pressure restored and with partial water flood development, field performance has proved this cyclic operation is capable of producing oil from the matrix rock at least 50 per cent faster and with lower water percentage than is imbibition of water at stable reservoir pressure.

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

Reinterpretation of core analysis of an unconsolidated sand containing 8,000-cp oil indicates that the actual porosity of the sand in place is much lower than that arrived at even by special measurements on core samples recompacted under high confining pressure! The density log and sonic log from the same well support this conclusion. Introduction Accurate determination of oil in place in a reservoir is important when decisions are being made regarding development of a field; it is even more important later when decisions are made regarding installation of fluid injection projects when less of the oil remains; and it is extremely important in considering the recovery of additional oil by tertiary methods. Basically, volumetric estimates involving core analyses, fluid samples, well tests, well logs, and other geologic information are the only direct measure of oil initially in place. Frequently, interpreting pressure-production performance of the reservoir through material balance techniques performance of the reservoir through material balance techniques helps to establish the reliability of volumetric estimates. In some very heterogeneous reservoir rocks or in some reservoirs of limited areal extent, a material balance estimate is superior to the volumetric estimate. Uncertainties exist in all factors involved in both types of estimates. Because of alteration of cores during coring, handling, and analysis, volumetric estimates of oil in place in unconsolidated sand reservoirs are subject to added uncertainties. Unusual circumstances in the basal Oil Creek sand in the S.E. Pauls Valley field, Garvin County, Okla., provide some quantitative insight into these uncertainties. The reservoir rock is a completely unconsolidated, clean, well sorted, silica sand. It contains 10 degrees API gravity oil having a viscosity of about 8,000 cp at reservoir temperature. The oil has essentially no gas in solution. Thus, alteration of oil saturation by invasion of water-base mud filtrate and by release of pressure in bringing the core to the surface was minimized. In the example well drilled in 1966, 80 ft of oil-saturated core was recovered with a rubber-sleeve core barrel. This sand was so soft that it slumped by its own weight when the rubber sleeve was cut away from the core. One core sample per foot had fluid content measured by conventional, routine per foot had fluid content measured by conventional, routine analysis by a commercial laboratory. Porosity was determined by the sum-of-fluids technique. Eight samples, still in the rubber sleeve, were recompacted under simulated overburden pressure before porosity and fluid saturations were determined. pressure before porosity and fluid saturations were determined. Open-hole logs obtained from the same well included a dual induction-laterolog, a compensated formation density logs, and a sonic-gamma ray log. This paper reviews the various estimates of oil in place that might have been made if only parts of the core analysis and log data had been available. Conventional Core Analysis For those who are unfamiliar with the laboratory procedure, the sum-of-fluids porosity technique involves placing a weighed sample of core in a mercury porosimeter in which the bulk volume of the sample is first determined by displacement of mercury. Then mercury is injected into the core under high pressure to determine the volume of gas-filled space in the core sample. A weighed companion sample, or in some cases the mercury-impregnated sample, is retorted to determine the quantities of oil and water present. JPT P. 1315

Published in Petroleum Transactions, AIME, Volume 219, 1960, pages 301–304 Abstract Inclusion of anisotropic permeability in mathematical analysis of pressure transients observed during development of the huge Spraberry field indicates a major fracture trend which is in good agreement with that observed by fluid-injection tests spread over a 12- by 17-mile area. Delineation of this trend is important in selecting a pattern of injection for the pending large-scale water flooding in this field. Determination of reservoir parameters yielding best agreement between calculated pressures and observed reservoir pressures in newly completed wells was made using an IBM 650 computer. Introduction The Spraberry field covering 400,000 acres is a tight sand of less than 1-md permeability cut by an extensive system of vertical fractures. Primary recovery dominated by capillary retention of oil in the fractured sand matrix blocks is less than 10 per cent of oil in place. Strong forces of capillary imbibition of water into the sand, coupled with water flow under dynamic pressure gradient, indicate considerable increase in oil recovery can be achieved through water flooding. Best results will occur if the pattern of water injection is selected to force the water flow across the grain of the major fracture system. Existence of an oriented vertical fracture system in the Spraberry, observed first in cores, was highlighted more recently by the 144-fold contrast in permeability along and at right angles to the major fracture trend required to match relative water breakthrough times in Humble Oil and Refining Co.'s waterflood test there. Spraberry Operators since have conducted two gas-injection tracer tests for further areal confirmation of the fracture trend. Re-analysis of early reservoir pressure transients for evidence of anisotropic permeability has permitted many more local determinations of major fracture trend without resort to further field tests. This paper is limited to updating analysis of reservoir pressure transients to include anisotropic permeability as a test for orientation of the major fracture trend in the Spraberry. The reader is referred to Ref. 1 and 2 for information about general Spraberry reservoir performance and to Refs. 3 and 4 for information about significance of fracture orientation in selection of the injection well pattern for water flooding the Spraberry.