Air injection in the COFCAW project at Sloss field, Nebraska, was terminated in July 1971, but water injection was continued. The result has been the production of significant volumes of oil. Here is a discussion of field performance, of data obtained from core holes, and of possible modifications for future COFCAW operations. Introduction From Feb. 1967 to July 1971 a 960-acre COFCAW (Combination of Forward Combustion and Waterflooding) project was operated in the Sloss field, Nebraska. project was operated in the Sloss field, Nebraska. Well locations for the COFCAW area are shown in Fig. 1 and pertinent reservoir data are given in Table 1. During approximately 4 1/2 years in which air was injected, 646,776 bbl of stock-tank oil was recovered (not including 80,000 bbl captured during pilot operations). In addition, about 34,000 bbl of hydrocarbons vaporized by Rue gas pasting through the reservoir was vented to the atmosphere. Cumulative injections into the COFCAW area to July 1, 1971, were 13,754 MMscf of air and 10,818,000 bbl of water. The over-all average injected-air/produced-oil ratio was 21,266 scf/bbl. When air injection was terminated in July 1971, water injection was continued with encouraging results. To Jan. 1, 1974, an additional 189,000 bbl of stock-tank oil had been recovered: Adding this to that produced during air injection brings the total recovery to 836,000 bbl of oil and reduces the over-all air/oil ratio to 16,452 scf/bbl. (If all hydrocarbons in the vent gas had been recovered, the over-all air/oil ratio would calculate to be about 11,700 scf/bbl). After air injection was terminated in 1971, it was decided that core holes should be drilled in an effort to determine the following:Residual fuel saturation-i.e., how much hydrocarbon was left in those zones through which the combustion zone had moved.Variation in vertical sweep with distance from the injection well.Areal coverage by the burning front.Maximum temperature distribution - i.e., how the maximum temperature to which the rock had been subjected varied both areally and vertically.The effective permeability of the reservoir rock and whether some material had been deposited in the rock and reduced the flow capacity. Five core holes were drilled in late 1971 and early 1972. The COFCAW process is described in Refs. 1 through 4. Details of a 40-acre pilot test conducted in the Sloss field are given in Ref. 5 and details of the 960-acre project are given in Ref. 6. Our purpose here is to discuss the results of the core hole program and the performance of the COFCAW area under the influence of water injection. Selection of the Core Hole Locations The core holes were drilled in the Well 16-Well 17 quadrant of the five-spot pattern in which Well 16 was the center injector. This particular quadrant was selected because Well 16 was one of the better injection wells and because there was evidence that heat breakthrough had occurred at Well 17. Injection rates as a function of time for Well 16 are shown in Fig. 2. JPT P. 1439

Performance of a Forward Steam Drive Performance of a Forward Steam Drive Project-Nugget Reservoir, Winkleman Project-Nugget Reservoir, Winkleman Dome Field, Wyoming Despite its lack of some of the characteristics generally considered essential for a successful forward steam drive, this shallow reservoir, with its high saturation of viscous oil, has shown a gratifying response. Introduction The Winkleman Dome field in Fremont County, Wyo., was discovered in 1944 when the first well was completed in the Tensleep reservoir (Fig. 1). Early development in the field was exclusively in the Tensleep and Phosphoria reservoirs although the existence of oil in the shallower Nugget was recognized. Because of a lack of market and the low price of 14deg. API gravity crude, the Nugget could not be developed profitably. This situation was unchanged until crude prices increased by about 40cts/bbl in 1957. Five wells were drilled in 1958 and 1959 to obtain information about the reservoir, crude properties and primary performance. Studies indicated that none of primary performance. Studies indicated that none of the usual secondary recovery methods would be profitable. Even though the reservoir did not possess all profitable. Even though the reservoir did not possess all the criteria considered desirable for a steam injection project, it was believed that forward steam drive project, it was believed that forward steam drive should be tried. A steamflood was started in March, 1964, expanded in 1965, and expanded again in 1967 to the present area. The equipment used in these operations was discussed in an earlier paper. The purpose of this paper is to present performance of the Nugget reservoir during forward steam drive operations. Reservoir Characteristics Geology The Winkleman Dome field is an asymmetrical surface anticlinal feature along the northwest end of the Wind River basin of Wyoming. The accumulation of oil is primarily a result of structural relief. There is both surface and subsurface evidence of faults trending in a northeast-southwest direction. This faulting probably had a minor influence on the oil probably had a minor influence on the oil accumulation. (Within the presently developed acreage, only one fault in the northern portion has had any significant effect on well performance.) The Nugget sandstone is of Jurassic age and generally is considered to be a blanket sand. Within the Winkleman Dome field the formation is divided into three benches separated by shaly lenses. Fig. 2 shows a typical sonic log through the Nugget formation, with permeability also plotted to illustrate the zonation. The productive limits of the reservoir are determined by structural position. Oil-water contact was determined from information on Well 50, which appears to be located near it. Rock and Fluid Properties Average values for the various reservoir parameters are listed in Table 1. The rock properties are based on cores from five wells, three of which were cored with oil. The sand has excellent porosity and permeability (at least for a Rocky Mountain reservoir, permeability (at least for a Rocky Mountain reservoir, although these factors are not quite so good as those associated with steam recovery projects in some California fields). Pay thickness for the reservoir was developed from sonic logs correlated with core analysis data. Fluid properties were obtained from samples collected at the wellhead. The crude is a dead, viscous, 14 deg. API gravity oil. The original reservoir pressure was 210 psig. The primary producing mechanism was water influx. P. 35

Amoco Production Company is conducting a nine acre five-spot tertiary micellar project in the Sloss Field, Kimball County, Nebraska. Sloss Field, which is in the Denver Basin, produces from the Lower Cretaceous Muddy J Sandstone. The inability to match performance data collected during preflush water injection with mathematical model results suggested that an improved reservoir description was needed. Part of the effort to obtain a better reservoir description was to make a detailed geological study of the southern portion of the Sloss Field where the pilot is located. The geological update shows at least two genetically related, although different, deposits occurred within the field. Deposit Type I is a rather permeable sand that probably was deposited in a permeable sand that probably was deposited in a distributary channel. These deposits trend southeast-northwest and are relatively homogeneous. Permeability within these deposits is continuous. On the Permeability within these deposits is continuous. On the other hand, deposits of Type II, in which the pilot is located, represent overbank splays and apron sands. Sands in these deposits are discontinuous; consequently, there is a low probability that these sands have good areal and vertical communication with each other. The flow pattern in Type II sands is less uniform and less predictable than flow in Type I sands. Introduction The Sloss micellar project is being conducted, in a nine acre normal five-spot pattern, in the southern portion of the field. The four injectors are wells 110, 113, 114 and 115; Well 112 is the central producer (Fig. 1). All of these wells were drilled and cored after the pilot site was selected. All other wells in the southern portion of the field are shutin. Wells 109 and 75 are tested periodically. Reservoir performance data (primarily tracer data) collected during preflush water injection, prior to micellar injection, yielded results that prior to micellar injection, yielded results that conflicted with predicted flow behavior. The reservoir description utilized in the mathematical model predictions included a preferential permeability in predictions included a preferential permeability in a northwest-southeast direction to account for the flow behavior observed during earlier waterflooding and COFCAW operations. The description also contained the vertical variations that could be deduced from cores and logs in the pilot area. The description, however, did not include any significant variations in rock properties between the four quadrants of the pilot pattern. All four quadrants of the pattern were treated in a basically similar manner. Such a reservoir description would suggest that flow behavior within the quadrants of the five spot also would be similar. The conflicting tracer results were obtained from a program initiated in February, 1976. Different tracers were injected into each of the four injection wells. Samples were collected at the central producer, Well 112, and tracer concentrations in the produced fluid were obtained. Cumulative recoveries of these tracers, as a function of cumulative production, are shown in Figure 2. As may be seen from the figure, there was considerable difference in performance. The tracers injected at wells 110 and 115 broke through sooner and recoveries were higher than for tracers injected at wells 113 and 114. The performance was not consistent with the reservoir description being used for performance predictions. performance predictions. Changes in the reservoir description were needed. The steps that were taken to obtain a better description of areal and vertical variations in net pay, porosity, and permeability were (1) pulse testing, (2) additional tracer testing, and (3) a detailed geological study. The Sloss pulse test program is discussed in a separate pulse test program is discussed in a separate papers; the additional tracer test also is discussed papers; the additional tracer test also is discussed elsewhere.