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Infill development drilling in this field has more than doubled oil production and has increased ultimate recovery. Changes in injection production and has increased ultimate recovery. Changes in injection patterns and changing from gas injection to a combination of gas and water patterns and changing from gas injection to a combination of gas and water injection are expected to improve sweep and displacement efficiency. Introduction The Little Buffalo Basin field is located in northwestern Wyoming on the southwest side of the Big Horn basin (Fig. 1). The structure is a north-south trending asymmetrical anticline that encompasses 1,500 productive surface acres (Fig. 2). Five reservoirs on the productive surface acres (Fig. 2). Five reservoirs on the structure produce hydrocarbons. The Pennsylvania Tensleep reservoir discussed in this paper produces 20 degrees API gravity, 42-cp viscosity crude from an average depth of 4,600 ft. Reservoir energy is primarily supplied by an active edge-water drive. Because of unfavorable mobility ratios, it is quite common for moderately viscous crude reservoirs of this type to perform less efficiently than reservoirs exhibiting mobility ratios of 1 or less, especially if the formation is thick and heterogeneous. For example, when the driving phase prematurely breaks through open fractures or fingers through high-permeability strata the result generally is poor sweep efficiency. Even though well logs might indicate that a reservoir is continuous and relatively homogeneous from well well, cross-bedding, sealed vertical fractures, siltstone and pore filling can cause horizontal permeability to vary considerably. This permeability permeability to vary considerably. This permeability variation can drastically influence both primary and secondary recovery operations. Therefore even a generalized description of reservoir heterogeneity can be helpful, and in fact often results in operation changes that improve recovery. A geologic and engineering analysis of the Little Buffalo Basin Tensleep was undertaken to define the reservoir better and to explain producing characteristics. Oriented cores, using lease crude as the drilling fluid, were taken during the study, the purpose being to develop a better understanding of reservoir fluid saturations, cross-bedding, directional permeability, permeability variation, lenticularity and fracturing. permeability variation, lenticularity and fracturing. Knowledge gained from the core studies was then used to interpret how lithology influences flow of fluids in the reservoir and how field operations could be improved. Development History The Tensleep reservoir of the Little Buffalo Basin field was discovered in 1943 when Trigood Oil Co. completed T. A. Pedley Well 1 (now Unit Well 39). A unit was formed in the same year for the purpose of development and operation. Pan American Petroleum Corp., the unit operator, completed the confirming Well 2 in June, 1944. Development was slow at first because of the limited demand for the sour, viscous, asphalt-base crude. During the first 14 years, maximum production was 2,600 BOPD. Edge wells that completed development on 40-acre spacing within the productive limits were not drilled until 1958. Fig. 3 shows performance of the Tensleep reservoir since 1958 and the results of development drilling, which established a peak producing rate of 6,500 BOPD during mid-1958. To date, 68 Tensleep wells have been drilled. JPT P. 161

This paper was prepared for the SPE Rocky Mountain Regional Meeting to be held in Casper, Wyo., May 22–23, 1967. Permission to copy is restricted to an abstract of not more than 300 words. Illustrations may not be copies. The abstract should contain conspicuous acknowledgement of where and by whom the paper is presented. Publication elsewhere after publication in the JOURNAL OF PETROLEUM TECHNOLOGY or the SOCIETY OF PETROLEUM ENGINEERS JOURNAL is usually granted upon request to the Editor of the appropriate journal provided agreement to give proper credit is made. Discussion of this paper is invited. Three copies of any discussion should be sent to the Society of Petroleum Engineers office. Such discussion may be presented at the above meeting and, with the paper, may be considered for publication in one of the two SPE magazines. Abstract Cottonwood Creek field is on the east side of the Big Horn Basin in northwestern Wyoming. It is on a west-southwest dipping monoclinal surface, with about 5,500 ft of structural relief through the productive interval. This field is an excellent example of a stratigraphic trap resulting from an updip facies change. Throughout Phosphoria deposition the boundary between the carbonate facies and red shale-anhydrite facies fluctuated along a north-south zone in the eastern part of the Big Horn Basin. Cottonwood Creek field is in the zone where the two facies intertongue. The stratigraphic trap for hydrocarbons is the impervious strata of the red bed sequence where it grades into the carbonate facies. Within the productive area outlined by Cottonwood Creek field, upper Phosphoria shoaling and bioclastic thickening occurred together with a concomitant porosity increase within what generally is a fine-grained dolomite facies. The producing interval contains oolites, lithoclasts, pellets and residual fossil bioclasts. Vugs are numerous; some appear to be fossil molds. Cottonwood Creek field was discovered in 1953 and has produced more than 23 million bbl of oil from 14,200 productive acres. Field development was essentially complete by 1958. During June, 1958, an upstructure gas-injection program was begun to maintain reservoir pressure and increase ultimate oil recovery. Gas injection resulted in rapid movement of gas to producing wells and, in many wells, oil production rates declined. An upstructure water-injection program was begun in 1959 and was expanded to midstructure during 1962. In many places injected water channeled rapidly to producing wells and resulted in decreased oil production. To account for reservoir performance, all available geological, engineering and production data were reviewed. These indicated that reservoir performance is dependent on both the primary [matrix] rock characteristics and a superimposed fracture system. The fracture system was the primary cause of poor injection performance. The geologic concept of the reservoir was found to correlate-well with field performance and resulted in a rational explanation of the poor secondary recovery performance. A variety of methods were used to determine areal geological variations in the reservoir.

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.

Elk Basin Madison experience underscores the need for a good understanding of reservoir heterogeneity and subzone performance early in field life. That understanding was necessary in this case before a fully meaningful engineering analysis of the reservoir could be made. Introduction The Elk Basin anticline is one of the giant oil fields in the U. S. (see Fig. 1). It had more than a billion barrels of oil originally in place and has produced at rates in excess of 70,000 BOPD. Production is from seven horizons ranging in depth from 1,000 to 6,500 ft (Fig. 2). The anticline has dimensions of about 2 X 7 miles. Dip is about 25 degrees on the west flank and about 45 degrees on the east flank. Horizons below the Dakota are included in the Elk Basin Unit, operated by Pan American Petroleum Corp. for a large group of working interest owners. The Tensleep sandstone (Pennsylvanian) and Madison limestone (Mississippian) are the most important reservoirs, each having about a half billion barrels of original oil in place. In 1965, the Madison Unit began to experience waterflooding problems for which there was no readily apparent solution. Peripheral water injection initiated in 1962 did not get response. After part of the water was shifted to the interior, response was obtained, but water breakthrough, wellbore scaling and severe productivity declines soon became problems. The oil producing rate again began to decline. A preliminary review of logs and core analyses indicated highly complex zonation in the 920-ft vertical Madison section. A detailed zonation study was therefore undertaken to determine the degree of continuity in the reservoir, with the hope of finding answers to the waterflooding problems. The study was a coordinated effort by both geologists and engineers. Field Development History The Madison reservoir was discovered in 1946 when a well on the crest of the north high (see Fig. 3) was deepened from the Tensleep to the Madison. A number of cores and DST's established that porous intervals in the entire Madison section were productive and that a major discovery had been made. The discovery well had a flowing potential of 898 BOPD. Development was slow until 1948 when a market was found for the black, asphaltic-base, 28 degrees API crude. Seventeen wells were drilled in 1948 and eight more in 1950. Field producing rate increased to about 7,000 BOPD and remained in the 3,000 to 8,000 BOPD range until 1958 (see Fig. 4). During the late 1950's and early 1960's market demand of about 16,000 BOPD was met by drilling 27 additional producing wells and by installing larger rift equipment. From 1964 to the present, market has been essentially unrestricted, but no significant drilling, other than injection wells, was done until 1965 when the first wells were drilled as a result of the zonation study. Early Reservoir Concepts Early ideas about the Madison reservoir were influenced by the fact that most wells were completed open hole through the entire 920-ft section. First production performance was markedly water driveonly a slight pressure decline occurred in the first 10 years of field life. JPT P. 153ˆ