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

A pilot test of forward combustion in the Shannon pool, Salt Creek field, Wyo., is described. The Shannon sand, 950-ft deep, contains a heavy (25 API), viscous (76 cp) oil. Natural reservoir energy is limited. Primary production, intermittent since 1889, recovered only about 2 per cent of the oil in place. The field is operated by Pan American Petroleum Corp. for the Midwest Oil Corp., the owner. The original pilot was a 1.32-acre five-spot. The expanded pilot has eight producing wells surrounding a roughly triangular area of about five acres with the injection well near the center. A control or comparison well was also recompleted in another part of the field. Operation of the pilot has been little different from an ordinary gas drive. Little special equipment was found to be absolutely necessary. Except for some use of a temperature-resistant cement, all wells were conventionally completed. In spite of poor oxygen consumption, the over-all performance of the pilot has been good. Total oil recovery to June 1, 1961, was 73,971 bbl. The wells of the original pilot alone had produced about 24,000 bbl, equivalent to 50 per cent of the oil in place, when fire breakthrough at the first well occurred. These wells have now produced oil equivalent to more than 74 per cent of the oil in place in the original pilot area and production is continuing. It appears that ultimate recovery will approach theoretical maximums before the wells must be abandoned. Performance of the pilot has been encouraging, and expansion to a fieldwide combustion operation is being investigated. Introduction The results of both laboratory investigations and field tests of underground combustion have been reported previously. However, most of the field tests were primarily experimental. More information and experience are needed before forward-combustion operations can be engineered with confidence. The purpose of this paper is to present the results of a successful pilot test of forward combustion. These results should increase confidence in forward combustion as a practical method for commercial oil recovery. HISTORY OF THE SHANNON POOL The Shannon pool is located on the north end of the Salt Creek field in Natrona County, Wyo. It is approximately 50-miles north of the city of Casper. The Shannon pool discovery well was completed in 1889, making this one of the oldest oil fields in the Rocky Mountain region. Three more wells were drilled in 1890. First production was hauled in wooden barrels by horse and wagon to the railroad in Casper. In 1894 a small refinery, the first in Wyoming, was built in Casper to process the Shannon crude. In the following years the field changed hands several times. It appears that each new owner did some development drilling as several wells were completed in each of the years 1895, 1902, 1905 and 1912, with negligible development in the intervening years. Forty-eight wells were drilled in this period, but many were later abandoned. Discovery of the more prolific Salt Creek field proper ultimately forced suspension of operations at the Shannon pool. After 1915 there was only sporadic production, mostly to supply cheap boiler fuel to drilling rigs in the Salt Creek field. But even this was discontinued in 1931. Since then the pool had been dormant until the recent operations, which are the subject of this paper. The Shannon pool is now owned by the Midwest Oil Corp. Field operations are conducted for Midwest by Pan American Petroleum Corp. THE RESERVOIR Fig. 1 is a map showing subsurface contours of the Shannon pool. The reservoir is on a nose of the Salt Creek anticline dipping to the north at about 500 ft/mile. The trap is provided by a shallow fault on the updip side of the productive area. The downdip limits are bounded by water, but this water has not provided an effective source of reservoir energy. The Shannon sand outcrops at many places in the immediate vicinity, providing good surface indications of the Salt Creek anticline. At the Shannon pool the sand has been lowered by faulting and is overlain by about 900 ft of shale and other sands. The Shannon sand consists of two members. The upper, a water sand, is about 40-ft thick and is separated from the lower member by several feet of sandy shale. JPT P. 197^

By 1955, the First Wall Creek reservoir had reached the stripper stage. At that time a 20-acre double five-spot pilot was started to evaluate waterflood feasibility. Injected water was lost from the pilot area through natural fractures, and the five-spots were not encouraging. However, wells outside the five-spots showed production increases, so the pilot area was expanded to include about 100 acres. The expansion proved highly successful, and a full-scale program is now underway. Sand-oil fracture treatments have contributed to the success of the project. Introduction The geology and history of the Salt Creek field, Salt Creek, Wyo., have been described previously. The First Wall Creek pool under consideration here was discovered in 1908 and is one of 11 productive zones found on the Salt Creek anticline. The pool is cut by numerous normal faults of small displacement. Fig. 1 is a field map. Many of the smaller faults have been omitted in this figure. There are surface indications which suggest that some of these faults may be sealed by secondary deposits of calcite. The First Wall Creek pay zone, found at an average depth of 900 ft, is a fine- to medium-grained sand with numerous thin shale partings. Porosity and permeability are locally erratic, and average 15 per cent and 80 md, respectively. Gross thickness of the section averages 120 ft, of which about two-thirds is net pay and the remainder is shale. Core analyses indicate local zones of high permeability, usually near the base of the section. Injectivity profiles from spinner surveys show that extensive natural fracturing is present in some areas, and as a result, matrix permeability does not necessarily determine points of fluid entry into the wellbore. The produced crude is paraffin base, 38 gravity, having an estimated original solution GOR of 550 cu ft/bbl. The northern two-thirds of the Salt Creek field, including all of the First Wall Creek pool, was unitized in 1939, with the Midwest Oil Corp. as unit operator. Pan American Petroleum Corp. conducts the field operations for the unit owners on a contract basis. Sixty-eight companies and individuals are working interest owners in the unit. Gas Injection A gas-drive project was started in the Second Wall Creek pool, Salt Creek's largest reservoir, in 1926. This project was successfulit is still in operationso a similar program was attempted in the First Wall Creek starting in 1927. Maximum available surface injection pressure was only 350 psi, and most of the First Wall Creek wells would not take gas at economically significant rates with this injection pressure, so no measurable production benefit was obtained. Injections were nonetheless continued until 1949 to avoid flaring gas. A total of about 2 billion cu ft was injected in 22 years. JPT P. 1233ˆ

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