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.