Abstract

A study was done at Nash Draw field, Eddy County, New Mexico, to demonstrate how engineering, drilling, geologic, geophysical, and petrophysical technologies should be integrated to improve oil recovery from Brushy Canyon reservoirs at depths of approximately 6600 ft (2000 m) on the northwest slope of the Delaware basin. These thin-bed reservoirs were deposited in a slope-basin environment by a mechanism debated by researchers, a common model being turbidite deposition. In this paper, we describe how state-of-the-art 3-D seismic data were acquired, interpreted, integrated with other reservoir data, and then used to improve the siting of in-field wells and to provide facies parameters for reservoir simulation across this complex depositional system. The 3-D seismic field program was an onshore subsalt imaging effort because the Ochoan Rustler/Salado, a high-velocity salt/anhydrite section, extended from the surface to a depth of approximately 3000 ft (900 m) across the entire study area. The primary imaging targets were heterogeneous siltstone and fine-grained sandstone successions approximately 100 ft (30 m) thick and comprised of complex assemblages of thin lobe-like deposits having individual thicknesses of 3 to 6 ft (1 to 2 m). The seismic acquisition was complicated further by (1) the presence of active potash mines around and beneath the 3-D grid that were being worked at depths of 500 to 600 ft (150 to 180 m). (2) shallow salt lakes, and (3) numerous archeological sites. We show that by careful presurvey wave testing and attention to detail during data processing, thin-bed reservoirs in this portion of the Delaware basin can be imaged with a signal bandwidth of 10 to 100 Hz and that siltstone/sandstone successions 100 ft (30 m) thick in the basal Brushy Canyon interval can be individually detected and interpreted. Further, we show that amplitude attributes extracted from these 3-D data are valuable indicators of the amount of net pay and porosity-feet in the major reservoir successions and of the variations in the fluid transmissivity observed in production wells across the field. Relationships between seismic reflection amplitude and reservoir properties determined at the initial calibration wells have been used to site and drill two production wells. The first well found excellent reservoir conditions; the second well was slightly mispositioned relative to the targeted reflection-amplitude trend and penetrated reservoir facies typical of that at other producing wells. Relationships between seismic reflection amplitude and critical petrophysical properties of the thin-bed reservoirs have also allowed a seismic-driven simulation of reservoir performance to be initiated.

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