This report summarizes results of an integrated geological, geophysical, petrophysical, and engineering study of a representative Delaware Mountain Group field to identify constraints on producibility in the deep-water sandstone reservoir exhibiting low primary recovery efficiency. The Ramsey sandstone interval of the Bell Canyon Formation was characterized in the Ford Geraldine unit, Culberson and Reeves Counties, Texas, using data from outcrops, subsurface logs and cores, and a 3-D seismic survey. Facies relationships determined from depositional processes interpreted from outcrop analogs exposed in Culberson County suggest that the sandstones were deposited by turbidites in a basin-floor system of channels and levees having attached lobes. The depositional model developed from outcrop can be widely applied by operators to other reservoirs that produce from Delaware sandstone. The study was funded primarily by the U.S. Department of Energy and the State of Texas. Because reservoirs in deep-water sandstones of the Delaware Mountain Group in West Texas and New Mexico are characterized by low primary recovery efficiency (<I4 percent), an integrated geological, geophysical, petrophysical, and engineering study of a representative Delaware Mountain Group field was performed to identify constraints on producibility. Characterization of the Ramsey sandstone interval of the Bell Canyon Formation was conducted in the Ford Geraldine unit, Culberson and Reeves Counties, Texas, using data from outcrops, subsurface logs and cores, and a 3-D seismic survey. Outcrop analogs exposed in Culberson County, Texas, were studied to interpret the depositional processes that formed the reservoirs at the Ford Geraldine unit better and to determine the dimensions of reservoir sandstone bodies. Facies relationships suggest that the sandstones were deposited by turbidites in a basin-floor system of channels and levees having attached lobes that initially prograded basinward, aggraded, and then turned around and stepped back toward the shelf. The 0- to 60-ft-thick Ramsey sandstone interval in the Ford Geraldine unit is interpreted as a channel-levee and lobe system similar to the one described in outcrop. Lobe deposits consist of massive and convoluted sandstones having load and dewatering structures, suggesting that the sandstones were deposited rapidly from high-density turbidity currents. Channel facies, approximately 1,200 ft wide and 15 to 35 ft thick, overlie and locally incise the lobe deposits. They consist of massive and crossbedded sandstones interpreted to have been deposited from high-density turbidity currents. Channel margins, characterized by rippled and convoluted sandstones interbedded with siltstones, are interpreted as channel levees formed by overbanking of low-density turbidity currents. Ramsey sandstones are bounded by laterally continuous, organic-rich siltstones deposited by settling from suspension. Siltstone beds and extensively calcite cemented sandstones are the most important causes of reservoir complexity. Petrophysical characterization of the Ford Geraldine unit was accomplished by integrating core and log data and quantifying petrophysical properties from wireline logs. Net-pay cutoffs of 215 percent porosity (for permeability of 1 md), 160 percent water saturation, and 515 percent volume of clay were established. Water saturations were calculated by the following modified Archie equation: S, = [(I/0) x (Rw/R,)]l'l.90. The petrophysical data were used to map porosity, permeability, net pay, water saturation, mobile oil saturation, and other reservoir properties. Interpretation of the 3-D seismic volume indicates that Ramsey sandstone thickness in the Ford Geraldine unit is one-fourth of a wavelength of the seismic data or less and is therefore considered a thin bed. The coherency cube was effective in delineating the field outline but failed to detect reservoir compartmentalization. A residual map of the seismic horizon corresponding to the top of the Lamar limestone identified a residual high that is associated with Ramsey sandstone thickness. An area in the north part of the unit that has not undergone tertiary development was chosen for reservoir modeling/simulation. Flow simulations were performed for a CO, flood to estimate the tertiary recovery potential of the area. Results indicate that 10 to 30 percent (1 to 3 million barrels [MMbbl]) of the remaining oil in the area can be produced by CO, injection.