The late Guadalupian Bell Canyon Formation comprises alternating siltstone and fine to very fine-grained sandstone, which constitute economically important, shallow (2,000-3,000 ft, 600-900 m) oil reservoirs in the Delaware basin. In Ford-Geraldine field (Reeves and Culberson Counties), the Ramsey sandstone member, uppermost sand of the Bell Canyon Formation, was deposited in a deep-water, sediment-starved, euxinic basin.
Bottom-hugging hypersaline density currents spilling off the shelf through breaches in the Permian platform margin gouged elongate, subparallel channels into the slope and preexisting Laurentian-type fan.
Occasionally, sand-laden currents flowed through these channels, either scavenging sand stored on the shelf near the channel head or scouring material from intermittent depocenters on the slope. Where the slope gradient decreased significantly, sand was deposited within the channel. Isopach maps how that the distribution of coarser sediment was highly influenced by channel-bottom topography. The back-filling lobate geometry of these flows indicates that the channels were retrograding to a more gentle slope during a late Guadalupian period of high sea-level stand.
After eastward tilting of the Delaware basin in the Tertiary, hydrocarbons migrated updip toward the toes of the lobes and along the western margins of the channels. The reservoir sands are encased in less permeable, laminated siltstone; therefore, the terminal part of the channels provided excellent stratigraphic traps.
The Ford-Geraldine field produces from one of these Ramsey sand-filled terminal channels with original reserves estimated at 110 million bbl of oil. Within this complex trap framework, hydrocarbon distribution in the field is determined by a combination of stratigraphy, subtle structure, and hydrodynamics. Large variations in sandstone porosity and permeability over short vertical and horizontal distances result from: (1) channeling within the larger channel complex, (2) the occurrence of thinly laminated siltstone layers isolating individual sand layers, (3) sandstone pinch-out into siltstone, and (4) the distribution of calcite and authigenic clay cements. Primary and secondary production extracted 22% of the original oil in place. Tertiary production (alternating carbon dioxide and waterf lood) is underway. Reservoir characteristics described here must be incorporated into the enhanced recovery model to make valid predictions of tertiary recovery performance.