Abstract

The late Guadalupian Bell Canyon Formation comprises alternating siltstone and fine to very fine-grained sandstone, which constitute economically important, shallow (2,000 to 3,000 ft. deep; 610 m to 914 m) oil reservoirs in the Delaware Basin. In Ford-Geraldine Field (Reeves and Culberson Counties), the “Ramsey” sandstone member, uppermost sandstone of the Bell Canyon Formation, was deposited in a deep, euxinic basin along a Permian passive margin (Figures 1 and 2).

To model reservoir geometry, especially in relationship to nearby production (Figure 3), over 500 well logs and 27 cores were analyzed. A network of core-to-log correlation was established by 19 stratigraphic cross-sections (Figures 4 and 5). The results indicate alternating sequences of channelized sandstone and widespread laminated siltstone and lutite (Figure 6).

Bottom-hugging hypersaline, density currents spilling off the shelf through arcuate, slump-generated breaches in the platform margin, gouged elongate, sub-parallel channels into the slope and extant submarine fan (Figure 7).

Occasionally, storm-generated 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 or ponded within the channel. Interval isopach maps show that the distribution of coarser sediment was strongly influenced by the topography of the channel-bottom. Finer sediment settled from suspension uniformly draping channel and inter-channel areas (Figure 8). Another aspect of sediment redistribution which adjusted slope gradient was the progressive, headward slumping of channel fill from successively higher portions of the slope triggered by instability farther down the slope. The back-filling lobate geometry of these deposits indicates that the channels were retrograding to a more gentle slope during a period of late Guadalupian high sea stand (Figures 8 and 9).

After eastward tilting of the Delaware Basin in the Permian and again in the Late Cretaceous, the proximal to distal fan facies had become structurally inverted. In addition, the thicker sand sections were compacted less than surrounding siltstone forming local compactional anticlines (Figure 10). Hydrocarbons migrated from structurally lower, more proximal facies toward the updip toes of the lobes and along the western margin of the channel facies. The reservoir sandstone was encased in less permeable, laminated siltstone; therefore, the terminal portion of the channels provided excellent stratigraphic traps, particularly where sandstone was “mounded” in compactional anticlines (Figures 10 and 11).

The Ford-Geraldine Field produces from one of these Ramsey, sand-filled terminal channels with original reserves estimated at 93 million barrels of oil in place (Figure 12). Within this complex trap framework, hydrocarbon distribution in the field is determined by a combination of stratigraphy, subtle structure, and hydrodynamics. Large variation in sandstone porosity and permeability over short vertical and horizontal distances result from

1. channeling within the larger channel complex,

2. thinly laminated siltstone layers which isolate individual sandstone layers,

3. sandstone pinch-outs into laminated siltstone, and

4. the distribution of calcite and authigenic clay cements.

Primary and secondary production extracted 22% of the original oil in place (Figure 13 and 14). Tertiary production (alternating carbon dioxide/water-flood) is underway (Figure 15). Reservoir characteristics described here should be incorporated into the enhanced recovery model in order to make valid predictions of tertiary recovery performance.