ABSTRACT The Lavaca submarine canyon briefly formed a large slump-generated embayment, centered in Lavaca County, Texas, along the prograding Lower Wilcox shelf margin. Episodes of canyon excavation by large-scale mass wasting alternated with periods of delta lobe progradation into the upper canyon. Resultant canyon fill consists of (1) displaced, rotated slide blocks of the pre-canyon deltaic succession, (2) slump, debris flow, fluidized flow, and turbidity-flow deposits derived from canyon-margin deltas, which bypassed the steep (20 to 30°) canyon walls, and (3) progradational prodelta and delta front deposits. Slide, slump, and flow deposits onlapped the canyon floor; unstable delta front sediments infilled and healed the remnant canyon cut embayment. The lower, onlapping canyon fill contains typical mud-dominated turbidite channel fills and associated overbank and levee facies that are prolific, though elusive, gas-condensate reservoirs in Hallettsville E., Hallettsville Burns, Good Hope, and Campbell Creek fields. The bulk of the canyon fill consists of mass-transport complexes of muddy slump and debris-flow lobes and tongues. Cohesive slides and slumps, a spectrum of liquefied flow deposits, high-density turbidites, and low-density turbidites are prominent in cores of the canyon fill. Reworked sand beds deposited by contour(?) currents are a minor but distinct lithofacies. In-situ hemipelagic and pelagic units are rare or absent. Reservoir facies consist of massive, amalgamated, coarse turbidite and grain flow units that are up to 100 ft (30 m) thick and confined to narrow, deep, leveed submarine channels. Interbedded mudflow units interrupt vertical continuity of sandstone within the channel fills. The trend and location of channel axes were controlled by the morphology of the enclosing canyon; the reservoirs form a series of offset, vertically superposed shoestrings within the muddy, onlapping, canyon fill. Adjacent deposits include heterolithic levee and overbank turbidites and current-reworked siltstone and fine sandstone. Levees were muddy, developed high relief, and locally collapsed as slides and slumps. Rotated slide blocks of pre-canyon delta-front sediment occur at the base of the canyon fill.

ABSTRACT The Pliocene-Pleistocene sequence cored in the Ewing Bank 826 Field in the Gulf of Mexico provides an example of sand distribution and reservoir quality produced by reworking by deep-marine bottom currents. A distinctive attribute of reworked sands is their traction bedforms. Common sedimentary features of traction currents include small-scale cross-bedding, starved current ripples, horizontal lamination, sharp upper contacts, and inverse size grading. The sands also exhibit internal erosional surfaces and mud-offshoots indicating oscillating current conditions. Presumably, the Loop current, a strong wind-driven surface current in the Gulf of Mexico, impinged on the sea bottom, as it does today, and reworked sand. A depositional model based on the integration of core, wireline log, and 3-D seismic data suggests that the reworked sediment package may be thick and continuous, but individual sand layers within the package may be thin and discontinuous. This model, which depicts the distribution of bottom-current reworked sand in interchannel slope areas as a distinctly different facies from channel-levee facies, has the potential for general application to other deep-water plays outside the study area. In the Ewing Bank 826 Field, the Type 1 (L-l) reservoir with 80% sand exhibits higher permeability values (100-1800 mD) than the Type 2 (N-l) reservoir with 26% sand (50-800 mD). The increased permeability in the Type 1 sand has been attributed to high sand content, vigorous reworking, and microfractures. The clean, porous and well-sorted Type 1 sands with good communication between sand layers have produced at higher rates and recovery efficiencies than the Type 2 sands with numerous interbedded mud layers.

ABSTRACT Jolliet Field reservoirs, discovered 1981, are middle to upper Pleistocene intraslope turbidites complicated by rapid deposition, sea level fluctuations, salt movement, and structural complexities. Seven exploratory wells integrated with 3-d seismic coverage allowed for geological, geophysical, and petrophysical description of the reservoirs. Subsequent drilling of 20 development wells provided additional data and prompted the recognition of a significant thrust fault. Production began from the field in November, 1989. High initial rates with rapid declines were characteristic of the reservoirs, especially in the subthrust and faulted east flank. This behavior is attributed to reservoir compartmentalization and lack of aquifer support. Completions in the less faulted western flank have been much better performers. Produced oils have ranged 20 to 60 degrees in API gravity, and some oils are paraffinic. Notable technical successes in the field include the predrilling of 20 development wells under time and under budget, the installation of the first tension leg well platform in the Gulf of Mexico in what was at the time a water depth record for a production platform (1760 feet), gravel packs of fine grained zones, and the use of selective completions. Significant concerns include the poor performance of some reservoirs and the production of paraffin. Core from two wells in the field provide insight into the depositional processes responsible for the accumulation of two of the reservoir sands, the HJ sand and the KE sand. The HJ sand was cored in Green Canyon well 184 #7. The unit shows a succession of lithofacies that are consistent with development from either a small, migrating, channel-levee-overbank system or a prograding channel/lobe system. A succession of similar scale in a Paleocene submarine canyon fill exposed at Point Lobos, California, provides a possible analogue. Abundant graded beds and Bouma sequences indicate that the uppermost and lowermost parts of the HJ sand were deposited predominantly from turbidity currents, and an intensely ripple-laminated middle interval represents reworking either at a hydraulic jump or by contour currents. In contrast, the KE sand seems more to have resulted from debris flows, at least in its occurrence in the Green Canyon well 184 A-1. Mud-clast breccia or conglomerate is common throughout the core, and the sand beds are more massive and lack Bouma sequences. In the Green Canyon 184 #7 sidetrack well, the KE sands are better stratified and may have been more influenced by deposition from turbidity currents.

ABSTRACT Auger Field is a 1987 deepwater discovery located 214 miles (344 km) southwest of New Orleans, Louisiana. The field consists of five productive horizons with the lowermost "S" sand reservoir containing an estimated 120 MMBOE, which is over half of the total field reserves. The Miocene "S" sand is oil productive from layered and amalgamated sheet sands that were deposited in the Auger minibasin. Onlap onto a paleoridge and faulting are the trapping mechanisms. The sands thicken into the basin away from the onlap as evidenced by both well and seismic data. The seismic data further indicate that the sands extend below the oil/water contact and should provide some aquifer support for pressure maintenance. The accumulation has a 1200 ft (366 m) hydrocarbon column based on an estimated oil-water contact from seismic at -19,650 ft (5990 m). The "S" sand is mostly a slightly consolidated, lower fine-grained sand with average porosity and permeability of 25 percent and 150 millidarcies, respectively. Production began in 1994 from a tension leg platform located in 2,862 ft (872 m) of water. High individual well rates have been established from these laterally continuous sands with average rates of 10 MBOPD and 20 MMCFGPD.

Abstract Ram/Powell field is an example of a passive margin deep-sea fan stratigraphic trap. Deposition of the Ram fan was controlled by sea level lowstand, intraslope basin geometry, and a point-source deltaic sediment supply. Multiple elongate lens-shaped fanlobes have been interpreted using 3D seismic, conventional-core, and well log data. Seismic reflection clinoform configurations indicate lithofacies distribution within the fanlobes. The reservoirs are trapped by stratigraphic pinch out of channel and levee-overbank sands. The best quality reservoirs are associated with channel-levee deposits, that are dominated by thick, fine-grained, massive turbidite sands.

ABSTRACT Fifty-three feet of whole core were taken from the Marathon #2 well in Garden Banks Block 171, Offshore Louisiana, Gulf of Mexico to determine reservoir characteristics, detailed lithology and depositional environments of the middle Pleistocene Trimosina A zone. The Trimosina A zone was previously evaluated in the Marathon #1 well in Garden Banks Block 215 with wireline logs, sidewall cores and repeat formation tester pressures and samples. In the GB 215 #1 well, the Trimosina A contains 79 net ft of oil-filled, finely laminated, very fine-grained sand and silt interbedded with shale with good reservoir pressure, an average porosity of 27% and estimated permeabilities of 50-1120 millidarcies. In the GB 171 #2 well, conventional Cores 1 and 2 were taken below a 20 ft oil sand and contain mostly shale, but also unexpected amounts of poorly lithified, finely laminated silt filled with oil. Core 3 was taken near the base of the thickest oil sand (40 ft thick) in the well and contains unconsolidated, interlaminated, well-sorted, subangular to well-rounded silty sand and massive, medium-grained, angular to well-rounded, moderately to moderately-well sorted sand. The average porosity of the oil sand in Core 3 is 27.9% and the geometric mean of the core plug permeability measured under 2,000 psi confining pressure is 671 millidarcies. The amount of dip in the cores was considerably higher than that of seismically visible horizons. The cores preserve irregular and anomalously high dips ranging from 50 to 60 degrees as well as gentler dips of 10 to 20 degrees. Images as well as structural attitudes were evaluated from the Formation Microscanner log (FMS) and confirm those observed in the core. In addition to confirming dip measurements in the cores, the FMS images show detailed dip patterns that were not evident from the dipmeter. While the dips are irregular and anomalously high, dips are consistent over 5 to 20 ft intervals. Furthermore, the cores show deformation features such as fine-scale folds, soft-sediment shearing and non-horizontal, closely-spaced fractures in Cores 1 and 2. Core 3 shows contorted laminations. The nature of the dips and the structures in the core indicate that the Trimosina A zone has been deformed into small, rotated blocks. This results in compartmentalizing the hydrocarbons which was corroborated by the drill-stem test results. Primary sedimentation structures in all three cores are too deformed to suggest much about depositional environments. In summary, whole core from the Marathon #2 well in Garden Banks Block 171, Offshore Louisiana, Gulf of Mexico, was crucial to understanding poor reservoir potential from good reservoir quality sand and economically disappointing hydrocarbon recoveries from drill-stem tests of the middle Pleistocene Trimosina A zone.

ABSTRACT Twenty-nine feet (8.8 meters) of lower Pleistocene core material were recovered by Marathon Oil in its Green Canyon Block 154 #1 well, offshore Louisiana, in order to more fully evaluate the exploration program being drilled by Marathon and its partners in this deep-water locality of the Gulf of Mexico. From the mid- to late-1980s, the partnership drilled seven wells within four miles of Shell Offshore Incorporated's newly-discovered Bullwinkle Field. Oil and gas pay zones were penetrated in the Plio-Pleistocene of these wells, and Marathon took the core to complete a reservoir characterization study that included evaluating wireline logs, drill stem tests and extensive seismic modelling in addition to the core analysis. The cored sediments are part of a larger unit of thinly bedded, fine-grained turbidites deposited in lower bathyal water depths on the edge of a Plio-Pleistocene salt withdrawal sub-basin. This interval is comprised of base-absent Bouma sequences (stacked T b -T e cycles), and contain parallel planar, undulose and rippled laminations. Sand beds are no more than five inches thick. The cored interval has a characteristic log signature for low contrast/low resistivity pay commonly found in laminated silt/sand/shale lithofacies. Drill stem tests of this unit yielded an average flow of 1391 barrels of oil/day and 1040 thousand cubic feet of gas/day on a 20/64 inch choke.

ABSTRACT Conventional cores from four wells in the High Island A-537 field were examined, described, and sampled for sedimentologic, biostratigraphic, and kerogen analyses. The cores were recovered from the reservoir interval between the Discoaster surculus and the Discoaster tamalis Condensed Sections. 531 feet of core was examined of which 126 feet was sandstone, the remainder being siltstone and mudstone. Sedimentary features included massive sandstone, graded very fine-grained sandstone, laminated silty sandstone, laminated silty mudstone, massive mudstone, siltstone and mudstone couplets, rip-up clasts floating within the sandstone, convolute laminations, and climbing ripples. Sandstone and siltstone contain inner to middle neritic foraminifera while encasing mudstones have middle bathyal foraminiferal assemblages. Isolated kerogen analysis showed that over 80% of the kerogen was of terrestrial, woody origin. Paleogeographic reconstruction of the reservoir interval suggests deposition within in a salt-bounded submarine valley thirty-five miles from the age equivalent shelf-edge. All stratigraphic and sedimentologic data indicate that these sediments were deposited during a relative sea level lowstand by gravity-flow processes in a Lower Pleistocene to Upper Pliocene intraslope valley system.

Abstract Many of the major factors that control diagenesis, such as detrital composition, fluid composition, and fluid flux, can be related directly or indirectly to physical and biological processes operating at the time of deposition. Each depositional environment produces a lithofacies with a specific limited range of physical and compositional characteristics that affect diagenesis. The concept of diagenesis as a function of facies is well illustrated by the second Frontier sandstone of the Moxa Arch, Wyoming. The lower Frontier Formation on the Moxa Arch comprises sandstones and mudstones deposited in a delta/strand plain system on the western edge of the interior Cretaceous seaway. Depositional environments represented by the rocks include: marine shelf with sand ridges, marine shoreline, fluvial channels, and fluvial flood plain. Marine sandstones are significantly more quartzose than fluvial units because of sorting within the delta and wave abrasion on beaches. Substantial input of silica-rich water expelled from the underlying Aspen Shale caused nearly complete cementation of the cleaner beach and backshore sandstones by quartz overgrowths. Fluvial sandstones contain less quartz and more chert grains and rock fragments than the marine sandstones, and as a result, were less affected by quartz cementation. In addition, temporary filling of pores by calcite prevented further irreversibly destructive diagenesis. As a result, fluvial sandstones are better reservoirs, even though they are compositionally less mature. Clay-rich sandstones of the lower shoreface, lower sections of the sand ridges, and muddy fine-grained fluvial sandstones have poor present-day porosity and permeability primarily because of compaction. Fluid flux also appears to have played an important role in determining present-day porosity and permeability profiles. Because of a very low sandstone/shale ratio, fluid channeling in fluvial sandstones on the southern end of the Moxa Arch seems to have caused extreme leaching. The sandstone section here, although it is very thin, is very permeable. To the north, a higher sandstone/shale ratio appears to have permitted a lower fluid throughput per unit volume of sand. As a result, fluid channeling was not as severe, detrital and authigenic clays are more common, and the sandstone section is more homogeneous and of lower overall permeability.