Production characteristics of sheet and channelized turbidite reservoirs, Garden Banks 191, Gulf of Mexico

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1 CORNER INTERPRETER S Production characteristics of sheet and channelized turbidite reservoirs, Garden Banks 191, Gulf of Mexico DAVID S. FUGITT, JAMES E. FLORSTEDT, GARY J. HERRICKS, and MICHAEL R. WISE, Chevron North American E&P Company, Lafayette, Louisiana, U.S. CHARLES E. STELTING, Chevron Petroleum Technology Company, New Orleans, Louisiana, U.S. WILLIAM J. SCHWELLER, Chevron Petroleum Technology Company, San Ramon, California, U.S. Coordinated by Linda R. Sternbach Turbidite sands form the main reservoirs for deepwater fields in the Gulf of Mexico and many deepwater fields throughout the world. Garden Banks 191 Field is a deepwater discovery that, while fairly new, can relate depositional characteristics of reservoirs to an extensive production history. Of particular interest are production Figure 1. Garden Banks Block 191 is part of GB 236 Field, in 700 ft of water about 160 miles southeast of Lafayette, Louisiana, U.S. characteristics of the 4500-ft sand, a turbidite sheet, and the 8500-ft sand, a turbidite channel. These reservoirs have produced more than 210 billion ft 3 since This study provides valuable insights into how different types of turbidite sands produce through time. Garden Banks Block 191, part of GB 236 Field, is in 700 ft of water about 160 miles southwest of Lafayette, Louisiana, U.S. (Figure 1). Chevron and partners drilled the field discovery in It found gas trapped by an updip pinchout of the 4500-ft sand onto a shale-cored high. The initial discovery has produced 220 billion ft 3 to date. The accumulation at Block 191 was drilled as a field extension in The stepout was designed to test two amplitude anomalies that terminated updip onto a salt cored high. The shallower anomaly had been drilled by Shell in Shell found gas in the 4500-ft sand; however, it deemed it uneconomic and released the block. Chevron and Unocal acquired Block 191 in the 1983 lease sale. The initial stepout, drilled by Chevron, found gas in the ft sand but was unable to reach the deeper anomaly. A second well, suspended in January 1990, tested the deeper amplitude and discovered the 8500-ft sand accumulation. Ten wells have been drilled to date. The main reservoir of the 8500-ft sand has produced 121 billion ft 3 since production began in The 4500-ft sand began producing a) Figure 2. Depositional model. Diapirs formed topographic highs and lows on the slope, trapping sand transported downslope from lowstand deltas to the north. Dip-oriented salt ridges funneled sand-rich turbidite flows into the area. Sand was trapped on the north flank of a strike-oriented shale ridge at block 236 and on the north flank of a salt diapir at block 191. b) Figure 3. Depositional model Garden Banks 191 (cross-sectional view). Sand was trapped on the north flank of a strike-oriented shale ridge at block 236 and on the north flank of a salt diapir at block 191. As the north flank minibasin continued to subside (a) due to continued loading and withdrawal, the 4500-ft interval was rotated, and gas was trapped (b) by the updip shaleout of the sand to the south. 356 THE LEADING EDGE APRIL 2000 APRIL 2000 THE LEADING EDGE 0000

2 in June 1994 and has produced 87 billion ft3 to date. The 4500-ft and 8500-ft sands are Pleistocene (Illinoian) turbidities deposited during relative lowstands of sea level. Both salt and Plio-Pleistocene-age shale mobilized into diapirs and ridges due to rapid sediment loading. The diapirs formed topographic highs and lows on the slope, trapping sand transported downslope from lowstand deltas to the north (Figure 2). Dip-oriented salt ridges funneled the sand-rich turbidite flows into the Garden Banks 236/191 area. The sand was trapped on the north flank of a strike-oriented shale ridge at Block 236 and on the north flank of a salt diapir at Block 191. As the north flank minibasin continued to subside due to continued loading and withdrawal, the 4500-ft and 8500-ft intervals were rotated, and gas was trapped, by the updip shaleout of the sands to the south (Figure 3). The 4500-ft sand was deposited as a turbidite sheet sand in a lowstand system tract above the 0.85 M.Y. sequence boundary. Equivalent lowstand shelf edge deltas are 10- Figure 4. Seismic depth section showing productive intervals at Garden Banks 191. Note the flat spots at the 4500-ft and 8500-ft sands. Wells A1 and A6 are shown. See Figure 5 for orientation of the seismic profile. 15 miles to the north, where they compose the main reservoirs at West Cameron 638 and 643 fields. The 4500-sand interval is 1000 ft thick an easy event to recognize on seismic. The interval is 75-90% sand, deposited over a large portion of both blocks 191 and 147. At Garden Banks 236, the 4500-ft interval has ft of sand, in several lobes, near the top of the unit; the lower part of the section is shaly. The 8500-sand, part of the lowstand system tract above the 1.2 M.Y. sequence boundary, is restricted to the Garden Banks 191 structure. The paleoshelf edge was farther north. The salt withdrawal minibasin north of the 191 dome trapped sand from turbidity flows originating on the shelf. The 8500-ft interval sands are localized channels in a small withdrawal basin just north of the salt. As happened during the 4500-ft interval, the minibasin continued to subside, and a trap was formed by the updip shaleout of the sand. A seismic depth section (Figure 4) shows the present structure of the 4500-ft and 8500-ft sands at block 191. The gas-water contacts in each sand are flat spots on seismic. Both the 4500-ft and 8500-ft sands produce almost pure methane, probably biogenic gas. The gas was probably sourced from the surrounding shales. Not much associated liquid has been produced with the gas, although the offsetting Tick Field, six miles to the west, has produced both oil and gas. The gas columns in both the 4500 and 8500 reservoirs extend ft. The long gas columns are interpreted to be the result of a trapping mechanism connected to shaling out of sands southward and not to faulting along the flank of the salt or related to paleoshale highs ft sand (sheet sand reservoir). The 4500-ft sand accumulation at Garden Banks 191 is trapped on a north plunging nose by stratigraphic shale-outs and faulting to the south, west, and east (Figure 5). However, on block 236, gas is trapped as a updip pinchout on a shale ridge. The 4500-ft sand is supported by a strong water drive; however, there was some initial decline in pressure as high production rates outran the water. A log from well A6 shows the sand divided into four members by shale beds corre- Figure 5. (above) Structure map on the 4500-ft sand showing A1, A5, A6, A10, and Shell 1. Well symbols are shown at the penetration point for the 4500-ft sand. (right) Areal extent of the amplitude and reservoir. Note location of cross-section A-A (Figure 9), and seismic section S-S (Figure 4). 358 THE LEADING EDGE APRIL 2000 APRIL 2000 THE LEADING EDGE 0000

3 latable throughout the reservoir area (Figure 6). Shale breaks disappear in downdip wells, grading into a continuous sandy section. All four members have a common gas-water contact at subsea. The gas-water contact is a pronounced flat spot on seismic. The 4500-ft sand is continuous and wet in downdip wells, becoming more than 800 ft thick and providing a large aquifer below the gas accumulation. The updip shaleout of the 4500-ft sand is very sharp. Seismic coherency helped define the updip limit of the sheet flows and in placement of attic gas wells. A clear example is from block 236 where the 4500-ft sand pinches out on a shale-cored high. Figure 7 shows the updip termination of the ft sand in block 236 on a coherency horizon slice. The coherency horizon slices were Figure 6. Type log from A6 for the 4500-ft sand showing members 1-4. The reservoir divided into four members by shale beds correlatable throughout the reservoir. Shale breaks disappear in downdip wells, grading into a continuous sandy section. generated by flattening the 3-D seismic on a continuous event above the 4500-ft sand. A coherency cube was generated from the flattened seismic file. Slices through the flattened volume clearly show the sharp updip pinchout of the 4500-ft sheet flows. Borehole imaging and core of the 4500-ft sand. The ft sand reservoir interval is composed of interbedded, turbidite sands and shales. Individual turbidite sand beds range from 2.5 in. to 8.5 ft in thickness, with most beds being less than 2.0 ft. (Figure 8). The sedimentary character of beds in Garden Banks 191 is consistent with bedding and facies associations described by Mahaffie (1994) for Mars Field (Mississippi Canyon 807); i.e., amalgamated and layered sheet sands. Three facies types are identified in core and borehole images: thick-bedded sands, thin-bedded sands, and laminated shales. Thick-bedded (>2 ft) sands tend to have erosive bases and load casts. Internally, they exhibit massive, inclined, and planar laminae; they are rich in organics locally, especially when associated with the inclined strata. Thin-bedded (<2 ft thick) sand lithofacies are shale-dominated; net-to-gross is generally less than 50%. Sand beds, which tend to be less than six inches thick, are ripple to wavy laminated, and less commonly, horizontally laminated. Macerated, chewed up, organics are very common along the bedding planes. Laminated shales are classified as graded mud couplets (silty clay to clay); starved sand ripples are a common component. Burrows occur locally but are relatively rare. Sedimentary structures observed in these three facies are a combination of high-to-moderate energy, low energy, and muddy turbidity currents. The lack of chaotic bedding suggests that relatively organized tur- Figure 7. Flattened coherency horizon slice showing updip shaleout of the 4500-ft sand at Garden Banks 236. (Courtesy of Diamond Geophysical). 360 THE LEADING EDGE APRIL 2000 APRIL 2000 THE LEADING EDGE 0000

4 Figure 8. Borehole image log from the 4500-sand in A6. Scale on right. Three facies types are identified in core and borehole images: thick-bedded sands, thin-bedded sands, and laminated shales. Thin-bedded facies is on the left; thick-bedded facies on right. The sedimentary beds are amalgamated and layered sheet sands. bidite deposition occurred throughout the 4500-ft sand deposition. At the reservoir scale, the 4500-ft sand consists of relatively thin sheet sands punctuated by thicker lobes and small channel deposits, composed of both thick- and thinbedded sands. The laminated shale facies occurs as both an intraformational facies and as a continuous drape over the top of each reservoir unit. The shale drape is a critical factor as it controls fluid flow through the reservoir and relates to the productivity of this reservoir. Electric log evaluations typically underestimate the effective porosity and overestimate the water saturation in the thin-bedded facies, leading to an underestimation of reserves. Analysis of sand/silt beds in 86 sidewall cores from two wells indicates a wide range of reservoir quality. Porosity ranges from 16.7 to 33.5% with an average of 25.5%. Permeability values extend from 0.6 to 2520 md, averaging 427 md. Crossplots show that porosity and permeability vary primarily in response to grain-size changes, a relationship typical of deepwater turbidites in the Gulf of Mexico. Also, the best reservoir quality in the 4500-ft sand (>29% porosity and >550 md) is associated with the thicker, clean sands lacking clay. These sands are the most prominent on well logs ft sand water encroachment and depletion. Three wells (A5, A6, and A10) have a combined production of more than 87 billion ft 3 from the 4500-ft sand since June A5 and A6 were drilled in 1994; A10 was drilled in 1998 to recover attic gas reserves. A6 was a dual completion, with the long string in member 4 and the short string in member 3 of the 4500-ft sand. A5 was dually completed in members Figure 9. Seismic line through the 4500 reservoir showing continuity of reflectors, and cross-section A-A through the 4500-ft sand. Seismic events are continuous through the reservoir interval due to lateral continuity of beds within the 4500-ft sand. Continuous shale breaks, formed by thick packages of laminated shale, limit vertical permeability and constrain water encroachment within the reservoir. This causes the individual members to act as separate flow units during production. 1 and 2. Lack of pipeline capacity delayed the completion of A5 and caused the rate to be cut back slightly from the well s capability. Figure 9 shows a close-up seismic section and a log crosssection through the 4500-ft reservoir. Seismic events are continuous through the reservoir interval, the result of lateral continuity of beds within the 4500-ft sand. Depositional characteristics can be anticipated from seismic and borehole data and used to guide the completion strategy. The depositional characteristics of the 4500-ft sand control the way the reservoir produces. Areal extent and lateral continuity of the turbidite sheet flows provide a connection to a large downdip aquifer, resulting in strong water drive. The continuous shale breaks, formed by thick packages of laminated shale, limit vertical permeability and constrain water encroachment within the reservoir. This causes the individual members to act as separate flow units during production. The production history of A6 and A5 illustrates how the shale beds separate the sand into multiple flow units. Bottom hole pressures, and timing of water breakthrough, suggest the existence of three flow units. Members 1 and 2 acted as a single flow unit; members 3 and 4 are the two other flow units. Member 3 watered out in A6 in June Member 4 continued to produce until May This shows that members 3 and 4 were acting independently. In November 1995, A5 was tested in member 3 and completed in members 1 and 2. Member 3 showed a reduced pressure from the production in A6. Members 1 and 2 were at original formation 362 THE LEADING EDGE APRIL 2000 APRIL 2000 THE LEADING EDGE 0000

5 pressure. Bottom-hole pressures in members 1 and 2 have tracked each other in A ft sand (channel reservoir). Figure 10 is a map of the 8500-ft sand. The amplitude outline gives a good indication of the extent of the sand in an east-west direction. A gas/water contact at 9090-ft subsea limits the reservoir to the north. The stacked channels of the 8500-ft sand were deposited in a local salt withdrawal basin north of a salt diapir in block 191. The 8500-ft sand is divided into five Figure 10. Structure map on the 8500-ft sand. Well symbols are shown at the penetration points for the 8500-ft sand. Shaded area shows areal extent of amplitude associated with the 8500-ft sand. Note location of cross-sections B-B (Figure 12) and C-C (Figure 13b). members, separated by shale breaks (Figure 11). Member 3 was further divided into upper, middle, and lower units based on shallow, perched water contacts. Members 1 and 2 make up the upper, or abandonment phase, of the channel fill. Members 3-5 make up the lower part of the channel fill. The divisions were partly based on geology and partly to facilitate volumetric reserve estimation. Figure 12 shows that individual sand lobes and shale breaks do not correlate on logs across the reservoir. A seismic line through the reservoir (Figure 13a) shows a complex reflection pattern of onlap and downcutting reflecting the lateral variation of the individual channels within the 8500-ft sand (Figure 13b). RFT pressures taken before production show that the gas column in members 3-5 are vertically connected; an interpreted gas-water contact is at ft subsea (Figure 14). Pressures taken in A7, which encountered member 5 updip, showed that it is also connected to members 3 and 4. RFT pressures in the abandonment phase of the system (members 1 and 2) show they are in a separate reservoir. Several RFT pressures taken in the water leg below one of the perched water contacts show the perched water is in communication with the gas column but is not directly connected to the downdip aquifer. The production history, RFT pressures, distribution of perched water contacts, and difficult log correlations between wells suggest that the 8500-ft sand is a channelized turbidite reservoir with good vertical connectivity but poorer lateral connectivity. A flattened coherency slice through the third member (Figure 15) shows a channel in this succession and supports this interpretation. The perched water legs probably form in channels that pinch out laterally before reaching the main water level. Perforations immediately above one of these contacts in Figure 11. (left) Type log for the 8500-ft sand. The sand is divided into five members, separated by shale breaks. Member 3 was further divided into upper, middle, and lower units based on shallow, perched water contacts. Members 1 and 2 make up the upper, or abandonment, phase of the channel fill. Members 3-5 make up the lower part of the channel fill. (a) (right) Amplitude extraction of the 8500-ft sand. 364 THE LEADING EDGE APRIL 2000 APRIL 2000 THE LEADING EDGE 0000

6 Figure 12. Stratigraphic cross-section of the 8500-ft sand hung on the 3U member, showing lateral variation between wells in members 3 and 4. Compare the gas-water contact at 8750-ft subsea in lobe 3M in A2 with the gas-water contact at ft subsea in lobe 3M in 2. Individual sand lobes and shale breaks do not correlate on logs across the reservoir. a) A2 produced free water with no influx from the perched water leg. Depositional interpretation of the 8500-ft sand. The ft sand is interpreted as a 900 ft thick fining-upward channel succession, deposited in a slope minibasin formed by salt withdrawal. The lower part of the channel fill is dominated by thick, 3-12 ft, massive, fine- to medium-grain sand based on core and borehole image data. Concentrations of rip-up clasts several feet thick are common along the erosional bases of individual flow events and also occur suspended within the deposits. These facies are inferred to be the product of sandy turbidity currents and other highconcentration sediment gravity flows (Lowe, 1982; Stelting et al., 1998). The succession is punctuated periodically by lower energy facies such as laminated sandstone and siltstone, interlaminated siltstone and shale, and homogeneous to laminated shale. These finer-grained deposits represent thin-bedded and muddy turbidites. Production data has been used to determine that bed length of finer-grained, muddy beds is less than bed length of more massive sands. This condition is common in submarine channel deposits (Cook et al., 1994; Clark and Pickering, 1996). The upper part of the channel fill has a lower net-to-gross than the lower, main reservoir interval and is inferred to consist of stacked channel-levee complexes accumulating as late stage depositional energy declined. Reservoir quality estimates based on sidewall cores show a result similar to that found in the 4500-ft sand. Thicker, clean sands have high porosity and permeability values; thin, shaly beds have low values. Even though the net-to-gross is lower in the upper units, sands sampled in sidewall cores still have moderate porosity (24-29%) and permeability ( md). Continuous core was critical in estimating reserves, selecting intervals to perforate, and designing a development strategy for this channel sand reservoir. Electric log evaluations in thick sands with abundant shale rip-up clasts underestimated the reservoir quality of this facies. The shale clasts appeared as dispersed clay to the logging tools, instead of shale within a clean sand matrix. The b) Figure 13. (a) Seismic line through the 8500-ft sand showing complex reflection pattern and (b) cross-section C-C showing water encroachment through the 8500-ft sand. Solid bars show perforated intervals. RFT pressures taken before production commenced show that the gas column in members 3-5 are vertically connected. Figure 14. RFT pressures taken in the 8500-ft sand from four wells. Pressures from members 3-5 line up along a single gradient. Pressures from members 1 and 2 have a similar slope but line up at higher pressures. A perched water leg from A3 shows a water gradient connected to the gas column ft sand effective porosity was underestimated, and the water saturation was overestimated, leading to lower reserve estimates ft sand production drainage as seen on seismic. The 8500-sand has produced a total of 121 billion ft 3 from three 366 THE LEADING EDGE APRIL 2000 APRIL 2000 THE LEADING EDGE 0000

7 a) Figure 15. The production history, RFT pressures, distribution of perched water contacts, and difficult log correlations between wells, suggest that the 8500-ft sand is a channelized turbidite reservoir with good vertical connectivity but poorer lateral connectivity. A flattened coherency slice through the third member shows a channel in this succession and supports this interpretation. wells (A1, A2, and A3) since November An additional well, A7, was drilled in 1998 to recover attic gas. The initial combined rate of 150 million ft 3 /d from the three wells has declined steadily through time. Throughout most of its production history, the 8500-ft sand behaved as a pressure depletion reservoir. Initial formation pressure of 4750 psi declined to 1300 psi by In 1997, water arrived successively at A2 (April), A3 (September), and A1 (October). Water influx indicated a weak water drive and led to the decision to drill A7. A7 was designed to recover updip reserves in members 3 and 4 and to target suspected updip gas in member 5, which was wet in A1. A seismic line and cross-section through A7, A1, A3 is shown in Figure 13. A seismic flat spot was interpreted to mean that the member 5 sand channel was 1200 ft wide and co tained gas updip. A7 did encounter a massive sand from 8500-ft subsea to total depth (9195-ft subsea). This was interpreted to be an amalgamation of members 4 and 5. Member 3 was shaled out. A7 encountered a gas-water contact at 8681-ft subsea, 360 ft above the perforations simultaneously producing gas from A1. A7 saw 378 feet of residual gas below the gaswater contact at 8681 ft subsea SS and evidence of an original gas-water contact at 9059 ft subsea consistent with the seismic flat spot. b) Compartmentalization of 8500-ft sand production. Vertical connectivity has allowed the 8500-ft sand to act as a single tank and allowed the existing wells to effectively drain the gas reserves. The shale beds, which separate the individual members and channels, have acted as baffles within the reservoir. The gas was able to move around the baffles and be produced from the existing wells. If the reservoir fluid had been oil, there would have been much greater potential for bypassed reserves, and more wells would have been needed to drain the reservoir. Recovery efficiencies for oil would have been much lower because of the pressure depletion and weak water drive exhibited by the 8500-ft reservoir. The lateral extent of the individual channels limits the lateral connectivity. Each member contains several individual channels, which may or may not be laterally con- Figure 16. Production plots comparing the 4500-ft and 8500-ft sands. (a) Plot of rate versus time for two representative completions 4500 member 4 in A6 and 8500 member 4 in A1. (b) P/Z versus cumulative production for both the 4500-ft and 8500-ft sands. Both sands show high initial flow rates although the ft sand has a higher productivity because of its higher initial pressure and the more massive nature of the channel sands. nected. Initial RFT pressures and bottom hole pressures taken over several years show the stacked channels are acting as a single tank. The shale breaks separating the members and channels are not correlative across the reservoir, but they have controlled water influx in individual wells. The weak water drive suggests the downdip aquifer is relatively small. The pattern of water influx illustrates the combination of good vertical connectivity and poorer lateral connectivity within the reservoir. The reservoir produced for three years before water entered A2. The water that successively hit A2, A3, A1 wells came in from the edge of the reservoir along the lower part of member 4. At A1, there was no influx of water from the massive wet member 5 sand. The shale break between members 4 and 5 at that location prevented the water from entering A1. At A7, where members 4 and 5 coalesced into a single massive sand, the water contact moved upward 378 ft from an original gaswater of 9059-ft subsea to a current gas-water of 8681-ft subsea. A1 actually drew gas downdip from A7. Conclusions. Different reservoir architectures of the ft and 4500-ft sands have resulted in different production histories. Figure 16a shows flow rates for representative completions in both sands. Figure 16b shows the P/Z plots versus cumulative production for both reservoirs. Both sands show high initial flow rates although the 8500-ft sand has a higher productivity due to its higher initial pressure 368 THE LEADING EDGE APRIL 2000 APRIL 2000 THE LEADING EDGE 0000

8 and the more massive nature of the channel sands. The 4500-ft sand shows lower decline rates, but production falls rapidly once water enters the completion. The P/Z plot of the 4500-ft sand is more complex since the different members depleted individually; however, the plot is much flatter, which is typical of water drive reservoirs. The P/Z of the 8500-ft sand shows a more linear decline, typical of pressure depletion reservoirs. The following observations can be made from the production history of the turbidite sands at Garden Banks 191: 1) These turbidite sands are excellent reservoirs, capable of high flow rates and high recovery efficiencies. Interaction of basin configuration and turbidite depositional processes created reservoir geometry, aquifer size, and drive mechanisms for the 4500-ft and 8500-ft sands. 2) Seismic coherency was useful in defining the updip limits of the reservoirs and in placing attic wells. 3) The continuity of the shale breaks within the reservoirs controlled the influx of water as the sands produced. In the 8500-ft sand, shale bed lengths were less than the reservoir extent and formed baffles in the reservoir. In the 4500-ft sand, shale bed lengths extended across the reservoir and caused the individual members to act as separate flow units. Understanding the distribution of the fine grained and muddy facies was very important to designing a development and completion strategy for both the channel (8500-ft) sand and sheet (4500-ft) sand. 4) Conventional core and borehole imaging logs were critical to evaluating the quality of the reservoirs prior to development. Reserves would have been significantly underestimated without this data. 5) RFT pressures were critical to evaluating the connectivity of the 8500-ft reservoir and in designing a development strategy. David Fugitt is staff geologist with Chevron in Lafayette, Louisiana, U.S. He joined Chevron in Fugitt received a bachelor s degree in geology from Ohio State University in 1976, and a master s from Texas A&M University in William Schweller has worked in petroleum research with Gulf and Chevron since 1982, primarily studying turbidite reservoirs and sequence stratigraphy of deepwater systems. Charles Stelting has been a regional and reservoir stratigrapher/sedimentologist specializing in deepwater depositional systems at Chevron since He received a bachelor s degree in geology from Texas A&M University, Kingsville, in 1980 and a master s degree from University of California, Riverside in Gary Herricks has 20 years of experience in reservoir engineering. Gary has been with Chevron since He received a bachelor s degree in petroleum engineering from Texas Tech University in Michael R. Wise is a senior petroleum engineer with Chevron USA Inc. and is currently working in the Gulf of Mexico Business Unit of the North American E&P Company. Wise has almost 22 years of combined experience with Gulf and Chevron and has worked in both the Gulf of Mexico and the Permian Basin regions, primarily in production and reservoir engineering Suggestions for further reading. Submarine Channel Processes and Architecture by Clark and Pickering (Vallis Press, London, 1996). Facies architecture and reservoir characterization of a submarine fan channel complex, Jackfork Formation, Arkansas by Cook et al. (in Submarine fans and turbidite systems: sequence stratigraphy, reservoir architecture, and production characteristics, GCSSEPM 15th Annual Research Conference, 1994). Sediment gravity flows: II. Depositional models with special reference to the deposits of high-density turbidity currents by Lowe (Journal of Sedimentary Petrology, 1982). Reservoir classification for turbidite intervals at the Mars discovery, Mississippi Canyon 807, Gulf of Mexico by Maffie (in Submarine fans and turbidite systems: sequence stratigraphy, reservoir architecture, and production characteristics). Production characteristics of sheet and channelized turbidite reservoirs, Garden Banks 236 Field, Gulf of Mexico by Stelting et al. (EAGE/AAPG Third Research Symposium). Production characteristics of sheet and channelized turbidite reservoirs, Garden Banks 191, Gulf of Mexico, U.S.A. by Fugitt et al. (Gulf Coast Association of Geological Societies Transactions, 1999). LE Acknowledgments: We thank Chevron and Spirit Energy for permission to publish this paper (a similar article was previously published in GCAGS Transactions in 1999). We also thank Mark Zastrow for helpful comments and insight into the regional geology, and we thank Scott Turner for his help with the RFT data. Corresponding author: dfug@chevron.com 000 THE LEADING EDGE APRIL 2000 APRIL 2000 THE LEADING EDGE 369