production characteristics of sheet and channelized turbidite ...bidite sands and shales. individual...

Turbidite sands form the main reservoirs for deepwaterfields in the Gulf of Mexico and many deepwater fieldsthroughout the world. Garden Banks 191 Field is a deep-water discovery that, while fairly new, can relate deposi-tional characteristics of reservoirs to an extensiveproduction history. Of particular interest are production

characteristics of the 4500-ft sand, a turbidite sheet, andthe 8500-ft sand, a turbidite channel. These reservoirs haveproduced more than 210 billion ft3 since 1993. This studyprovides valuable insights into how different types of tur-bidite sands produce through time.

Garden Banks Block 191, part of GB 236 Field, is in 700ft of water about 160 miles southwest of Lafayette,Louisiana, U.S. (Figure 1). Chevron and partners drilledthe field discovery in 1977. It found gas trapped by anupdip pinchout of the 4500-ft sand onto a shale-cored high.The initial discovery has produced 220 billion ft3 to date.The accumulation at Block 191 was drilled as a field exten-sion in 1988. The stepout was designed to test two ampli-tude anomalies that terminated updip onto a salt coredhigh. The shallower anomaly had been drilled by Shell in1976. Shell found gas in the 4500-ft sand; however, itdeemed it uneconomic and released the block. Chevronand Unocal acquired Block 191 in the 1983 lease sale. Theinitial stepout, drilled by Chevron, found gas in the 4500-ft sand but was unable to reach the deeper anomaly. A sec-ond well, suspended in January 1990, tested the deeperamplitude and discovered the 8500-ft sand accumulation.Ten wells have been drilled to date. The main reservoir ofthe 8500-ft sand has produced 121 billion ft3 since pro-duction began in 1993. The 4500-ft sand began producing

356 THE LEADING EDGE APRIL 2000 APRIL 2000 THE LEADING EDGE 0000

Production characteristics of sheet andchannelized turbidite reservoirs, Garden Banks191, 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.

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Figure 1. Garden Banks Block 191 is part of GB 236Field, in 700 ft of water about 160 miles southeast ofLafayette, Louisiana, U.S.

Figure 2. Depositional model. Diapirs formed topo-graphic highs and lows on the slope, trapping sandtransported downslope from lowstand deltas to thenorth. Dip-oriented salt ridges funneled sand-rich tur-bidite flows into the area. Sand was trapped on thenorth flank of a strike-oriented shale ridge at block236 and on the north flank of a salt diapir at block 191.

Figure 3. Depositional model Garden Banks 191(cross-sectional view). Sand was trapped on the northflank of a strike-oriented shale ridge at block 236 andon the north flank of a salt diapir at block 191. As thenorth flank minibasin continued to subside (a) due tocontinued loading and withdrawal, the 4500-ft intervalwas rotated, and gas was trapped (b) by the updipshaleout of the sand to the south.

a)

b)

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 intodiapirs and ridges due to rapid sediment loading. Thediapirs formed topographic highs and lows on the slope,trapping sand transported downslope from lowstanddeltas to the north (Figure 2). Dip-oriented salt ridges fun-neled the sand-rich turbidite flows into the Garden Banks236/191 area. The sand was trapped on the north flank ofa strike-oriented shale ridge at Block 236 and on the northflank of a salt diapir at Block 191. As the north flank mini-basin continued to subside due to continued loading andwithdrawal, the 4500-ft and 8500-ft intervals were rotated,and gas was trapped, by the updip shaleout of the sandsto the south (Figure 3).

The 4500-ft sand was deposited as a turbidite sheet sandin a lowstand system tract above the 0.85 M.Y. sequenceboundary. Equivalent lowstand shelf edge deltas are 10-

15 miles to the north, where they compose the main reser-voirs at West Cameron 638 and 643 fields. The 4500-sandinterval is 1000 ft thick—an easy event to recognize on seis-mic. The interval is 75-90% sand, deposited over a largeportion of both blocks 191 and 147. At Garden Banks 236,the 4500-ft interval has 100-300 ft of sand, in several lobes,near the top of the unit; the lower part of the section isshaly.

The 8500-sand, part of the lowstand system tract abovethe 1.2 M.Y. sequence boundary, is restricted to the GardenBanks 191 structure. The paleoshelf edge was farther north.The salt withdrawal minibasin north of the 191 dometrapped sand from turbidity flows originating on the shelf.The 8500-ft interval sands are localized channels in a smallwithdrawal basin just north of the salt. As happened dur-ing the 4500-ft interval, the minibasin continued to sub-side, and a trap was formed by the updip shaleout of thesand. A seismic depth section (Figure 4) shows the presentstructure of the 4500-ft and 8500-ft sands at block 191. Thegas-water contacts in each sand are flat spots on seismic.

Both the 4500-ft and 8500-ft sands produce almost puremethane, probably biogenic gas. The gas was probablysourced from the surrounding shales. Not much associatedliquid has been produced with the gas, although the off-setting Tick Field, six miles to the west, has produced bothoil and gas. The gas columns in both the 4500 and 8500reservoirs extend 900-1000 ft. The long gas columns areinterpreted to be the result of a trapping mechanism con-nected to shaling out of sands southward and not to fault-ing along the flank of the salt or related to paleoshalehighs.

4500-ft sand (sheet sand reservoir). The 4500-ft sand accu-mulation at Garden Banks 191 is trapped on a north plung-ing nose by stratigraphic shale-outs and faulting to thesouth, west, and east (Figure 5). However, on block 236,gas is trapped as a updip pinchout on a shale ridge. The4500-ft sand is supported by a strong water drive; how-ever, there was some initial decline in pressure as high pro-duction rates outran the water. A log from well A6 showsthe sand divided into four members by shale beds corre-


Figure 5. (above) Structure map on the4500-ft sand showing A1, A5, A6, A10,and Shell 1. Well symbols are shown atthe penetration point for the 4500-ftsand. (right) Areal extent of the ampli-tude and reservoir. Note location ofcross-section A-A’ (Figure 9), and seis-mic section S-S’ (Figure 4).

Figure 4. Seismic depth section showing productiveintervals at Garden Banks 191. Note the flat spots atthe 4500-ft and 8500-ft sands. Wells A1 and A6 areshown. See Figure 5 for orientation of the seismic pro-file.

latable throughout the reservoir area (Figure 6). Shalebreaks disappear in downdip wells, grading into a con-tinuous sandy section. All four members have a commongas-water contact at -5523 subsea. The gas-water contactis a pronounced flat spot on seismic. The 4500-ft sand iscontinuous and wet in downdip wells, becoming more than800 ft thick and providing a large aquifer below the gas

accumulation.The updip shaleout of the

4500-ft sand is very sharp.Seismic coherency helpeddefine the updip limit of thesheet flows and in placementof attic gas wells. A clearexample is from block 236where the 4500-ft sandpinches out on a shale-coredhigh. Figure 7 shows theupdip termination of the 4500-ft sand in block 236 on acoherency horizon slice. Thecoherency horizon slices were

generated by flattening the 3-D seismic on a continuousevent above the 4500-ft sand. A coherency cube was gen-erated from the flattened seismic file. Slices through theflattened volume clearly show the sharp updip pinchoutof the 4500-ft sheet flows.

Borehole imaging and core of the 4500-ft sand. The 4500-ft sand reservoir interval is composed of interbedded, tur-bidite sands and shales. Individual turbidite sand bedsrange from 2.5 in. to 8.5 ft in thickness, with most bedsbeing less than 2.0 ft. (Figure 8). The sedimentary charac-ter of beds in Garden Banks 191 is consistent with beddingand facies associations described by Mahaffie (1994) forMars Field (Mississippi Canyon 807); i.e., amalgamated andlayered sheet sands.

Three facies types are identified in core and boreholeimages: thick-bedded sands, thin-bedded sands, and lam-inated shales. Thick-bedded (>2 ft) sands tend to have ero-sive bases and load casts. Internally, they exhibit massive,inclined, and planar laminae; they are rich in organicslocally, especially when associated with the inclined strata.Thin-bedded (<2 ft thick) sand lithofacies are shale-dom-inated; net-to-gross is generally less than 50%. Sand beds,which tend to be less than six inches thick, are ripple towavy laminated, and less commonly, horizontally lami-nated. Macerated, chewed up, organics are very commonalong the bedding planes. Laminated shales are classifiedas graded mud couplets (silty clay to clay); starved sandripples are a common component. Burrows occur locallybut are relatively rare. Sedimentary structures observed inthese three facies are a combination of high-to-moderateenergy, low energy, and muddy turbidity currents. The lackof chaotic bedding suggests that relatively organized tur-


Figure 6. Type log from A6for the 4500-ft sand show-ing members 1-4. The reser-voir divided into fourmembers by shale bedscorrelatable throughout thereservoir. Shale breaks dis-appear in downdip wells,grading into a continuoussandy section.

Figure 7. Flattened coherency horizon slice showing updip shaleout of the 4500-ft sand at Garden Banks 236.(Courtesy of Diamond Geophysical).

bidite deposition occurred throughout the 4500-ft sanddeposition.

At the reservoir scale, the 4500-ft sand consists of rel-atively thin sheet sands punctuated by thicker lobes andsmall channel deposits, composed of both thick- and thin-bedded sands. The laminated shale facies occurs as bothan intraformational facies and as a continuous drape overthe top of each reservoir unit. The shale drape is a criticalfactor as it controls fluid flow through the reservoir andrelates to the productivity of this reservoir.

Electric log evaluations typically underestimate theeffective porosity and overestimate the water saturationin the thin-bedded facies, leading to an underestimationof reserves. Analysis of sand/silt beds in 86 sidewall coresfrom two wells indicates a wide range of reservoir qual-ity. Porosity ranges from 16.7 to 33.5% with an average of25.5%. Permeability values extend from 0.6 to 2520 md,averaging 427 md. Crossplots show that porosity and per-meability vary primarily in response to grain-size changes,a relationship typical of deepwater turbidites in the Gulfof Mexico. Also, the best reservoir quality in the 4500-ftsand (>29% porosity and >550 md) is associated with thethicker, clean sands lacking clay. These sands are the mostprominent on well logs.

4500-ft sand water encroachment and depletion. Threewells (A5, A6, and A10) have a combined production ofmore than 87 billion ft3 from the 4500-ft sand since June1994. A5 and A6 were drilled in 1994; A10 was drilled in 1998to recover attic gas reserves. A6 was a dual completion, withthe long string in member 4 and the short string in member3 of the 4500-ft sand. A5 was dually completed in members

1 and 2. Lack of pipeline capacity delayed the completionof A5 and caused the rate to be cut back slightly from thewell’s capability.

Figure 9 shows a close-up seismic section and a log cross-section through the 4500-ft reservoir. Seismic events are con-tinuous through the reservoir interval, the result of lateralcontinuity of beds within the 4500-ft sand. Depositional char-acteristics can be anticipated from seismic and borehole dataand used to guide the completion strategy. The depositionalcharacteristics of the 4500-ft sand control the way the reser-voir produces. Areal extent and lateral continuity of the tur-bidite sheet flows provide a connection to a large downdipaquifer, resulting in strong water drive. The continuous shalebreaks, formed by thick packages of laminated shale, limitvertical permeability and constrain water encroachmentwithin the reservoir. This causes the individual members toact as separate flow units during production.

The production history of A6 and A5 illustrates how theshale beds separate the sand into multiple flow units. Bottomhole pressures, and timing of water breakthrough, suggestthe existence of three flow units. Members 1 and 2 acted asa single flow unit; members 3 and 4 are the two other flowunits. Member 3 watered out in A6 in June 1996. Member 4continued to produce until May 1997. This shows that mem-bers 3 and 4 were acting independently. In November 1995,A5 was tested in member 3 and completed in members 1and 2. Member 3 showed a reduced pressure from the pro-duction in A6. Members 1 and 2 were at original formation


Figure 9. Seismic line through the 4500 reservoir show-ing continuity of reflectors, and cross-section A-A’through the 4500-ft sand. Seismic events are continu-ous through the reservoir interval due to lateral conti-nuity of beds within the 4500-ft sand. Continuousshale breaks, formed by thick packages of laminatedshale, limit vertical permeability and constrain waterencroachment within the reservoir. This causes theindividual members to act as separate flow units dur-ing production.

Figure 8. Borehole image log from the 4500-sand in A6.Scale on right. Three facies types are identified in coreand borehole images: thick-bedded sands, thin-beddedsands, and laminated shales. Thin-bedded facies is onthe left; thick-bedded facies on right. The sedimentarybeds are amalgamated and layered sheet sands.

pressure. Bottom-hole pressures in members 1 and 2 havetracked each other in A5.

8500-ft sand (channel reservoir). Figure 10 is a map of the8500-ft sand. The amplitude outline gives a good indica-tion of the extent of the sand in an east-west direction. Agas/water contact at 9090-ft subsea limits the reservoir tothe north. The stacked channels of the 8500-ft sand weredeposited in a local salt withdrawal basin north of a saltdiapir in block 191. The 8500-ft sand is divided into five

members, separated by shale breaks (Figure 11). Member3 was further divided into upper, middle, and lower unitsbased on shallow, “perched” water contacts. Members 1and 2 make up the upper, or abandonment phase, of thechannel fill. Members 3-5 make up the lower part of thechannel fill. The divisions were partly based on geologyand partly to facilitate volumetric reserve estimation.Figure 12 shows that individual sand lobes and shalebreaks do not correlate on logs across the reservoir. A seis-mic line through the reservoir (Figure 13a) shows a com-plex reflection pattern of onlap and downcutting reflectingthe lateral variation of the individual channels within the8500-ft sand (Figure 13b).

RFT pressures taken before production show that thegas column in members 3-5 are vertically connected; aninterpreted gas-water contact is at -9090-ft subsea (Figure14). Pressures taken in A7, which encountered member 5updip, showed that it is also connected to members 3 and4. 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 ofthe perched water contacts show the perched water is incommunication with the gas column but is not directly con-nected to the downdip aquifer.

The production history, RFT pressures, distribution ofperched water contacts, and difficult log correlationsbetween wells suggest that the 8500-ft sand is a channel-ized turbidite reservoir with good vertical connectivitybut poorer lateral connectivity. A flattened coherency slicethrough the third member (Figure 15) shows a channel inthis succession and supports this interpretation. Theperched water legs probably form in channels that pinchout 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 lowerpart of the channel fill. (a) (right) Amplitude extraction of the 8500-ft sand.

Figure 10. Structure map on the 8500-ft sand. Well sym-bols are shown at the penetration points for the 8500-ftsand. Shaded area shows areal extent of amplitudeassociated with the 8500-ft sand. Note location ofcross-sections B-B’ (Figure 12) and C-C’ (Figure 13b).

A2 produced free water with no influx from the perchedwater leg.

Depositional interpretation of the 8500-ft sand. The 8500-ft sand is interpreted as a 900 ft thick “fining-upward” chan-nel succession, deposited in a slope minibasin formed bysalt withdrawal. The lower part of the channel fill is dom-inated by thick, 3-12 ft, massive, fine- to medium-grain sandbased on core and borehole image data. Concentrations ofrip-up clasts several feet thick are common along the ero-sional bases of individual flow events and also occur sus-pended within the deposits. These facies are inferred to bethe product of sandy turbidity currents and other high-concentration sediment gravity flows (Lowe, 1982; Steltinget al., 1998). The succession is punctuated periodically bylower energy facies such as laminated sandstone and silt-stone, interlaminated siltstone and shale, and homoge-neous to laminated shale. These finer-grained depositsrepresent thin-bedded and muddy turbidites.

Production data has been used to determine that bedlength of finer-grained, muddy beds is less than bed lengthof more massive sands. This condition is common in sub-marine channel deposits (Cook et al., 1994; Clark andPickering, 1996). The upper part of the channel fill has alower net-to-gross than the lower, main reservoir intervaland is inferred to consist of stacked channel-levee com-plexes accumulating as late stage depositional energydeclined.

Reservoir quality estimates based on sidewall coresshow a result similar to that found in the 4500-ft sand.Thicker, clean sands have high porosity and permeabilityvalues; thin, shaly beds have low values. Even though thenet-to-gross is lower in the upper units, sands sampled insidewall cores still have moderate porosity (24-29%) andpermeability (100-550 md).

Continuous core was critical in estimating reserves,selecting intervals to perforate, and designing a develop-ment strategy for this channel sand reservoir. Electric logevaluations in thick sands with abundant shale rip-upclasts underestimated the reservoir quality of this facies.The shale clasts appeared as dispersed clay to the loggingtools, instead of shale within a clean sand matrix. The

8500-ft sand effective porosity was underestimated, andthe water saturation was overestimated, leading to lowerreserve estimates.

8500-ft sand production drainage as seen on seismic. The8500-sand has produced a total of 121 billion ft3 from three


Figure 12. Stratigraphic cross-section of the 8500-ftsand hung on the 3U member, showing lateral varia-tion between wells in members 3 and 4. Compare thegas-water contact at 8750-ft subsea in lobe 3M in A2with the gas-water contact at -9090 ft subsea in lobe3M in 2. Individual sand lobes and shale breaks donot correlate on logs across the reservoir.

Figure 13. (a) Seismic line through the 8500-ft sandshowing complex reflection pattern and (b) cross-sec-tion C-C’ showing water encroachment through the8500-ft sand. Solid bars show perforated intervals. RFTpressures taken before production commenced showthat the gas column in members 3-5 are vertically con-nected.

Figure 14. RFT pressures taken in the 8500-ft sandfrom four wells. Pressures from members 3-5 line upalong a single gradient. Pressures from members 1 and2 have a similar slope but line up at higher pressures.A perched water leg from A3 shows a water gradientconnected to the gas column.

a)

b)

wells (A1, A2, and A3) since November 1993. An additionalwell, A7, was drilled in 1998 to recover attic gas. The ini-tial combined rate of 150 million ft3/d from the three wellshas declined steadily through time. Throughout most ofits production history, the 8500-ft sand behaved as a pres-sure depletion reservoir. Initial formation pressure of 4750psi declined to 1300 psi by 1998. In 1997, water arrived suc-cessively at A2 (April), A3 (September), and A1 (October).Water influx indicated a weak water drive and led to thedecision to drill A7.

A7 was designed to recover updip reserves in mem-bers 3 and 4 and to target suspected updip gas in mem-ber 5, which was wet in A1. Aseismic line and cross-sectionthrough A7, A1, A3 is shown in Figure 13. A seismic flatspot was interpreted to mean that the member 5 sandchannel was 1200 ft wide and co tained gas updip. A7 didencounter a massive sand from 8500-ft subsea to totaldepth (9195-ft subsea). This was interpreted to be an amal-gamation of members 4 and 5. Member 3 was shaled out.A7 encountered a gas-water contact at 8681-ft subsea, 360ft above the perforations simultaneously producing gasfrom A1. A7 saw 378 feet of residual gas below the gas-water contact at 8681 ft subsea SS and evidence of an orig-inal gas-water contact at 9059 ft subsea consistent with theseismic flat spot.

Compartmentalization of 8500-ft sand production.Vertical connectivity has allowed the 8500-ft sand to act asa single tank and allowed the existing wells to effectivelydrain the gas reserves. The shale beds, which separate theindividual members and channels, have acted as baffleswithin the reservoir. The gas was able to move around thebaffles and be produced from the existing wells. If thereservoir fluid had been oil, there would have been muchgreater potential for bypassed reserves, and more wellswould have been needed to drain the reservoir. Recoveryefficiencies for oil would have been much lower becauseof the pressure depletion and weak water drive exhibitedby the 8500-ft reservoir.

The lateral extent of the individual channels limits thelateral connectivity. Each member contains several indi-vidual channels, which may or may not be laterally con-

nected. Initial RFT pressures and bottom hole pressurestaken over several years show the stacked channels are act-ing as a single tank. The shale breaks separating the mem-bers 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 rel-atively small.

The pattern of water influx illustrates the combinationof good vertical connectivity and poorer lateral connectivitywithin the reservoir. The reservoir produced for three yearsbefore water entered A2. The water that successively hitA2, A3, A1 wells came in from the edge of the reservoiralong the lower part of member 4. At A1, there was noinflux of water from the massive wet member 5 sand. Theshale break between members 4 and 5 at that location pre-vented the water from entering A1. At A7, where mem-bers 4 and 5 coalesced into a single massive sand, thewater contact moved upward 378 ft from an original gas-water of 9059-ft subsea to a current gas-water of 8681-ftsubsea. A1 actually drew gas downdip from A7.

Conclusions. Different reservoir architectures of the 8500-ft and 4500-ft sands have resulted in different productionhistories. Figure 16a shows flow rates for representativecompletions in both sands. Figure 16b shows the P/Z plotsversus cumulative production for both reservoirs. Bothsands show high initial flow rates although the 8500-ft sandhas a higher productivity due to its higher initial pressure


Figure 16. Production plots comparing the 4500-ft and8500-ft sands. (a) Plot of rate versus time for two rep-resentative completions—4500 member 4 in A6 and8500 member 4 in A1. (b) P/Z versus cumulative pro-duction for both the 4500-ft and 8500-ft sands. Bothsands show high initial flow rates although the 8500-ft sand has a higher productivity because of its higherinitial pressure and the more massive nature of thechannel sands.

Figure 15. The production history, RFT pressures, dis-tribution of perched water contacts, and difficult logcorrelations between wells, suggest that the 8500-ftsand is a channelized turbidite reservoir with goodvertical connectivity but poorer lateral connectivity. Aflattened coherency slice through the third membershows a channel in this succession and supports thisinterpretation.

a)

b)

and the more massive nature of the channel sands. The4500-ft sand shows lower decline rates, but production fallsrapidly once water enters the completion. The P/Z plot ofthe 4500-ft sand is more complex since the different mem-bers depleted individually; however, the plot is much flat-ter, which is typical of water drive reservoirs. The P/Z ofthe 8500-ft sand shows a more linear decline, typical of pres-sure depletion reservoirs.

The following observations can be made from the pro-duction history of the turbidite sands at Garden Banks 191:

1) These turbidite sands are excellent reservoirs, capableof high flow rates and high recovery efficiencies.Interaction of basin configuration and turbidite depo-sitional processes created reservoir geometry, aquifersize, and drive mechanisms for the 4500-ft and 8500-ftsands.

2) Seismic coherency was useful in defining the updiplimits of the reservoirs and in placing attic wells.

3) The continuity of the shale breaks within the reservoirscontrolled the influx of water as the sands produced.In the 8500-ft sand, shale bed lengths were less than thereservoir extent and formed baffles in the reservoir. Inthe4500-ft sand, shale bed lengths extended across thereservoir and caused the individual members to act as separate flow units. Understanding the distri-bution of the fine grained and muddy facies was veryimportant to designing a development and completionstrategy for both the channel (8500-ft) sand and sheet(4500-ft) sand.

4) Conventional core and borehole imaging logs were crit-ical to evaluating the quality of the reservoirs prior todevelopment. Reserves would have been significantlyunderestimated without this data.

5) RFT pressures were critical to evaluating the connec-tivity of the 8500-ft reservoir and in designing a devel-opment strategy.

Suggestions for further reading. Submarine Channel Processesand Architecture by Clark and Pickering (Vallis Press, London,1996). “Facies architecture and reservoir characterization of asubmarine fan channel complex, Jackfork Formation,Arkansas” by Cook et al. (in Submarine fans and turbidite sys-tems: sequence stratigraphy, reservoir architecture, and productioncharacteristics, GCSSEPM 15th Annual Research Conference,1994). “Sediment gravity flows: II. Depositional models withspecial reference to the deposits of high-density turbidity cur-rents” by Lowe (Journal of Sedimentary Petrology, 1982).“Reservoir classification for turbidite intervals at the Mars dis-covery, Mississippi Canyon 807, Gulf of Mexico” by Maffie(in Submarine fans and turbidite systems: sequence stratigraphy,reservoir architecture, and production characteristics). “Productioncharacteristics of sheet and channelized turbidite reservoirs,Garden Banks 236 Field, Gulf of Mexico” by Stelting et al.(EAGE/AAPG Third Research Symposium). “Productioncharacteristics of sheet and channelized turbidite reservoirs,Garden Banks 191, Gulf of Mexico, U.S.A.” by Fugitt et al. (GulfCoast Association of Geological Societies Transactions, 1999). LE

Acknowledgments: We thank Chevron and Spirit Energy for permis-sion to publish this paper (a similar article was previously published inGCAGS Transactions in 1999). We also thank Mark Zastrow for help-ful comments and insight into the regional geology, and we thank ScottTurner for his help with the RFT data.

Corresponding author: [email protected]

David Fugitt is staff geologist with Chevron in Lafayette, Louisiana,U.S. He joined Chevron in 1978. Fugitt receiveda bachelor’s degree in geology from Ohio StateUniversity in 1976, and a master’s from TexasA&M University in 1978.

William Schweller has worked in petroleum research with Gulf andChevron since 1982, primarily studying turbidite reservoirs and sequencestratigraphy of deepwater systems.

Charles Stelting has been a regional and reservoir stratigrapher/sedi-mentologist specializing in deepwater depositional systems at Chevronsince 1982. He received a bachelor’s degree in geology from Texas A&MUniversity, Kingsville, in 1980 and a master’s degree from Universityof California, Riverside in 1989.

Gary Herricks has 20 years of experience in reservoir engineering. Garyhas been with Chevron since 1989. He received a bachelor’s degree inpetroleum engineering from Texas Tech University in 1979.

Michael R. Wise is a senior petroleum engineer with Chevron USA Inc.and is currently working in the Gulf of Mexico Business Unit of theNorth American E&P Company. Wise has almost 22 years of combinedexperience with Gulf and Chevron and has worked in both the Gulf ofMexico and the Permian Basin regions, primarily in production andreservoir engineering


production characteristics of sheet and channelized turbidite ...bidite sands and shales. individual...

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