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Abstract

Sheet sands and sandstones are considered to be some of the best high-rate, high-ultimate recovery (HRHU) reservoirs in deepwater (Chapter 2). This is due to their tendency towards the simplest reservoir geometries: good lateral continuity, potentially good vertical connectivity, high aspect ratio, narrow range in grain size (and thus greater porosity and permeability: Chapter 13), and few erosional features. Because of their initial successes as reservoirs in the northern deep Gulf of Mexico, sheet sands and sandstones have been studied in great detail by industry to better understand them, and, hence, to find more of them. One problem, however, is that reservoirs initially interpreted as sheet sands were later determined to be amalgamated channel sands.

Sheet sands are deposited from decelerating flows at the terminus of channels. Sheet sands and sandstones reflect the sediments that have bypassed through updip channels (confined flow) and are deposited in primarily an unconfined setting. They are characterized by high aspect ratio reservoir sand bodies (>500:1), markedly different in aspect than the updip channels that feed them (30:1 to 300:1). Unlike other deepwater reservoir elements, the areal extent of sheet sands is commonly larger than the area of the trap. Sheet sands and sandstones are most prevalent in mixed mud-sand to mud dominated systems (Richards and Bowman, 1998). Sheet sands and sandstones are not as common in sand-rich to gravel-rich systems (Chapter 1 and Chapter 5).

Sheet sands and sandstones are characterized by their tabular

Introduction

Sheet sands and sandstones are considered to be some of the best high-rate, high-ultimate recovery (HRHU) reservoirs in deepwater (Chapter 2). This is due to their tendency towards the simplest reservoir geometries: good lateral continuity, potentially good vertical connectivity, high aspect ratio, narrow range in grain size (and thus greater porosity and permeability: Chapter 13), and few erosional features. Because of their initial successes as reservoirs in the northern deep Gulf of Mexico, sheet sands and sandstones have been studied in great detail by industry to better understand them, and, hence, to find more of them. One problem, however, is that reservoirs initially interpreted as sheet sands were later determined to be amalgamated channel sands.

Sheet sands are deposited from decelerating flows at the terminus of channels. Sheet sands and sandstones reflect the sediments that have bypassed through updip channels (confined flow) and are deposited in primarily an unconfined setting. They are characterized by high aspect ratio reservoir sand bodies (>500:1), markedly different in aspect than the updip channels that feed them (30:1 to 300:1). Unlike other deepwater reservoir elements, the areal extent of sheet sands is commonly larger than the area of the trap. Sheet sands and sandstones are most prevalent in mixed mud-sand to mud dominated systems (Richards and Bowman, 1998). Sheet sands and sandstones are not as common in sand-rich to gravel-rich systems (Chapter 1 and Chapter 5).

Sheet sands and sandstones are characterized by their tabular external form and their excellent continuity (Chapin et al., 1994; Mahaffie, 1994). They can be subdivided into two groups: layered and amalgamated. Layered sheets are characterized by relatively low net:gross with interbedded shale and sandstone beds. Amalgamated sheets are characterized by high net:gross, comprising stacked sandstone beds with fewer interbedded shales. Sheets exhibit a transition from amalgamated to layered in both longitudinal and transverse directions.

This chapter reviews the important attributes of sheet sands and sandstones, ranging from (a) their overall regional geometry and seismic characteristics, to (b) the development-scale stratigraphic and reservoir quality heterogeneities that control the flow of reservoir fluids through them. Selected reservoirs are then summarized in terms of their production history, geophysical and geological characteristics, and unique issues that affected each field’s development.

Regional-scale characteristics

Important features of sheets at the regional scale are presented here, first examining sea floor images, and then examining the shallow and deep subsurface expression from multifold seismic and wireline logs. The most important features at this scale are shape, size, area, thickness, edge relationships, internal reflection associations, and wireline log patterns. The features resolved in some sea-floor images (high resolution 3-D, Sea MARC I sidescan sonar) are at the approximate scale of some of the outcrops described below at the development scale. Otherwise, the features described here are larger than those described at the development scale.

Sea-floor characteristics

Sea-floor images of modern fans show a spectrum of geometries of deposits beyond the termini of channels. These different geometries reflect variations in the grain size, volume, and the rheological nature of the flows from which the deposits were derived. Three examples illustrate the variability in these systems.

Lobate pattern

Sheet deposits have a lobate form(s) at the terminus of channels. The sea-floor image of the slope of Nigeria in Figure 8-1 was generated from 3D seismic data. The image illustrates a channel that grades downdip in a small enclosed minibasin. A large, paddle-shaped deposit completely fills this small intraslope basin. The overall feature laps out against the edges of the basin, both laterally and downdip. Three smaller lobate features are present at the termini of the channels that are offset from each other with diffuse boundaries. Resolution of the seismic data is standard industry processing. These sheet deposits are uncored.

Figure 8-1.

Three-dimensional perspective of an isochron of one depositional lobe with sheet sands draped over seafloor bathymetry. Deposit is in one intraslope minibasin created from shale deformation on the Nigerian continental slope, Block 221. The maximum isochron values are shown in red (100 msec). Inset shows the same area with an amplitude extraction draped over bathymetry. Three distinct areas with sheets are outlined. The vertical “stripes” represent an acquisition “footprint” of the 3-D data. After Pirmez et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-1.

Three-dimensional perspective of an isochron of one depositional lobe with sheet sands draped over seafloor bathymetry. Deposit is in one intraslope minibasin created from shale deformation on the Nigerian continental slope, Block 221. The maximum isochron values are shown in red (100 msec). Inset shows the same area with an amplitude extraction draped over bathymetry. Three distinct areas with sheets are outlined. The vertical “stripes” represent an acquisition “footprint” of the 3-D data. After Pirmez et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Distributary channel patterns

With much higher-frequency 3-D seismic data (250 Hz), better resolution of the deposi-tional patterns is possible at the terminus of the deepwater channels. In one intraslope basin setting in the northern deep Gulf of Mexico, two upfan channels bifurcate downfan into at least four, discrete channel mouth lobe deposits (Fig. 8-2). These deposits are elongated and lobate in plan view, and have an offsetting pattern. The channel mouth lobe deposits are separated by areas of lower reflectivity. These features are uncored.

Figure 8-2.

Seismic horizon slice taken 20 ms below sea floor in one intraslope basin, late Quaternary, northern deep Gulf of Mexico. Two distinct upfan channel belts (A, B) to the right (north) change downfan to channel mouth lobes. Also present are basin margins, mud volcano, and “slumps.” Location of Figure 8-8 is shown. After Beaubouef et al., 2003. Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-2.

Seismic horizon slice taken 20 ms below sea floor in one intraslope basin, late Quaternary, northern deep Gulf of Mexico. Two distinct upfan channel belts (A, B) to the right (north) change downfan to channel mouth lobes. Also present are basin margins, mud volcano, and “slumps.” Location of Figure 8-8 is shown. After Beaubouef et al., 2003. Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Dendritic-channel patterns

A slightly different pattern of deposition is shown at the channel termini of one part of the Mississippi Fan (Twichell et al., 1992, 1995). A high-resolution, 30 kHz SeaMARC 1A sidescan sonar image illustrates the upfan channel that bifurcate downdip into several smaller channels with a dendritic pattern (Fig. 8-3). Channels are 100-150 m wide, and have less than 3-5 m of relief. The end of each channel has no channel mouth bar deposits; rather, the deposits have sharp edges.

Figure 8-3.

(a) Map of the youngest depositional lobe in the Mississippi fan, northern deep Gulf of Mexico. Box illustrates the area shown in detail in Figure 8-3 (b).

Figure 8-3.

(a) Map of the youngest depositional lobe in the Mississippi fan, northern deep Gulf of Mexico. Box illustrates the area shown in detail in Figure 8-3 (b).

Figure 8-3.

(b) SeaMARC I sidescan sonar image of distal Mississippi Fan lobe. Small channels (high back-scatter-white) are surrounded by areas of low backscatter (dark) suggesting the channel deposits formed as a series of interfingering channelized flows of sand and silt. White dots indicate where cores were collected. After Twichell et al., 1995. Reprinted with permission of Chapman-Hall and Kevin Pickering.

Figure 8-3.

(b) SeaMARC I sidescan sonar image of distal Mississippi Fan lobe. Small channels (high back-scatter-white) are surrounded by areas of low backscatter (dark) suggesting the channel deposits formed as a series of interfingering channelized flows of sand and silt. White dots indicate where cores were collected. After Twichell et al., 1995. Reprinted with permission of Chapman-Hall and Kevin Pickering.

These features have been sampled with piston cores at seven sites (Fig. 8-3; Nelson et al., 1992; Schwab et al., 1996). The core penetrations ranged from 1.2 to 7.0 m. Four general lithofacies were cored. (a) The upper 0.1-0.3 m of the cores consist of foraminiferal mud and silt deposited during the Holocene highstand in sea level. (b) Sites 29, 38, 41, and 42 cored the channels (high backscatter-white color) and recorded well-graded, poorly sorted sands, typically 10-30 cm thick and varying from fine sand at the base to coarse silt at the top (Fig. 8-3). (c) Overlying these deposits are poorly-sorted chaotic silt beds, with clay clasts and wood fragments, as recovered at sites 38, 41, 42, 43 and 44 (Fig. 8-3). The silt beds are 10-120 cm thick. (d) Site 31 cored the surrounding basin plain sediments (low backscatter-dark color) and recovered very fine silts and dark-banded clay (Fig. 8-3).

Nelson et al. (1992) interpreted the graded sand-silt beds as deposited by true turbidity currents from suspension flows, whereas the chaotic silty beds with mud clasts were deposited from non-turbulent debris flows. These authors suggest that the sediment distribution is largely one of discontinuity between sand-silt lenses. They interpreted the abrupt edges of the channels to have been caused by the abrupt deposition of flows. The equal number of sand beds and chaotic silt beds suggests that both turbidity and debris flows contributed to sedimentation at the distal edge of this fan system.

Differences in patterns

These three sea-floor images illustrate that the sheet deposits, at one point in time, consist of broad lobe-like patterns separated by other deposits. The first two images probably reflect similar processes; the only difference is that Figure 8-2 has higher resolution. The third image is somewhat different in that no channel-mouth bar deposits are present.

The one important aspect lacking in these sea-floor images is how the sediments stack and are preserved through time. The distribution of sediment at this scale shows some horizontal discontinuity between sheets; however, with more deposition, many of the lows are filled with both sands and muds, and continuity between similar deposits does begin to develop. As discussed below, the seismic stratigraphic expression of these deposits on vertical profiles is one of laterally continuous deposits because these are beyond resolution, and hence they appear as sheet deposits. These are at the scale of outcrops, and as will be discussed, these may reflect where sands transition from amalgamation to non-amalgamation.

Seismic stratigraphic and wireline log characteristics

Seismic resolution is always a key issue with the definition of sheets. In general, with the decrease in seismic frequency with depth, vertical resolution decreases. At shallow depths, it is possible to obtain higher frequency data. In plan view, the geometries depicted by the images generated in these shallow settings are remarkably similar to those generated from sea-floor images (Figs. 8-18-3), but with less detail. The seismic stratigraphic expression of producing sheets at depth is similar to the shallow expression, but with less resolution.

The following examples are from different depositional and tectonic settings and illustrate important features of sheets at the seismic stratigraphic scale. Examples shown are from both salt-dominated (northern Gulf of Mexico) and shale-dominated (Nigeria, Brunei) intras-lope basins and from unconfined basins (Brazil, Indonesia, North Sea). These examples include seismic profiles, attribute maps, and their wireline log expression from several different producing basins. In addition, the relationship between sheets and overlying channels is briefly discussed.

Shape and size

Sheets vary considerably in shape and size, depending largely on the overall nature of the deepwater system. The composition of the source terrain that produces the primary sediment; volume, grain size, and duration of flows; and the size and shape of the receiving basin all affect the shape and size of the sheets deposits. Syndepositional tectonics (salt, shale, faults) can also control the shape of these units.

The shape of the sheets, as revealed from 3-D seismic, is similar to shapes imaged from sidescan sonar systems described above, although the stratigraphic detail is generally not resolvable on 3-D seismic with more deeply buried sheets. Both lobate systems (offshore Brunei; Figs. 8-4, 8-5, 8-6) and distributary systems (Makassar Straits, Indonesia, northern Gulf of Mexico, Brazil; Figs. 8-78-11) can be imaged.

Figure 8-4.

Stereometric display of the amplitude extraction of the yellow event about 150 ms below the sea floor (Fig. 8-5) from a portion of the late Quaternary, upper Brunei continental slope. Upslope channel changes downdip to a channelized lobe and then to a sheet deposit. Location of seismic profile in Fig. 8-5 is shown. After Demyttenaere et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-4.

Stereometric display of the amplitude extraction of the yellow event about 150 ms below the sea floor (Fig. 8-5) from a portion of the late Quaternary, upper Brunei continental slope. Upslope channel changes downdip to a channelized lobe and then to a sheet deposit. Location of seismic profile in Fig. 8-5 is shown. After Demyttenaere et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-5.

Seismic profile from the continental slope of Brunei showing near-surface channelized lobe. Yellow horizon indicates surface from which Figure 8-4 was extracted. See Figure 8-4 for location of profile. After Demyttenaere et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-5.

Seismic profile from the continental slope of Brunei showing near-surface channelized lobe. Yellow horizon indicates surface from which Figure 8-4 was extracted. See Figure 8-4 for location of profile. After Demyttenaere et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-6.

RMS amplitude extraction 170 msec below the seafloor in one intraslope minibasin in the Brunei continental slope. Upslope channel passes through shale ridges to elongated, sheet deposit. Margin consists of intraslope basins associated with shale features and strike-slip tectonics. After Demyttenaere et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-6.

RMS amplitude extraction 170 msec below the seafloor in one intraslope minibasin in the Brunei continental slope. Upslope channel passes through shale ridges to elongated, sheet deposit. Margin consists of intraslope basins associated with shale features and strike-slip tectonics. After Demyttenaere et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-7.

(a) Seismic profile from latest Pleistocene submarine fan, Makassar Strait, eastern Borneo. The vertical succession consists of a series of laterally continuous, high-amplitude reflections at the base (sheets), overlain by packages of laterally migrating channels that evolve upward into a single aggradational channel with lateral migration. Arrow marks the level of the horizon slice. (b) Amplitude extraction map taken 48 msec below the sea floor showing the distributary channel patterns changing downfan to sheet deposits. After Posamentier et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-7.

(a) Seismic profile from latest Pleistocene submarine fan, Makassar Strait, eastern Borneo. The vertical succession consists of a series of laterally continuous, high-amplitude reflections at the base (sheets), overlain by packages of laterally migrating channels that evolve upward into a single aggradational channel with lateral migration. Arrow marks the level of the horizon slice. (b) Amplitude extraction map taken 48 msec below the sea floor showing the distributary channel patterns changing downfan to sheet deposits. After Posamentier et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-8.

Three high-resolution seismic profiles from one shallow intraslope minibasin, northern deep Gulf of Mexico. Proximal (A) and medial (B) profiles cross the upfan channelized systems. (C) Distal profile crosses the sheet deposits. Note that the lobes A and B have slightly mounded appearance amongst the laterally continuous sheet-like reflections that lapout against the side of the basin. The deposits are up to 50 msec in twtt. See Figure 8-2 for location of profiles. After Beaubouef et al. (2003). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-8.

Three high-resolution seismic profiles from one shallow intraslope minibasin, northern deep Gulf of Mexico. Proximal (A) and medial (B) profiles cross the upfan channelized systems. (C) Distal profile crosses the sheet deposits. Note that the lobes A and B have slightly mounded appearance amongst the laterally continuous sheet-like reflections that lapout against the side of the basin. The deposits are up to 50 msec in twtt. See Figure 8-2 for location of profiles. After Beaubouef et al. (2003). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-9.

Seismic profile across the Marlim and Marlim Sul fields, Campos Basin, offshore Brazil. Prominent seismic amplitude can be traced across the profile from both fields. See Figure 8-10 for amplitude extraction of the horizon. After Bruhn (2001). Reprinted with permission of AAPG and Carlos Bruhn.

Figure 8-9.

Seismic profile across the Marlim and Marlim Sul fields, Campos Basin, offshore Brazil. Prominent seismic amplitude can be traced across the profile from both fields. See Figure 8-10 for amplitude extraction of the horizon. After Bruhn (2001). Reprinted with permission of AAPG and Carlos Bruhn.

Figure 8-10.

Amplitude extraction of the top Marlim and Marlim Sul Field, Campos Basin, offshore Brazil. Note the three updip channels (arrows) that feed the lobe-shaped sheet sands. After Bruhn (2001). Reprinted with permission of AAPG and Carlos Bruhn.

Figure 8-10.

Amplitude extraction of the top Marlim and Marlim Sul Field, Campos Basin, offshore Brazil. Note the three updip channels (arrows) that feed the lobe-shaped sheet sands. After Bruhn (2001). Reprinted with permission of AAPG and Carlos Bruhn.

Figure 8-11.

Wireline log from the Marlim field, Campos Basin, Brazil. Four distinct amalgamated sheets are present (labeled L1-L4), each 20-40 m (66-132 feet) thick. After Bruhn (2001). Reprinted with permission of AAPG and Carlos Bruhn.

Figure 8-11.

Wireline log from the Marlim field, Campos Basin, Brazil. Four distinct amalgamated sheets are present (labeled L1-L4), each 20-40 m (66-132 feet) thick. After Bruhn (2001). Reprinted with permission of AAPG and Carlos Bruhn.

The area of sheets can be anywhere from tens to hundreds of square km. In unconfined basins, the size of the flows and overall updip depositional system control the area. In intra-slope basins, sheets can partially fill the basin or can extend across the entire basin. Booth et al. (2000) presented examples of upper Pliocene sheet sands filling large portions of the greater Auger mini basin (250 square km) (Fig. 8-12). Sheets are interpreted to correspond to laterally continuous reflections that were deposited in multiple sequences. Nine of the twelve producing reservoir intervals in the Auger and Macaroni fields occur within the onlapping seismic facies associated with sheet sands and amalgamated channel sands. Individual sand units can be correlated 15 km between fields.

Figure 8-12

(A) Flattened seismic profile across the Greater Auger minibasin showing the relationships between the Auger and Macaroni fields. Multiple sheet sands are interpreted to be present that extend across most of the basin. (B) Interpreted stratigraphic fill packages between two wells. Two kinds of facies are present. Yellow intervals are interpreted as onlapping fill facies (i.e. sand –rich sheets), and the orange are channel-fill facies (“bypass facies”). Gamma ray logs from each field illustrate layered sheet (LS), amalgamated sheet (AS) sands, and amalgamated channel (AC) sands. After Booth et al., 2000. Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-12

(A) Flattened seismic profile across the Greater Auger minibasin showing the relationships between the Auger and Macaroni fields. Multiple sheet sands are interpreted to be present that extend across most of the basin. (B) Interpreted stratigraphic fill packages between two wells. Two kinds of facies are present. Yellow intervals are interpreted as onlapping fill facies (i.e. sand –rich sheets), and the orange are channel-fill facies (“bypass facies”). Gamma ray logs from each field illustrate layered sheet (LS), amalgamated sheet (AS) sands, and amalgamated channel (AC) sands. After Booth et al., 2000. Reprinted with permission of the Gulf Coast Section SEPM Foundation.

The thickness of sheets is quite variable and depends in part on areal distribution. Generally, layered sheet sands are 10-50 ft (3-16 m) thick; where they amalgamate, they can become up to 200-300 ft (60-90 m) thick (Figs. 8-11, 8-12). In addition, the relative amount of bathy-metric confinement affects thickness. In unconfined basins, systems tend to spread out laterally in response to updip channel avulsion. Each sheet deposit tends to be relatively thin. In structurally confined basins, sheet deposits can be considerably thicker where deposits pond against some feature and where there are higher rates of subsidence (accommodation). Sheets can develop in one to multiple sequences in one confined basin (Chapter 3).

Edge relations

At the seismic scale, sheets can have both transitional and lapout edge relations, depending upon the depositional setting of the basin. Seismic data are essential to defining these relations, which have significant implications for the lateral seal and potential trap for these kinds of features as prospects and reservoirs. Unfortunately, many of the details of the lapouts are beneath seismic resolution.

The updip contact of sheets, i.e. between sheets and channels, is transitional (Figs. 8-48-9, and 8-10). One difficulty in defining sheets on seismic reflection data is the transitional nature from the upfan channels (confined flow) to the unconfined sheet deposits. Generally, channels can be seen to die out downfan, where they are beneath seismic resolution. Indeed, one of the problems with sheets as potential reservoirs is that they are in communication with updip channels and can be leaky reservoirs. An amplitude extraction map of a portion of the sea-floor shows the clear transition from the late Pleistocene channel systems downfan into a channelized lobe (Figs. 8-3, 8-8). The lobe is lens-shaped in cross section, and the map shows the channels clearly changing gradationally to the sheet-like deposits.

The lateral contacts can be either transitional or abrupt. In unconfined settings, sheet sands thin at their edges (apparent downlap) beneath seismic resolution. In intraslope basins, the reflections can thin and lap out against a pre-existing depositional surface, or physically onlap against the surface with little to no thinning. Prather et al. (1998) presented examples of sheet sands in vertical and horizontal perspectives (Figs. 8-13, 8-14). These authors noted that the sheets were deposited in a series of onlapping reflections against a sequence boundary.

Figure 8-13.

Flattened seismic profiles across one intraslope minibasin in the northern deep Gulf of Mexico. A sheet deposit (Cbh facies) onlaps the condensed section (D facies) and dipping depositional surface. Red dipping lines mark the edge of channels (Bh facies) that eroded the sheet. See Figure 8-14 for amplitude extraction of the sheet, and location of the profiles. After Prather et al. (1998). Reprinted with permission of AAPG.

Figure 8-13.

Flattened seismic profiles across one intraslope minibasin in the northern deep Gulf of Mexico. A sheet deposit (Cbh facies) onlaps the condensed section (D facies) and dipping depositional surface. Red dipping lines mark the edge of channels (Bh facies) that eroded the sheet. See Figure 8-14 for amplitude extraction of the sheet, and location of the profiles. After Prather et al. (1998). Reprinted with permission of AAPG.

Figure 8-14.

Amplitude extraction of the sheet sand shown in Figure 8-13. Distinct edge to the sheet can be seen onlapping the slope. Note the fairly uniform amplitude within the sheet. Location of seismic profiles in Figure 8-13 are shown. After Prather et al. (1998). Reprinted with permission of AAPG.

Figure 8-14.

Amplitude extraction of the sheet sand shown in Figure 8-13. Distinct edge to the sheet can be seen onlapping the slope. Note the fairly uniform amplitude within the sheet. Location of seismic profiles in Figure 8-13 are shown. After Prather et al. (1998). Reprinted with permission of AAPG.

The downdip contacts for sheet sands and sandstones are generally transitional in the unconfined setting where they thin beneath seismic resolution (Fig. 8-7). Amplitudes tend to decrease as the thickness of the unit decreases beneath seismic resolution. In confined settings such as intraslope basins, the downdip contact can consist of distal onlap against some structural feature; pinchout against the flank; or be gradational by thinning (Figs. 8-48-6, 8-12–8-16).

Internal reflections

On shallow occurrences with good seismic penetration, sheets are expressed as multiple reflections. Subtle internal variations in the wavelets are also present (Figs. 8-5, 8-8).

The seismic amplitude response of the sheet depends upon the rock physics, thickness, and fluids in the sediments. Externally, the top and the base of the sheet can be imaged, depending upon the thickness and frequency of data. The reflections corresponding to sheets have generally good continuity with minimal change in the seismic wavelet (Figs. 8-88-14). Radovich (2002) presented images of sheet sands in intraslope basins using different seismic attributes, notably instantaneous phase, frequency, and phase. The use of different attributes highlights the laterally continuous nature of the sheets, and their widespread areal distribution (Fig. 8-15). Radovich (2002) also noted that within intraslope basins, stratal onlap onto a sequence boundary occurs in both sand-prone facies and shale-prone facies, a slightly different interpretation than those presented by Prather et al (1998) and Booth et al. (2000).

Figure 8-15.

Seismic volume rendered display from offshore Nigeria showing four discrete zones with different facies. Note that the lower zone shows sequences dominated by sheet sands (basin–floor fans). Only the highest amplitude voxels are visible. After Radovich (2002). Reprinted with permission Gulf Coast Section SEPM Foundation.

Figure 8-15.

Seismic volume rendered display from offshore Nigeria showing four discrete zones with different facies. Note that the lower zone shows sequences dominated by sheet sands (basin–floor fans). Only the highest amplitude voxels are visible. After Radovich (2002). Reprinted with permission Gulf Coast Section SEPM Foundation.

Wireline log to seismic response

Of the four reservoir elements described in this book, sheets have the most consistent wireline log signature. For layered sheets, the gamma ray log pattern consists of sharp bases and tops, with a blocky to serrated pattern, depending upon the proportion of shale to sandstone beds (Figs. 8-12, 8-16). For amalgamated sheets, the gamma ray log expression is one of blocky shape with sharp lower and upper contacts, often with minor serrations produced by the occasional shale interbed. Thickness of amalgamated sheet sands and sandstones is quite varied; ranging from 10 to 60 m (30 to hundreds of feet), if local conditions provide the accommodation for such deposits.

Figure 8-16.

Composite gamma ray and resistivity wireline logs through the Ram-Powell field, northern Gulf of Mexico. Note the different shape log curves for different reservoirs. (i.e. architectural elements). Sheet sands are illustrated at the top of the log (J sand). After Craig et al., 2003. Reprinted with permission of AAPG.

Figure 8-16.

Composite gamma ray and resistivity wireline logs through the Ram-Powell field, northern Gulf of Mexico. Note the different shape log curves for different reservoirs. (i.e. architectural elements). Sheet sands are illustrated at the top of the log (J sand). After Craig et al., 2003. Reprinted with permission of AAPG.

Distinguishing sheet sands and sandstones from channel-fill sands and sandstones using a single wireline log can be extremely difficult. One-dimensional criteria such as coarsening-and thickening- upward patterns, though commonly cited, are not reliable indicators to differentiate a sheet from a channel-fill sand and sandstone body because both can also exhibit a thinning- and fining-upward pattern. Without multiple logs or good seismic data, this kind of interpretation can be a daunting task. There are several unpublished examples of fields in different basins where seemingly definitive interpretations were made based on one wireline log and seismic data. But once production was established or additional wells were drilled, the interpretation had to be modified to fit a more complex reservoir distribution. Therefore, we urge caution when interpreting deepwater elements based on the wireline log signature from only a few wells. RFT data can help identify laterally continuous shales that are more characteristic of sheets than channel-fill.

Arreguin (2003) showed an example of layered and amalgamated sheet sands from the Cocuite Field in the southeastern Veracruz Basin (Fig. 8-17). At the upper Miocene level, a single channel bifurcates downdip to smaller channels and then to sheets. There is a clear updip to downdip transition in the gamma ray log response. For the updip portion, the gamma ray response is blocky and thick, reflecting amalgamated sheets, changing laterally and down-fan to layered sheet deposits.

Figure 8-17.

RMS amplitude map and geologic interpretation for a 40 MS window in upper Miocene sequence, Cocuite Field, Veracruz Basin, Mexico. Sheet sands are cut by faults (linear features). Sediment transport was from the northwest to the southeast. Five wireline logs illustrate both layered and amalgamated sheet sands in the interval. Scale on wireline logs is in meters. After Arreguin (2003). Reprinted with permission of Marco J. J. Arreguin.

Figure 8-17.

RMS amplitude map and geologic interpretation for a 40 MS window in upper Miocene sequence, Cocuite Field, Veracruz Basin, Mexico. Sheet sands are cut by faults (linear features). Sediment transport was from the northwest to the southeast. Five wireline logs illustrate both layered and amalgamated sheet sands in the interval. Scale on wireline logs is in meters. After Arreguin (2003). Reprinted with permission of Marco J. J. Arreguin.

Shanley et al. (2000) defined several seismic facies for three sub-classes of sheets in the northern Gulf of Mexico, and then related these to net:gross. These seismic facies were recognized on the basis of subtle differences in seismic stratigraphic expression, correlated to well log penetrations (Fig. 8-18): (C1) channelized, tabular/sheets and mounded sheets are characterized by parallel reflections that are concordant at the base; (C2) amalgamated/layered tabular sheets are similar to facies C1 but vary in continuity and amplitude consistency; and (3) mounded tabular/sheets, which differ from the two previous classes by subtle onlap at the base. These three seismic facies can appear to be subtly mounded across a large distance. The dimensions for all three classes of sheets are the same: 2-15 km across and 2-30 km along transport direction.

Figure 8-18.

Schematic drawing of different facies types in northern Gulf of Mexico. Three types of sheet sands (C1-3) are present. After Shanley et al. (2000). Reprinted with permission Gulf Coast Section SEPM Foundation.

Figure 8-18.

Schematic drawing of different facies types in northern Gulf of Mexico. Three types of sheet sands (C1-3) are present. After Shanley et al. (2000). Reprinted with permission Gulf Coast Section SEPM Foundation.

Shanley et al. (2000) calculated net:gross values from well log data. Cumulative probability distributions for net:gross were then calibrated to the seismic facies for risk analysis, and to provide additional information for seismic attribute analyses. These data are useful in basins where there is little to no well control, and predictions must be made primarily based on seismic data.

Development-scale characteristics

Important features of sheets at the development scale are presented here, first using outcrop, then subsurface reservoir examples to illustrate the effect of these features on reservoir production performance. The most important features at this scale are net-to-gross (either at any given location on a sheet sand and sandstone reservoir or in the downdip direction); lateral bed continuity; vertical bed connectivity; and bed-scale features such as sedimentary structures, textures, and composition. These features are often beneath the resolution of conventional 2D and 3D seismic, and are termed ‘sub-seismic’ scale features of deepwater reservoirs (Slatt and Weimer, 1999). Within this context, the reader should be aware that discussions of vertical and offset stacking of sedimentary units refer to individual beds, as opposed to the stacking of packages of beds at the seismic scale, described above.

Examples of sheet sandstone outcrops

Twelve outcrops in the world have well-exposed sheet sands and sandstones, and therefore have been extensively described and characterized (Table 8-1 ; Fig. 8-19). Below, we illustrate select outcrops in which data on lateral, vertical, and internal attributes of beds have been measured. These outcrops represent sand-prone, mixed sand-mud prone, and mud-prone deepwater systems (Richards et al., 1998).

Table 8-1.

Outcrops with sheet sandstones commonly used for reservoir modeling.

Figure 8-19.

Map showing (a) location of most common outcrops of sheet sandstones used by companies for outcrop characterization/reservoir modeling (Table 8-1 ), and (b) location of producing fields discussed in the text.

Figure 8-19.

Map showing (a) location of most common outcrops of sheet sandstones used by companies for outcrop characterization/reservoir modeling (Table 8-1 ), and (b) location of producing fields discussed in the text.

Upper Carboniferous Ross Formation, Western Ireland

The original definitions for amalgamated and layered sheet sands were based on outcrop studies of the sand-prone, Upper Carboniferous Ross Formation in western Ireland (Chapin et al., 1994) (Fig. 8-20). Table 8-2 provides data on characteristics of some Ross Formation outcrops. Paleocurrent and outcrop orientation data provided by Chapin et al. (1994) indicate that the exposures are oblique to depositional strike by about 40 degrees.

Table 8-2.

Layered and amalgamated sheet sandstone outcrops, Ross Formation, Ireland (Chapin et al., 1994).

Figure 8-20.

(a) Cross section based on pseudo gamma ray logs of the Kilcloher Cliff Section, Upper Carboniferous Ross Formation, western Ireland. The lower section is composed of layered sheet sandstones with a net:gross of 54%, and 3% sand-on-sand bed contacts. The upper section is composed of amalgamated sheet sandstones with 90% net:gross and 67% sand-on-sand bed contacts. Length of the outcrop is approximately 660 m (2000 feet). After Chapin et al. (1994) Reprinted with permission of Gulf Coast Section SEPM Foundation.

Figure 8-20.

(a) Cross section based on pseudo gamma ray logs of the Kilcloher Cliff Section, Upper Carboniferous Ross Formation, western Ireland. The lower section is composed of layered sheet sandstones with a net:gross of 54%, and 3% sand-on-sand bed contacts. The upper section is composed of amalgamated sheet sandstones with 90% net:gross and 67% sand-on-sand bed contacts. Length of the outcrop is approximately 660 m (2000 feet). After Chapin et al. (1994) Reprinted with permission of Gulf Coast Section SEPM Foundation.

Figure 8-20.

(b) Outcrop photograph of the layered and amalgamated sheet sandstones at Kilcloher Cliff Section. After Sullivan et al. (2000). Reprinted with permission of Gulf Coast Section SEPM Foundation.

Figure 8-20.

(b) Outcrop photograph of the layered and amalgamated sheet sandstones at Kilcloher Cliff Section. After Sullivan et al. (2000). Reprinted with permission of Gulf Coast Section SEPM Foundation.

Amalgamated and layered sheet sandstones occur within the sections. At the West Kil-cloher section, there is an upward change from layered sheets with a relatively low net:gross (54%) and degree of amalgamation (3%) to amalgamated sheets with a high net:gross (90%) and degree of amalgamation (67%) (Fig. 8-20).

Permian Skoorsteenberg Formation, South Africa

The Permian Skoorsteenberg Formation in South Africa provides an excellent example of deepwater deposits because the formation crops out almost continually for 640 km2 and provides almost continuous exposure for up to 60 km in length (Johnson et al., 2001). It is an example of a fine-grained, mud rich, submarine fan system (Wickens and Bouma, 2000). Several separate fans (five fans according to Johnson et al., 2001; six fans according to Wickens and Bouma, 2000) comprise the Skoorsteenberg Formation. The 450 m thick basin fill indicates a progradational trend from distal basin floor (Fan 1) through basin-floor sub-environments (Fans 2-4), to a slope setting (Fan 5) (Johnson et al., 2001). Individual fans are up to 65 m thick with gradational to sharp bases and tops. Each of the fans is interpreted as the product of low-frequency lowstand deposition, with intervening shales representing transgres-sive-highstand deposition.

Johnson et al. (2001) provide some general characteristics of the sheet sandstones. They have a tabular geometry with planar upper and lower surfaces and can be divided into amalgamated and layered sheets. Amalgamated sheets contain thin-bedded (<40 cm) to thick-bedded (>40 cm) sandstones that exhibit compensation bedding styles. Amalgamated sheets occur as thick units (up to 15 m) in the mid- to outer fan region, downdip of feeder systems, and in areas between channels in the mid-fan setting (Fig. 8-21). In the latter setting, sheets are thinner and tend to be dominated by ripple-laminated (Tc) sandstones that alternate with massive sandstones. Layered sheets also exhibit planar upper and lower surfaces with an overall tabular geometry. Layered sandstones are interbedded with siltstone and claystone. In the updip direction, the layered sheets are composed of beds mainly >40 cm thick, while in the downdip direction layered sheets are <40 cm thick. The layered sheets are common between channels in the mid- to upper fan and are dominated by ripple-laminated (Tc) beds. Net sand is usually <40%, but may reach 60%. The overall thickness of sheet units and net sand do not generally change in the strike dimension, but both decrease in the downdip direction (Fig. 8-22).

Figure 8-21.

Outcrop photograph of sheet sandstones, Grootvontein section, Permian Skoorsteenberg Formation, South Africa. Correlation panel with measured sections show lithofacies, and degree of amalgamation within the sheets. Photograph shows a portion of the outcrops described in the correlation panel. After Sullivan et al. (2000). Reprinted with permission of Gulf Coast Section SEPM Foundation.

Figure 8-21.

Outcrop photograph of sheet sandstones, Grootvontein section, Permian Skoorsteenberg Formation, South Africa. Correlation panel with measured sections show lithofacies, and degree of amalgamation within the sheets. Photograph shows a portion of the outcrops described in the correlation panel. After Sullivan et al. (2000). Reprinted with permission of Gulf Coast Section SEPM Foundation.

Figure 8-22.

Strike and dip outcrop correlation sections of the Permian Skoorsteenberg Formation, South Africa. There is a systematic decrease in thickness in the west to east dip direction, but the south to north strike section shows no such change. Shales also extend the length of the strike section, and would be fluid flow barriers in an analogous reservoir. Shales are also long and increase in abundance along the down-dip direction. There are fewer shales in the more proximal area to the west. After Wickens and Bouma (2000). Reprinted by permission of Gulf Coast Section SEPM Foundation.

Figure 8-22.

Strike and dip outcrop correlation sections of the Permian Skoorsteenberg Formation, South Africa. There is a systematic decrease in thickness in the west to east dip direction, but the south to north strike section shows no such change. Shales also extend the length of the strike section, and would be fluid flow barriers in an analogous reservoir. Shales are also long and increase in abundance along the down-dip direction. There are fewer shales in the more proximal area to the west. After Wickens and Bouma (2000). Reprinted by permission of Gulf Coast Section SEPM Foundation.

Rozman (2000) described Fan 2 and related the fan’s characteristics to potential reservoir performance. Fan 2 is 3-10 km in length and 100-2000 m in width. It consists of upper, middle, and lower sandstone units, each 5-15 m thick and separated by 3 m thick silty-shale intervals. Net sand varies from 78-85% in the three units. Sandstone intervals are composed of 10-100 cm thick beds of very fine-grained, massive to Ta (graded) sandstones and 2-20 cm thick, parallel-laminated siltstone. There is no consistent downdip change in average sandstone bed thickness nor in the percentage of net sand. Rozman (2000) used the classification of Slatt and Galloway’s (1992) for reservoir scale heterogeneities of Fan 2, as follows:

  • Wellbore Scale: Uniformity of grain size and sorting, and absence of prominent sedimentary structures implies ease of fluid flow through the sandstones. However, shale clasts, which are common in some Fan 2 sandstones, might be potential barriers or baffles to fluid flow.

  • Interwell Scale: The sandstone beds and sets of beds are laterally continuous over significant distances in Fan 2, thus providing the potential for areally extensive well drainage areas. The common occurrence of scoured beds, noted by both Rozman (2000) and Morris et al. (2000), results in discontinuous amalgamation of overlying and underlying sandstone beds, which, without the scour, would be separated by shale. This feature results in a higher degree of amalgamation than might be expected by examining one vertical section of strata in a core or image log. The increased amalgamation of sandstones should have a significant positive impact on vertical connectivity. Shales thinner than 10 cm in Fan 2 are likely to be scoured away at some point over their 3D area. In 2D space, mean siltstone lengths are only 167-260 cm. Rozman (2000) notes that the degree of scouring and amalgamation decreases only slightly in the downdip direction.

  • Field Scale: Fan 2, or even its component three individual units, can be considered small fieldwide features. Each sandstone unit can be considered an individual flow unit, which, because of thicker, intervening shales, only will be in communication if the beds are faulted and/or fractured.

Table 8-3 combines additional details of Fans 1, 2, and 4 from Morris et al. (2000) and Fan 4 deposits from Dudley et al. (2000). Note that Morris et al. (2000) consider amalgamated sheets to be proximal fan deposits and layered sheets to be distal deposits.

Table 8-3.

Characteristics of sheet sandstones of the Skoorsteenberg Formation, South Africa (combined from Dudley et al., 2000, and Morris et al., 2000).

*According to Johnson et al. (2001), net sand decreases to <40% distally.

Figure 8-23 (b).

Note the presence of both thinning- and thickening-upward cycles within the sheets, the flat tops and bases to the beds that are separated by thin shale zones. After Beaubouef et al. (1999). Reprinted with permission of the AAPG.

Figure 8-23 (b).

Note the presence of both thinning- and thickening-upward cycles within the sheets, the flat tops and bases to the beds that are separated by thin shale zones. After Beaubouef et al. (1999). Reprinted with permission of the AAPG.

Permian Brushy Canyon Formation, West Texas, USA

The Permian Brushy Canyon Formation in West Texas comprises 500m of deepwater sandstones and siltstones (water depths of 400-600m) that lap onto older carbonate slope deposits at the northwest margin of the Delaware Basin (Beaubouef et al., 1999). Oblique-dip outcrops expose channel and related stratal geometries that were deposited from the slope to the basin floor. Lowstand fan systems tracts consist of sharp-based, laterally extensive, sand-prone basin floor fan deposits (Fig. 8-23a, b) and large, sand-filled channels deposited on the slope. Several depositional cycles are present, each attributed to the following three phases: (1) erosion, mass wasting, and sand bypass on the slope with concurrent deposition of sand on the basin floor; (2) progressive backfilling of feeder channels; and (3) cessation of sand delivered to the basin, and deposition of laterally-extensive, blanket siltstones (Beaubouef et al., (1999).

Figure 8-23 (a).

Outcrop photograph of the sheet sandstones, Colleen Canyon section, Permian Brushy Canyon Formation, west Texas.

Figure 8-23 (a).

Outcrop photograph of the sheet sandstones, Colleen Canyon section, Permian Brushy Canyon Formation, west Texas.

Beaubouef et al. (1999) and Carr and Gardner (2000) have described the basin-floor fan deposits as the products of high-density, unconfined sediment gravity flows. A core collected behind the outcrop, the EPR Co. Colleen Canyon #1 well, penetrated 73m of the Colleen Canyon section, interpreted as mainly sheet axis and channel/sheet margin facies by Beaubouef et al. (1999). According to Carr and Gardner’s outcrop studies, deposits exhibit bed compensation, and as a result, non-unique stacking patterns.

The Colleen Canyon section, which is interpreted to have been deposited about 32 km downdip from the coeval shelf edge (Carr and Gardner, 2000), consists of three cycles and represents a channel-to-sheet transition zone. Fan 3 contains mainly unconfined sheet flows with only minor channel fills. It is a uniform 30m thick, and contains three high frequency strati-graphic cycles labeled 1 to 3, from oldest to youngest. Characteristics of these cycles are summarized in Table 8-4 .

Table 8-4.

Fan 3, Permian Brushy Canyon Formation, west Texas.

Beaubouef et al. (1999) and Gardner and Borer (2000) describe another basin-floor fan within the Codorniz Canyon Section (Table 8-4 ). According to Beaubouef et al. (1999), the sandstone packages are laterally continuous for long distances, and of uniform thickness. However, lenticular and compensatory sandstone bedding styles and small-scale scour surfaces are locally present, as are dewatering structures and flat, non-erosional bed bases. Bed amalgamation increases toward the axis of the sheet-sand complex.

Pennsylvanian Jackfork Group, Arkansas, USA

The Pennsylvanian Jackfork Group in Arkansas provides an example of a mixed sand-mud submarine fan system. Table 8-5 shows the percentages of different types of beds within a total of 1800 m of measured stratigraphic section from 11 outcrops interpreted to have been deposited in a downdip, base-of-slope to basinal setting. Also shown in the table are the % sand (net-gross), % of sand-on-sand bed contacts, calculated rate of bed thinning (= change in bed thickness in meters/100 m of lateral bed distance; expressed as %), and rate of change in % sand (=change in % sand/100m lateral bed distance) within a 300m section at one of these outcrops. In these outcrops, layered and amalgamated sheets tend to be grouped into larger packages from outcrop to outcrop, and are separated by thick, laterally continuous shales (Fig. 8-24).

Table 8-5.

Layered and amalgamated sheet sandstone outcrops, Jackfork Group, Pennsylvanian, south central Arkansas (Slatt et al., 2000).

Figure 8-24.

(A) Schematic measured stratigraphic section (Morris, 1971) and outcrop gamma ray log (DeGray East) of the DeGray Lake Spillway section of the upper Jackfork Group, Pennsylvanian, Arkansas. These sections are correlated to a well log from the Shell Rex-Timber #1-9 well, drilled through the same stratigraphic section 9.5 km to the southwest (Slatt et al., 2000). The two wells form an oblique depositional strike orientation, and represent a minimum distance down the depositional axis (from the outcrop to the well), because major faults occur between the two areas. (B) Outcrop photograph shows the entire 300+m (1000 feet) thick DeGray Spillway section. (C) Photograph showing details of a 27 m (81 feet) thick interval of layered (lower part of interval) to amalgamated (upper part of interval) sheet sandstones which occurs within the Spillway section (box). Rate of change of thickness for this interval is calculated to be 12.5 m/km or 1.25%.

Figure 8-24.

(A) Schematic measured stratigraphic section (Morris, 1971) and outcrop gamma ray log (DeGray East) of the DeGray Lake Spillway section of the upper Jackfork Group, Pennsylvanian, Arkansas. These sections are correlated to a well log from the Shell Rex-Timber #1-9 well, drilled through the same stratigraphic section 9.5 km to the southwest (Slatt et al., 2000). The two wells form an oblique depositional strike orientation, and represent a minimum distance down the depositional axis (from the outcrop to the well), because major faults occur between the two areas. (B) Outcrop photograph shows the entire 300+m (1000 feet) thick DeGray Spillway section. (C) Photograph showing details of a 27 m (81 feet) thick interval of layered (lower part of interval) to amalgamated (upper part of interval) sheet sandstones which occurs within the Spillway section (box). Rate of change of thickness for this interval is calculated to be 12.5 m/km or 1.25%.

Reservoir implications of outcrop characteristics

Lateral continuity

Thickness and lateral changes in thickness of individual beds and packages of beds are critical parameters in the performance and ultimate recovery of petroleum from a reservoir. The greater the thickness and continuity of reservoir sandstones, the larger the drainage area that can be covered by a single producing well, and the fewer wells will be required during primary and secondary recovery. Amalgamation of individual sandstone beds also can significantly improve vertical connectivity, and thus producibility.

The actual lengths of sheet sandstones are difficult to determine in outcrop. Ideal outcrops for continuity measurement are long, and the beds are horizontal to near-horizontal (Slatt, 2000). Unfortunately, sheet sandstone beds are often longer than the length of the outcrop. For example, most beds are longer than the 700-1370 m length of the Ross Formation outcrops (Table 8-2 ), so that the actual lengths of beds as they were originally deposited cannot be documented. Unless both ends of a bed pinch out within the outcrop, only a minimum length is measurable. Such is the case with most outcrops, including those of the Ross Formation.

Although total bed lengths cannot usually be measured in outcrop, rates of change of bed thickness are measurable, and provide a means of estimating the original lengths or lateral continuity of beds and packages of beds. Data in Table 8-2 –8-5 indicate that individual amalgamated sheet sandstones tend to be thicker than layered sheet sandstones. Because only minimum depositional lengths are normally measured in outcrops, lateral variations in bed thickness and net sandstone also cannot be measured. However, by measuring thickness and net:gross (% sand) of correlative strata over known distances (i.e. a single continuous outcrop, or discontinuous, but correlative outcrops), a rate of lateral change of thickness can be calculated. In the Skoorsteenberg Formation, variations in gross sandstone and sandstone thickness have been measured in a 1.9 km dip direction and a 1.2 km strike direction (Fig. 8-22). In the dip direction, the rate of change of bed thickness is 0.23% and there is no appreciable change in the strike direction. By contrast, for Jackfork strata, rates of change in thickness vary from 0.36% for layered sheet sandstones to 0.43% for amalgamated sheet sandstones across distances up to 1.3 km (Table 8-5 ) (Al-Siyabi, 2000; Slatt et al., 2000). One sheet sandstone lobe 27 m thick increases in thickness to 47 m over a distance of 9.5 km (0.2% rate of change), suggesting this is a very large lobe (Fig. 8-24). Individual beds within this lobe exhibit alternate thickening and thinning of stacked beds over a 90 m distance in the transport direction oblique to strike, indicative of compensation-style bedding (Slatt et al., 2000).

Although such measurements provide a means of predicting lateral continuity of beds and packages of beds, this calculation method assumes a constant rate of change over lateral distances. This assumption may not always be correct. For example, in the Eocene-Oligocene Gres d’Annot (a sand-rich submarine fan system) in the Trois Eveches area of France, Hurst et al. (1999) recognized variations in thickness and lateral continuity that are attributable to offset stacking (i.e. compensation deposition), and to a lesser extent, to erosional scour along a 2.5 km long outcrop belt of sheet sandstones. Vertical trends in bed thickness are different from place to place along the outcrop (i.e. thinning upward at one location and thickening upward at another), although the gross thickness of the package may not vary over such distances, at least in the strike dimension (for another example, see Fig. 8-22).

Also, compensation bedding styles are common in sheet sands and sandstones, giving rise to lateral variations in thickness (Mutti and Sonnino, 1981). In the strike direction, beds thicken and thin according to the thickness of underlying strata upon which a sediment gravity flow, or group of flows is deposited. Thus, bed thickness and continuity will not remain constant in the lateral dimension.

Differential erosion along a sandstone bed can also alter any systematic variation in lateral continuity of the bed. For example, Lomas et al. (2000) described the 30+ m thick “FB” section of the Gres d’Annot Sandstone. This section records a downcurrent trend of almost continuous outcrop exposure of an amalgamated sheet deposit over a 1.7 km distance. Although individual beds are highly amalgamated, they are not traceable laterally for more than 100-200 m due to erosional scour. In another 3 km long cliff exposure of the Gres d’Annot Sandstone, Joseph et al. (2000) found that amalgamated beds 1-10 m thick form continuous tabular bodies up to 25 m thick and >5 km long. Common internal scouring led Joseph et al. (2000) to conclude that these sandstones were ‘channelized lobes’. As discussed above, sheet sandstones in the Skoorsteenberg Formation are also intermittently amalgamated along scour surfaces.

The geometry of sheet sandstone pinchouts can also be variable. Hurst et al. (1999) differentiated between gradational pinchouts resulting from beds that onlap a relatively flat surface in an unconfined setting and to abrupt pinchouts of beds infilling the sides of a depression in a confined setting (Fig. 8-25). The vertical profiles along a sandstone package, do not allow for the prediction of lateral pinchout geometry. However, pinchout geometry can be important in volumetric calculations and reservoir performance modeling.

Figure 8-25.

Schematic cross section showing two types of depositional edges to sheet sandstones (yellow): (a) gradational depositional pinchout along a flat surface, (b) onlap onto an inclined surface. The type of edge in a reservoir can have a pronounced effect on volumetric calculations. After Hurst et al. (1999). Reprinted with permission of AAPG.

Figure 8-25.

Schematic cross section showing two types of depositional edges to sheet sandstones (yellow): (a) gradational depositional pinchout along a flat surface, (b) onlap onto an inclined surface. The type of edge in a reservoir can have a pronounced effect on volumetric calculations. After Hurst et al. (1999). Reprinted with permission of AAPG.

Vertical connectivity

Vertical connectivity is another important factor that affects production performance of sheet sand and sandstone reservoirs. Vertical connectivity is a measure of the vertical stacking of sandstone beds upon each other, with or without intervening beds such as shale. Vertical connectivity is relatively high in amalgamated sheet sands and sandstones, where amalgamation of individual sand beds may be a result of (1) deposition of sands directly onto underlying sands without intervening mud deposition and/or (2) erosion (scour) and removal of mud interbeds above a sand bed by a succeeding sandy flow so that the two sands become amalgamated. By contrast, layered sheets sandstones show relatively low vertical connectivity.

The percentage of beds with sand-on-sand (amalgamated) contacts within a strati-graphic succession is another means of differentiating between amalgamated and layered sheet sands and sandstones. For intervals in the sand-prone Ross Formation that contain >80% net sandstone, sand-on-sand bed contacts reach 60% of the total contacts (the remainder being sandstone on shale), whereas intervals containing >80% net sandstone contain up to 40% sand-on-sand contacts (Table 8-2 ). For the mixed mud-sand prone Jackfork Group, amalgamated sheet sandstones contain 80% sand-on-sand contacts, whereas layered sheet sandstones contain 53% sand-sand contacts (Table 8-5 ). For amalgamated sheet sandstone intervals in the mud-prone Skoorsteenberg Formation, the percentage of bed contacts that are sand-on-sand reaches 66%, whereas for layered sheet sandstones, the percentage of sand-on-sand contacts only reaches 33% (Table 8-3 ). Comparison of these data indicates that within a stratigraphic succession, the higher the net sandstone content the greater the percentage of amalgamated bed contacts. However, there is no apparent, systematic difference between net sandstone and percentage of amalgamated sand-on-sand contacts among sand-prone, mixed sand-mud, and mud-prone deposits.

Because of their higher net sand content, amalgamated sheet sands and sandstones generally occur in a more proximal environmental setting, where sand supply is greater and sediment gravity flows are more energetic. By contrast, layered sheets sandstones generally occur in a more distal or lateral setting, where the sand volume is less and flows are less energetic. Thus, bases of individual amalgamated sheet sand and sandstone beds may or may not be erosional. In contrast, bases and tops of layered sheet sand and sandstone beds are more likely to be flat and non-erosive. As stated above, amalgamated sheet sandstone beds tend to be thicker than layered sheet sandstone beds in the Ross and Jackfork sandstones (Table 8-2 , 8-5). Because amalgamated sheet sandstones are generally more proximal than layered sheet sandstones in terms of deposition within a sheet sandstone complex, then one might expect amalgamated sheet sandstone beds to exhibit a greater number of erosive bases than do layered sheet sandstone beds. This has been shown to be true for the Gres d’Annot Sandstone (Hurst et al., 1999), but not for Fan 2 of the Skoorsteenberg Formation (Rozman, 2000).

The effect of shales on continuity and connectivity

The preceding discussion has referred mainly to sheet sand and sandstone beds. However, the lateral continuity of shales is also a critical factor in reservoir performance, primarily because laterally continuous shales may vertically isolate individual sand and sandstone beds, especially for layered sheets sands. Shales deposited in an unconfined setting tend to be at least as laterally continuous as associated sands and sandstones. These shales may be the deposits of the fine-grained tails of turbidity currents, pelagic rain of siliciclastic silt and clay, and/or carbonate/siliceous tests of micro-organisms. The influence of such shales is to limit vertical connectivity. Thererfore, the longer the shale bed, the less opportunity for vertical connectivity to develop between sandstones (Schuppers, 1993). For example, in the West Kilcloher section of the Ross Formation (Fig. 8-20), approximately 50% of the shales are longer than 280 m, so that vertical connectivity can be impeded at greater lengths in an analog sheet reservoir (Stephen et al., 2001).

A hierarchy of shale intervals do affect vertical connectivity. For example, the six fans of the Skoorsteenberg Formation are each separated by shales that are 20-75 m thick (Morris et al., 2000). At the next smaller scale, the 60m thick Fan 4 is composed of six separate layered to amalgamated sheet packages, each separated by shales and fine-grained beds (Bouma Tbcde) ranging from 0.5 to 2 m in thickness. Shales separating upper, middle, and lower sands of Fan 2 are on the order of 3 m thick (Rozman, 2000).

A similar distribution of mudstone intervals has been described for the associated Laingsburg Formation in the Karoo Basin (Sixsmith et al., 2004). In addition to 20- to 80-m-thick shale and mudstone intervals that separate the six lowstand sheet sandstone units comprising the formation, smaller sandstone intervals within each unit are separated by laterally continuous mudstones. One of the six sheet sandstone units, termed Fan A, is 350 m thick and consists of seven individual 4th-order lowstand sheet sandstones, each separated by 1- to 20-m-thick transgressive/highstand mudstones. These high-order mudstones are what will vertically isolate individual sandstone intervals.

Another example is the Miocene Mt. Messenger Formation mixed sand-mud submarine fan system of New Zealand. Four sheet sandstone packages, ranging in thickness from 10 to 50m each, can be clearly distinguished on a conventional well log and in outcrop (Fig. 8-26) (Brown and Slatt, 2002). Each sandstone package is separated by a shaley to marly interval up to 20 m thick. A 2D seismic line acquired near the outcrop illustrates four high-amplitude, continuous seismic reflections that have been correlated to the well log, and to the four sandstone packages in outcrop (Fig. 8-26). In this instance, the marls and sandstones provide sufficient acoustic contrast to generate strong seismic reflections at their interface. The four sandstone packages have been traced inland in the third dimension, for a distance of 6-8 km, where they pinch out against slope shales (Fig. 8-26). Such marls are also present in northern deep Gulf of Mexico reservoirs (Meckel et al., 2002), and can be significant barriers to vertical connectivity.

Figure 8-26.

Diagrams showing different aspects of the upper Miocene, Mt. Messenger Formation, New Zealand. (A) Wireline logs of the Pukearhue #1 well drilled immediately downdip of outcrops of equivalent strata. Four sheet sandstones (referred to as basin-floor fan complex) are shown on the logs. These same four sandstone packages crop out a few km to the north. (B) Schematic cross section of the four sheet sandstones. Each sandstone package (yellow) is erosionally based, and is separated by marls and shales (brown). The northwest end of this section occurs along a beach, so that the vertical stratigraphy is visible. In the third dimension (inland), the sandstones can be discontinuously traced about 8 km inland from the coast, where they pinch out against slope shales. Proportions of sandstones at different locations are shown by the pie diagrams. (c) Location of the Pukearuhe #1 well in relation to a north-south 2D seismic line. The four sheet sandstones correlate to four high amplitude, continuous seismic reflections. Presumably, the reflections are a result of the acoustic contrast between the sandstones and intervening marls/shales. After Browne and Slatt (2002). Reprinted with permission of AAPG.

Figure 8-26.

Diagrams showing different aspects of the upper Miocene, Mt. Messenger Formation, New Zealand. (A) Wireline logs of the Pukearhue #1 well drilled immediately downdip of outcrops of equivalent strata. Four sheet sandstones (referred to as basin-floor fan complex) are shown on the logs. These same four sandstone packages crop out a few km to the north. (B) Schematic cross section of the four sheet sandstones. Each sandstone package (yellow) is erosionally based, and is separated by marls and shales (brown). The northwest end of this section occurs along a beach, so that the vertical stratigraphy is visible. In the third dimension (inland), the sandstones can be discontinuously traced about 8 km inland from the coast, where they pinch out against slope shales. Proportions of sandstones at different locations are shown by the pie diagrams. (c) Location of the Pukearuhe #1 well in relation to a north-south 2D seismic line. The four sheet sandstones correlate to four high amplitude, continuous seismic reflections. Presumably, the reflections are a result of the acoustic contrast between the sandstones and intervening marls/shales. After Browne and Slatt (2002). Reprinted with permission of AAPG.

Shales within a single sheet sandstone package can also be quite areally extensive and directionally variable in length. For example, most of the shale beds on Skoorsteenberg Formation Fan 4 are >1200 meters long in the strike direction but only >600 m long in the dip direction (Dudley et al., 2000). Thus, vertical sandstone connectivity is better in the dip direction than in the strike direction. Dudley et al. (2000) used this information to develop different drilling scenarios in the strike and dip directions of a reservoir. The opposite trend occurs for the Annot Sandstone where shale beds are laterally continuous for 1500 m in the dip direction, but only about 500 m in the strike direction (Moraes et al., 2000).

Texture, compositional, and structural characteristics of sheet sands and sandstones

Grain-size of sheet sands and sandstones may be quite variable, depending upon the source lithology of sand, the grain size of the sand in the source area, the energy of the sediment gravity flows from which the sands were transported and deposited, and the overall nature of the depositional environment. In general, sheet sands and sandstones from sand-prone systems tend to be coarser-grained than sheet sandstones from mud-prone systems.

Some amalgamated sheet sandstones, such as the Annot Sandstone, are conglomeratic. Beds are 30-600 cm thick, exhibit flat to strongly scoured bases, and may contain shale rip-up clasts (Lomas et al., 2000). Many beds are structureless, but cross-stratification and horizontal stratification of sandstone beds are common. Massive, ungraded, and Bouma Ta sandstones predominate in amalgamated sheet sandstones. Thinner-bedded, layered sheet sandstones, deposited in a relatively more distal setting, tend also to contain Bouma Ta beds, but also with Tb, Tc, and Td beds. Massive (ungraded), structureless sandstones also predominate in the Skoorstenberg Formation sheet sandstones (Dudley et al., 2000) (Fig. 8-27), the Mt. Messenger Formation sheet sandstones (Browne and Slatt, 2002) and in the lower Brushy Canyon Formation (west Texas) sheet sandstones (Table 8-4 ) (Carr and Gardner, 2000).

Figure 8-27.

Pie diagrams illustrating the proportion of various sedimentary facies in the Permian Skoorsteenberg sheet sandstones, South Africa. Note that the most common facies is a structureless (massive) sandstone. Structureless sandstones have also been noted as being most common in other sheet sandstones examined by the authors. After Morris (2000). Reprinted with permission of Gulf Coast Section SEPM Foundation.

Figure 8-27.

Pie diagrams illustrating the proportion of various sedimentary facies in the Permian Skoorsteenberg sheet sandstones, South Africa. Note that the most common facies is a structureless (massive) sandstone. Structureless sandstones have also been noted as being most common in other sheet sandstones examined by the authors. After Morris (2000). Reprinted with permission of Gulf Coast Section SEPM Foundation.

Identifying layered and amalgamated sheets in subsurface cores and borehole image logs

Based upon the various sedimentologic and stratigraphic characteristics described above, differentiating layered from amalgamated sheet sandstones in core and image logs should be fairly easy. Layered sheet sandstones will be interbedded with shales, whereas amalgamated sheet sandstones will exhibit amalgamated, sand-on-sand contacts (Figs. 8-28, 8-29). If a scour surface separating amalgamated beds is sufficiently deep, it can be detected in core or on an image log (Fig. 8-30).

Figure 8-28.

Core photographs of the amalgamated sheet sands of the Lower Yellow reservoir, Mars Field, northern deep Gulf of Mexico. Photographs show cores under normal and UV light (showing gold fluoresence of oil). Sands are massive to planar laminated. Wireline log on the right shows the response of the cored interval. After Cumming (2002). Reprinted by permission of Gulf Coast Section SEPM Foundation.

Figure 8-28.

Core photographs of the amalgamated sheet sands of the Lower Yellow reservoir, Mars Field, northern deep Gulf of Mexico. Photographs show cores under normal and UV light (showing gold fluoresence of oil). Sands are massive to planar laminated. Wireline log on the right shows the response of the cored interval. After Cumming (2002). Reprinted by permission of Gulf Coast Section SEPM Foundation.

Figure 8-29.

Core photograph of layered sheets sands of the Upper Yellow reservoir, Mars field, northern deep Gulf of Mexico. Photographs show cores under normal and UV light (showing gold fluoresence of oil). Sand beds exhibit primarily planar laminations changing upward to ripple laminations. After Cumming (2002). Reprinted by permission of Gulf Coast Section SEPM Foundation.

Figure 8-29.

Core photograph of layered sheets sands of the Upper Yellow reservoir, Mars field, northern deep Gulf of Mexico. Photographs show cores under normal and UV light (showing gold fluoresence of oil). Sand beds exhibit primarily planar laminations changing upward to ripple laminations. After Cumming (2002). Reprinted by permission of Gulf Coast Section SEPM Foundation.

Figure 8-30.

STAR (copyright Baker-Hughes Inc.) borehole image log from the Barrel Springs 7-22 well, Dad Sandstone Member, Upper Cretaceous Lewis Shale, Wyoming. (A) Static image showing sandstones (yellow), very-fine grained sandstones and siltstones (orange) and mudstone and shales (reddish-brown to black). Flat, non-scoured bases of Bouma Ta and Tb bed couplets are shown, along with a single scour surface.(B) Dynamic normalized image from the Barrel Springs 7-22 well showing chaotic bedding due to rapid dewatering of supersaturated sand. (C) Dynamic normalized image from the Barrel Springs 7-22 well showing convolute bedding compared with similar outcrop features, and vertical dewatering pipes. After Witton-Barnes et al. (2000). Reprinted with permission of Gulf Coast Section SEPM Foundation.

Figure 8-30.

STAR (copyright Baker-Hughes Inc.) borehole image log from the Barrel Springs 7-22 well, Dad Sandstone Member, Upper Cretaceous Lewis Shale, Wyoming. (A) Static image showing sandstones (yellow), very-fine grained sandstones and siltstones (orange) and mudstone and shales (reddish-brown to black). Flat, non-scoured bases of Bouma Ta and Tb bed couplets are shown, along with a single scour surface.(B) Dynamic normalized image from the Barrel Springs 7-22 well showing chaotic bedding due to rapid dewatering of supersaturated sand. (C) Dynamic normalized image from the Barrel Springs 7-22 well showing convolute bedding compared with similar outcrop features, and vertical dewatering pipes. After Witton-Barnes et al. (2000). Reprinted with permission of Gulf Coast Section SEPM Foundation.

If bedding surfaces are flat and not erosive, they are much more readily apparent in cores or image logs of sandstones than in cores of unconsolidated sandstone (Fig. 8-30). For example, individual, unconsolidated sheet sands from the Ranger Zone of the Long Beach Unit, Wilmington Field, California often do not exhibit a large range of grain sizes in some intervals (Slatt et al., 1993), so it is difficult to identify amalgamation surfaces in core (Fig. 13-6 [Chapter 13] and Fig. 4-23 [Chapter 4]). Often, the only way to identify an amalgamated surface is by noting a slight upward decrease in ‘grittiness’ (indicating a fining of grain-size), as determined by touch or with a spatula, or a sharp increase in ‘grittiness’ (indicating a sharp increase in grain-size).

Vertical stratification features also are relatively easy to see on image logs as well as in core. Figure 8-31 illustrates a Gulf of Mexico deepwater sand body that is thinly bedded at its base, but becomes more thickly bedded upward. The gamma-ray log to the left shows a vague cleaning- upward pattern, but individual beds are not resolvable. The thicker-bedded part of the succession is oil-bearing, whereas the thinner part is water-bearing. Internal sedimentary structures and textures also can sometimes be identified on high-quality image logs (Fig. 8-30).

Figure 8-31.

Borehole image of a coarsening- and cleaning-upward, layered to amalgamated sheet sand interval from a Pliocene reservoir in the northern deep Gulf of Mexico. Thin, water-bearing sands are shown in the lower portion of the interval and thicker, oil sands are shown in the upper part. The gamma-ray log on the left shows a cleaning-upward pattern. After Slatt et al. (1994). Reprinted with permission of Gulf Coast Section SEPM Foundation.

Figure 8-31.

Borehole image of a coarsening- and cleaning-upward, layered to amalgamated sheet sand interval from a Pliocene reservoir in the northern deep Gulf of Mexico. Thin, water-bearing sands are shown in the lower portion of the interval and thicker, oil sands are shown in the upper part. The gamma-ray log on the left shows a cleaning-upward pattern. After Slatt et al. (1994). Reprinted with permission of Gulf Coast Section SEPM Foundation.

Several authors (Slatt et al., 1994; Slatt et al., 2000; Witton-Barnes et al., 2000) have suggested the following criteria which can be considered as often (though not always) diagnostic of sheet sandstones in image log or core: (1) a high proportion of structureless or Bouma Ta beds, (2) a general lack of climbing ripple, Bouma Tc beds, (3) a predominance of non-erosive, flat bases of beds, (4) few or no shale rip-up clasts within the sand beds, (5) relatively few slump or debrite beds, and (6) somewhat ordered stacking patterns. Some of these features have been used to identify sheet sandstones in some subsurface reservoirs (Fugitt et al., 2000; Sullivan et al., 2000)

Examples of sheet sandstone reservoirs

The following discussion is a brief summary of the performance of eight fields or sedimentary basins with sheet reservoirs. These examples are taken from the better-documented fields in the literature. For each field, we describe the basic setting of the field, trap, rates of production; show examples of seismic profile and log data; and then discuss the important production history of the sheet. Note that most of these fields have multiple reservoirs—we describe only the sheet reservoir. A key point is that sheet reservoirs have widely varying performance due to several factors. In nearly every case, the initial models of the reservoir were fairly simplistic, but production revealed more complexity.

The first five examples are from the northern Gulf of Mexico, and reflect fields from discovery to peak production. The next two examples illustrate mature fields and the impact of better reservoir description and modeling in sustaining field life. Finally, we discuss the significant discoveries and development challenges from the Campos Basin, Brazil.

Auger Field, northern Gulf of Mexico, USA

Key references

Location

Auger Field is in Garden Banks blocks 426, 427, and 471 in the northern deep Gulf of Mexico, 345 km (214 miles) southwest of New Orleans, Louisiana, USA (Fig. 8-32)

Figure 8-32.

Map of the Auger minibasin, northern Gulf of Mexico, showing the original estimates of the Auger “S” sand aquifer distribution (blue area), and the current estimate after initial production and pressure matching (pink area). The current estimate is that the aquifer is approximately equal to the size of the Auger minibasin. After Kendrick (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-32.

Map of the Auger minibasin, northern Gulf of Mexico, showing the original estimates of the Auger “S” sand aquifer distribution (blue area), and the current estimate after initial production and pressure matching (pink area). The current estimate is that the aquifer is approximately equal to the size of the Auger minibasin. After Kendrick (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Significance

The field was discovered in 1987, and was brought on production in April 1994. The field is notable for its extremely high production rates from one reservoir (S sand), thus qualifying as a HRHU reservoir (Figs. 8-33, 8-34). Originally, 120 million barrels of oil equivalent were assigned to this interval. As of 2000, 110 MMBOE had been produced from seven wells. Initially, the aquifer distribution of the reservoir was estimated to be about 12 square miles (Fig. 8-32).

Figure 8-33.

Seismic profile across the Auger Field, Garden Banks 427, northern Gulf of Mexico. Reservoirs are associated with high amplitude (red) events that onlap and pinch out against the structure. Amplitude extraction is from the S-1 level and shows the oil-water contact. After Booth et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-33.

Seismic profile across the Auger Field, Garden Banks 427, northern Gulf of Mexico. Reservoirs are associated with high amplitude (red) events that onlap and pinch out against the structure. Amplitude extraction is from the S-1 level and shows the oil-water contact. After Booth et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-34.

Wireline log cross section showing the distribution of sheet sands in the Auger Field, northern Gulf of Mexico. Pink interval is amalgamated sheet sands. Blue interval is layered sheet sands. The continuous shale datum separates the two sand types. After McGee et al. (1994). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-34.

Wireline log cross section showing the distribution of sheet sands in the Auger Field, northern Gulf of Mexico. Pink interval is amalgamated sheet sands. Blue interval is layered sheet sands. The continuous shale datum separates the two sand types. After McGee et al. (1994). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

The much higher than expected production rates were due to strong aquifer support for the reservoir. When the pressure history was matched to the curves, the aquifer estimate was changed to reflect 53 times the original estimated aquifer volume (Fig. 8-35). This illustrates that the sheet sands have good continuity and completely fill the basin, 15 km (nine miles) at its greatest width.

Figure 8-35.

Graph showing the pressure history match for the Auger S sand for initial production. The green dashed line shows the predicted pressure decline associated with the original estimated aquifer volume. The solid green line is the expected pressure history of an aquifer that is 53 times greater than the reservoir volume. The black squares indicate the actual pressure data. After Kendrick (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-35.

Graph showing the pressure history match for the Auger S sand for initial production. The green dashed line shows the predicted pressure decline associated with the original estimated aquifer volume. The solid green line is the expected pressure history of an aquifer that is 53 times greater than the reservoir volume. The black squares indicate the actual pressure data. After Kendrick (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

One problem in the S sand that is common to sheet sandstone reservoirs is the presence of multiple fluid contacts. There are several laterally continuous shales which isolate sandstones, but are too thin to be resolved seismically (Figs. 8-33, 8-34). A pulsed neutron capture log through the S sand over a four year period reveals a number of different trends of oil replacement by water over time (Fig. 8-36) (Kendrick, 2000). These different trends indicate that some of the shales are sealing, thus preventing fluid communication across their boundary. Other shales within the S sand do not seem to be sealing, and a single trend of increasing water-cut over time occurs in sands separated by these shales. The reason why some shales are sealing in this reservoir and others are not has not been published. But, these shale-flow barriers apparently cause multiple fluid contacts.

Figure 8-36.

Pulsed neutron capture (PNC) log from the Auger S sands, A-9 well, Auger Field. Gamma ray log is shown on the left, and a Pulsed Neutron Capture log is shown in the middle. The Pulsed Neutron Capture (PNC) log records replacement of oil by water during development. Years in which the logging runs were made are shown on the right graph as horizontal axis (1994-97), with each year represented by a different color. Note that there are four separate trends in the PNC log over the three year interval. These trends begin and end at some of the shales, indicating they are sealing shales which isolate sands above and below. Some linear trends continue across shales, indicating these shales are not sealing. After Kendrick (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-36.

Pulsed neutron capture (PNC) log from the Auger S sands, A-9 well, Auger Field. Gamma ray log is shown on the left, and a Pulsed Neutron Capture log is shown in the middle. The Pulsed Neutron Capture (PNC) log records replacement of oil by water during development. Years in which the logging runs were made are shown on the right graph as horizontal axis (1994-97), with each year represented by a different color. Note that there are four separate trends in the PNC log over the three year interval. These trends begin and end at some of the shales, indicating they are sealing shales which isolate sands above and below. Some linear trends continue across shales, indicating these shales are not sealing. After Kendrick (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Trap

The field produces from a combination structural-stratigraphic trap with the updip pin-chout of sands against a large salt structure (Figs. 8-32, 8-33). Faults also bound the field to the north and east. The reservoirs dip southwestward into the basin.

Size

The field is triangular-shaped in plan view. It is 4 km (2.5 miles) long, and 3.2 km (2 miles) at its widest (Fig. 8-32). The oil column height is 1200 feet (400 m).

Age and depositional environment

The field consists of five upper Pliocene reservoir zones (S, R, Q, O, and N1: oldest to youngest). The lower three zones (S, R, Q) consist of layered and amalgamated sheet sandstone packages. The upper two zones consist of amalgamated channel-fill deposits. All reservoir sands were deposited in an intraslope basin.

Petroleum in place, production history, and well/field rates

The deeper sands contain volatile oil with 34 to 38 API gravity. Shallow sands contain retrograde gases. Total reserves for the field are 200 MMBOE. The deepest and most productive level in the field is the Auger S (Pink) Sandstone. Originally, 120 million barrels of oil equivalent were assigned to this interval (McGee et al., 1994). As of 2000, 110 MMBOE had been produced from seven wells, indicating either excellent recovery efficiency for oil or that the original estimates were way too low.

Seismic and wireline log response

The field was originally identified by prominent seismic amplitude anomalies (Fig. 8-33). S sand reservoirs consist of sheet sands with upward coarsening to blocky packages on gamma ray logs (Fig. 8-34).

Thickness, lateral continuity, and aspect ratio

The S sand has a gross thickness of 60 m (200 feet) with an average net:gross of 0.8. The reservoir extends across the width of the field 4 km (2.5 miles), and possibly longer. Minimum aspect ratio is 130:1, but probably considerably larger, given the aquifer support.

Vertical connectivity and net:gross

The net:gross for the entire field is 0.8. Major shale packages 100-160 m (300-500 feet) thick separate each of the five reservoirs. Shales separating the two S sands indicate that some are sealing, and others are not, based on the production history described above.

Sedimentary texture, composition and structures determined from core and borehole image logs

Two main lithofacies are present in the S sand in cores: (1) Thick massive, structureless sands are up to 9 m (30 feet) thick, with rare amalgamation surfaces identified by slight change in grain size; and (2) Thin beds consisting of parallel laminated (Tb) and rippled (Tc) and or convoluted sandstones. Some Ta beds are present.

Reservoir quality

The S Sand (main reservoir) has an average porosity of 25%, average permeability is 150 md.

Drive mechanism

The reservoir has major water drive.

Mars Field, northern Gulf of Mexico, USA

Key references

Location

Mississippi Canyon area (blocks 806, 807, 857) in the northern deep Gulf of Mexico, 130 miles southeast of New Orleans, Louisiana, USA (Fig. 8-37).

Figure 8-37.

Map showing the location of the Mars Field, and surrounding allochthonous salt, Mississippi Canyon, northern Gulf of Mexico. Nearby fields (Ursa, Crosby) are shown. After Reynolds (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-37.

Map showing the location of the Mars Field, and surrounding allochthonous salt, Mississippi Canyon, northern Gulf of Mexico. Nearby fields (Ursa, Crosby) are shown. After Reynolds (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Significance

The Mars field is the largest oil field in the northern deep Gulf of Mexico. The Mars Field is one of five fields in the same sediment fairway (along with King, Ursa, Princess, Crosby: Fig. 8-37). It was discovered in 1989, and brought on line in 1996. The field has 14 productive zones, with 7 reservoirs holding 70% of the reserves. Each of these seven reservoirs has an oil column height greater than 1500 feet (300 m). The Lower Yellow Sand, and amalgamated sheet sand, is the largest and best documented of the reservoirs.

Trap

The reservoir sands are trapped between two major allochthonous salt bodies. The sands dip primarily to the south (Figs. 8-37, 8-38).

Figure 8-38.

Seismic profiles across the Mars Field, northern Gulf of Mexico, illustrating the Mars Yellow reservoir. Note (a) Lower Yellow Sand, indicated by AE1 reflection, has good lateral extent, (b) the top of the AE1 is scoured into and filled with AE3 unit, and (c) is overlain by AE 8 channel. Time based-gamma logs (yellow) are displayed on the seismic. After Reynolds (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-38.

Seismic profiles across the Mars Field, northern Gulf of Mexico, illustrating the Mars Yellow reservoir. Note (a) Lower Yellow Sand, indicated by AE1 reflection, has good lateral extent, (b) the top of the AE1 is scoured into and filled with AE3 unit, and (c) is overlain by AE 8 channel. Time based-gamma logs (yellow) are displayed on the seismic. After Reynolds (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Size

Lower Yellow Sand is rectangular in shape, about 3.2 by 4.8 km (2.0 by 3.0 miles).

Age and depositional environment

The field consists of upper Miocene and lower Pliocene (9.2 to 4.2 Ma) reservoirs deposited as sheets (amalgamated and layered) and channel-fill (single and multi-story). The reservoir sands were deposited between two allochthonous salt bodies in an intraslope basin. Sheet sands were deposited in portions of the lower six reservoirs. The performance of the oldest of the reservoirs (Lower Yellow) is described here.

Petroleum in place, production history, and well/field rates

The reserves of the Mars Field are estimated to be 750 MMBOE. About 70% of the reserves occur in 7 zones. The largest producing zone, the Lower Yellow Sand, was producing 52 MBOPD and 62 MMCFGPD from six wells in early 2002. Production rates are constrained by tubing size, and thus, could be higher.

Seismic and wireline log response

The Lower Yellow amalgamated sheet reservoir consists of one laterally continuous reflection that extends across the field and farther downdip to the Ursa field (Figs. 8-37, 8-38). In some places, the reservoir has been eroded by channels. The reservoir sands have a blocky to slightly fining upward gamma response (Figs. 8-28, 8-38).

Thickness, lateral continuity and aspect ratio

The Lower Yellow Sands are 15 to 18 m (50 to 60 feet) thick (Figs. 8-28, 8-36). The sand extends about 4 km (2.5 miles) across the entire strike of the basin between two salt bodies (Fig. 8-37). Aspect ratio is not noted, but is limited by the size of the basin; we estimate about 250:1, based on the width of the basin and thickness of the sands (Fig. 8-39).

Figure 8-39.

Schematic cross section across the Yellow Reservoir, Mars Field, northern Gulf of Mexico. Architectural elements are based on core, wireline log, and seismic data. Elements 1 and 2 correspond to the Lower Yellow Interval, whereas elements 5-8 correspond to the Upper Yellow interval. After Reynolds (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-39.

Schematic cross section across the Yellow Reservoir, Mars Field, northern Gulf of Mexico. Architectural elements are based on core, wireline log, and seismic data. Elements 1 and 2 correspond to the Lower Yellow Interval, whereas elements 5-8 correspond to the Upper Yellow interval. After Reynolds (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Vertical connectivity and net:gross

The net:gross of Lower Yellow Sand is 0.8 to 0.85. A sand-filled channel between the Upper Yellow and Lower Yellow Sands created amalgamation and resulted in fluid communication between the two intervals. This vertical connectivity increases the performance of the reservoirs (Fig. 8-39).

Sedimentary texture, composition and structures determined from core and borehole image logs

Cores through the Lower Yellow sands show Bouma Ta or Ta-b beds consisting of fine to very fine sands (Figs. 8-28, 8-29). Cores through the Upper Yellow Sands show reservoir quality.

Reservoir quality

The Lower Yellow Sand has an average porosity of 27% ranging from 15-33%. Permeability ranges from 250 to 2000 md, averaging 500 md. The Upper Yellow layered sheet sand has an average porosity of 24% and permeability of 225 md.

Drive mechanism

The Mars reservoirs produce primarily because of pressure depletion and, secondarily, time-varying compaction.

Mensa Gas Field, northern Gulf of Mexico, USA

Key references

Location

Mensa field produces in Mississippi Canyon blocks 686, 687, 730, 731. The field is 225 km (140 miles) southeast of New Orleans, Louisiana, USA. The field produces in 1615 m (5300 feet) of water by subsea tieback via a 101 km (63-mile) long pipeline.

Significance

Mensa field was discovered in 1985 based on a prominent seismic anomaly (Fig. 8-40). Based on core data, wireline log response, and seismic data, the reservoir was interpreted to be a homogenous sand connected downdip to a major aquifer that provided the field’s drive mechanism (Fig. 8-41). Almost immediately after production began in 1997, pressure measurements did not support the original reservoir model. New reservoir simulations indicated that the reservoir was primarily a depletion-drive reservoir with little to no aquifer support. This realization had important consequences for the development scenario of maintaining at least 3200 psi pressure for subsea tieback.

Figure 8-40.

Seismic profile across the Mensa Field, Mississippi Canyon 731, northern deep Gulf of Mexico. Reservoir is noted by the prominent seismic amplitude. After Pfeiffer et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-40.

Seismic profile across the Mensa Field, Mississippi Canyon 731, northern deep Gulf of Mexico. Reservoir is noted by the prominent seismic amplitude. After Pfeiffer et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-41.

Wireline log cross section across the Mensa Field, Mississippi Canyon blocks 686, 687, 730, and 731, northern deep Gulf of Mexico. Two discrete sheets are present: I-A (upper) and I-B (lower). The two sheets amalgamate to the right of the profile. The lower sheet pinches out to the left. After Pfeiffer et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-41.

Wireline log cross section across the Mensa Field, Mississippi Canyon blocks 686, 687, 730, and 731, northern deep Gulf of Mexico. Two discrete sheets are present: I-A (upper) and I-B (lower). The two sheets amalgamate to the right of the profile. The lower sheet pinches out to the left. After Pfeiffer et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

The development team reevaluated the seismic data to ascertain if additional information regarding the architecture of the reservoir could be deciphered. With newer, higher-frequency seismic data, a more complex reservoir architecture was imaged. Instead of one laterally continuous reflection associated with one sheet sand as seen previously, three slightly offset stacked sheet sands were revealed (Figs. 8-42, 8-43). One sheet probably cut into the other, possibly separated by a partial permeability barrier between them. Additionally, an erosional channel that cuts the main pay sand to the west may limit the amount of pressure support that the aquifer can provide. Finally, an additional well was drilled that encountered a new, but smaller gas reservoir.

Figure 8-42.

Seismic profile across Mensa Field. The profile is from a higher frequency data set and shows the time-based gamma ray logs and the two amalgamated sheet sands, I-A and I-B. The inset map shows the location of the profile across the field. After Pfeiffer et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-42.

Seismic profile across Mensa Field. The profile is from a higher frequency data set and shows the time-based gamma ray logs and the two amalgamated sheet sands, I-A and I-B. The inset map shows the location of the profile across the field. After Pfeiffer et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-43.

Schematic cross section across the Mensa Field, northern deep Gulf of Mexico. This section was drawn after the integration of the higher frequency seismic data with well information. Additional data defined three discrete sheets, two of which are in pressure communication. After Pfeiffer et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-43.

Schematic cross section across the Mensa Field, northern deep Gulf of Mexico. This section was drawn after the integration of the higher frequency seismic data with well information. Additional data defined three discrete sheets, two of which are in pressure communication. After Pfeiffer et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

The overall lesson learned from the Mensa field development was the reservoir geometries are sub-seismic in scale. In the end, additional well work indicated that there was sufficient communication between reservoirs that the subsea tieback could be maintained.

Trap

The trap consists of a seismic amplitude anomaly draping a major turtle structure (anticline) in an intraslope mini-basin (Fig. 8-40). The main pay sand (I sand) is cut by a shale-filled, erosional channel to the west, and pinches out to the east.

Size

The field is roughly square shaped with maximum dimensions of 4.0 by 3.2 km (2.5 by 2.0 miles) at its widest.

Age and depositional environment

The main reservoir I sands are upper Miocene (9.0 Ma), and consist of layered and amalgamated sheet sands deposited within an intraslope setting. The shallower reservoir sands (H, K) were deposited as channel-fill (Figs. 8-41, 8-43).

Petroleum in place, production history, and well/field rates

The in-place reserves are estimated to be 1.3 trillion cubic feet of gas. I sand reservoirs have an estimated 750 Bcf. The remainder of the reserves are condensate.

Seismic and wireline log response

Mensa Field is associated with a prominent amplitude anomaly reflecting the distribution of fluids in the reservoir (Fig. 8-40). The gamma ray log response for the different I sand reservoirs is blocky (Fig. 8-41).

Thickness, lateral continuity and aspect ratio

The greatest thickness of I sand is 52 m (170 feet). Maxiumum lateral continuity is about 4.0 km (2.5 miles) (maximum) eroded to the west by a younger channel. No aspect ratio is published, but we estimate it to be at least 700:1, based on the width of the field as defined by the amplitude anomaly and the thickness of the reservoir sands.

Vertical connectivity and net:gross

After production began, remapping of the reservoir revealed that producing sheets were slightly offset (Fig. 8-43). Vertical connectivity is present between two main sands (I-A and B sands in Fig. 8-43). Net:gross is almost 90% in the I sand.

Sedimentary texture, composition and structures determined from core and borehole image logs

Cores show one facies consisting of (Ta), and (Tb beds) separated by amalgamation surfaces.

Reservoir quality

The porosity of the I sand varies from 29-33%, and permeability varies from 500 to 2000 md.

Drive mechanism

The reservoir has a limited water drive.

Garden Banks 191, northern deep Gulf of Mexico

Key references

Location

The field sits in 230 m of water in Garden Banks Block 191, northern Gulf of Mexico, about 410 mi (257 km) southwest of Lafayette, Louisiana, USA.

Significance

Gas production began in 1993 from layered and amalgamated sheet sandstones within an interval called the 4,500 ft. sand (Fig. 8-44). Four laterally continuous shale intervals divide the 4,500 ft. sand into vertically disconnected sands (Fig. 8-44). Originally, all four members had a common gas-water contact. With production, the gas-water contact has moved differentially upward within different intervals. The lateral continuity of the shales has resulted in sands behaving as separate flow units which water out at different times. Member 3 watered out in one production well in May 1996, and member 4 watered out in the same well in 1997. In contrast, members 1 and 2 behave as one flow unit, and are still at original formation pressure.

Figure 8-44.

The 4,500 ft. gas sand reservoir in the Garden Banks 191 field, northern Gulf of Mexico. (A) Seismic profile across the field illustrates the sediments dip to the left, and a horizontal gas-water contact is also visible. (B) Interpreted distribution of reservoir sands with three wells, the A5, A6, and A10. The reservoir intervals (labeled 1-4) are shown in the wireline log in (C). Note that the original gas-water contact was continuous across the reservoir (B); however, with time, the water front has moved upward in the reservoir to different levels. This pattern indicates that the shales (brown) that separate the sand packages are sealing shales and isolate the individual sand packages. After Fugitt et al. (2000). Reprinted by permission of Gulf Coast Section SEPM Foundation.

Figure 8-44.

The 4,500 ft. gas sand reservoir in the Garden Banks 191 field, northern Gulf of Mexico. (A) Seismic profile across the field illustrates the sediments dip to the left, and a horizontal gas-water contact is also visible. (B) Interpreted distribution of reservoir sands with three wells, the A5, A6, and A10. The reservoir intervals (labeled 1-4) are shown in the wireline log in (C). Note that the original gas-water contact was continuous across the reservoir (B); however, with time, the water front has moved upward in the reservoir to different levels. This pattern indicates that the shales (brown) that separate the sand packages are sealing shales and isolate the individual sand packages. After Fugitt et al. (2000). Reprinted by permission of Gulf Coast Section SEPM Foundation.

Trap

The trap consists of a south-dipping reservoir against the flank of a salt structure, and shales out to the south, west and east (Fig. 8-44).

Size

The 4,500 ft. sand is about 92 ft (30.5 m) thick, and was deposited over large portions of blocks 191 and 147 (Fig. 8-44).

Age and depositional environment

The sands are early Pleistocene in age. They were deposited in intraslope basins created by salt. The sands were fed by shelf-edge deltas 16-24 km to the north.

Hydrocarbons in place, production history, and well/field rates

Between 1994-2000, three wells produced 93BCF gas. The 4,500ft. sand exhibits high initial flow rates, and a relatively low decline rate, but production falls rapidly once water enters the completion. Different sand members deplete at different rates because of the shale seals.

Seismic and well log expression

The 4,500ft. sand is easily recognized on seismic as a high-amplitude, continuous, dipping seismic reflection (Fig. 8-44). A prominent flat spot highlights the original gas-water contact.

Thickness, lateral continuity and aspect ratio

Individual sand beds range from 6cm to 2.6m in thickness, with most beds being <0.6m thick. Good production from a strong water drive suggests that the sheet sands are laterally continuous through the gas and water legs.

Vertical connectivity and net:gross

Net sand is 75-90% in thicker-bedded (amalgamated), sandy intervals and <50% in thinner bedded (layered), shalier intervals.

Sedimentary texture, composition and structures determined from core and borehole image logs

Three lithofacies types have been identified in core and borehole image logs. (1) Thick-bedded (>0.7m) sands tend to have erosive bases and load casts, and are internally massive, inclined, or planar laminated. (2) Thin-bedded (<0.7m) sands exhibit ripple to wavy lamination (Tc), lesser horizontal lamination (Tb,) and abundant macerated organics along bedding planes. (3) Laminated shales occur as sections of graded mud couplets of silty clay to clay, with common starved ripples. This lithofacies occurs as continuous drapes over the top of each reservoir sand.

Reservoir quality

Porosities vary from 17 to 34% and permeabilities vary from 1 to 2520 md.

Drive mechanism

The reservoir has a strong water drive.

J Sand, Ram-Powell Field, northern Gulf of Mexico, USA

Key references

Location

Ram Powell Field is located in Viosca Knoll block 956 in the northern Gulf of Mexico (Fig. 8-45). The field is approximately 100 km east-southeast of New Orleans, Louisiana.

Figure 8-45.

Map of Ram-Powell field showing the areal distribution of the reservoir sands J, L, M, and N. Sand package J is a sheet sand interval. A type well log through the four reservoirs is shown in Figure 8-16. After Craig et al. (2003). Reprinted with permission of AAPG.

Figure 8-45.

Map of Ram-Powell field showing the areal distribution of the reservoir sands J, L, M, and N. Sand package J is a sheet sand interval. A type well log through the four reservoirs is shown in Figure 8-16. After Craig et al. (2003). Reprinted with permission of AAPG.

Significance

Production in Ram-Powell field is from a series of individual reservoir sands that include all the major deepwater architectural elements: amalgamated sheet/channel levee (J) sand, channel-levee (L and M) sands, and amalgamated channel (N) sands (Figs. 8-16, 8-45, 8-46). The J sand is a sheet sand complex overlain by a channel-levee deposit. The original J sand development plan in 1993 consisted of eight vertical wells—six producers from an oil rim and two gas-cap blowdown wells. The well spacing was planned at 1.4 km2 (340 acres) with expected production of 6000 BOPD. However, advances in horizontal drilling and completion technology offered the opportunity to produce the oil rim more efficiently. Specifically, reservoir modeling suggested that three horizontal wells, spaced at 3.2 km2 (800 acres) could drain the oil rim at a rate of 30,000 BOPD, thus resulting in a substantial development cost savings (Fig. 8-47). Drilling revealed some unpredicted features of the reservoir, which resulted in modification of the drilling plan. However, the program was a success.

Figure 8-46.

Seismic profile across the Ram Powell field illustrating the J, L, M, and N sands (Figs. 8-16, 8-45). After Clemenceau et al. (2000). Reprinted by permission of Gulf Coast Section SEPM Foundation.

Figure 8-46.

Seismic profile across the Ram Powell field illustrating the J, L, M, and N sands (Figs. 8-16, 8-45). After Clemenceau et al. (2000). Reprinted by permission of Gulf Coast Section SEPM Foundation.

Figure 8-47.

Cross section showing the horizontal well path in the Viosca Knoll 956 A-3 well through the J sand, Ram Powell Field. The J sand consists of a lower amalgamated sheet facies overlain by a thin-bedded levee facies. After Craig et al. (2003). Reprinted with permission of AAPG.

Figure 8-47.

Cross section showing the horizontal well path in the Viosca Knoll 956 A-3 well through the J sand, Ram Powell Field. The J sand consists of a lower amalgamated sheet facies overlain by a thin-bedded levee facies. After Craig et al. (2003). Reprinted with permission of AAPG.

Trap

Unlike most of the northern Gulf of Mexico fields, allochthonous salt was not influential in creating depositional mini-basins in this area. Rather, slope and toe-of-slope environments prevailed during deposition. Ram-Powell is one of the few fields in the northern Gulf of Mexico that is considered to be a pure stratigraphic trap (Figs. 8-45, 8-46). The reservoirs dip south-southeast at 2-4o.

Size

In map view, the sand forms a northwest-trending, southward-widening, funnel-shaped body up to 5 km wide and 8 km long (Fig. 8-45). The J sand oil rim is 33 m thick and covers 9.7 km2 (2400 acres). The overlying gas cap covers 29.1 km2 (7200 acres).

Age and depositional environment

Reservoir sands at Ram Powell were deposited during the middle Miocene (12 Ma) in slope and toe-of-slope environments during a major lowstand of sea level. The coeval shelf edge was approximately 35km from the depositional site. The oldest sand, the N sand (Figs. 8-16, 8-45, 8-46), was deposited in a pre-existing submarine slope canyon. The axis of deposition of overlying sands shifted laterally in a compensatory fashion, so that the entire sand complex is fan-shaped. For example, the J sand was deposited with a fanlike geometry in a basinal low created by subsidence of the underlying L sand. The J sand pinches out updip to the northeast.

Hydrocarbons in place, production history, and well/field rates

In-place volumes have been estimated at 80 MMBO and 600 BCFG. The oil rim is estimated to contain 50 MMBO. At year-end 2001, cumulative production was 29 MMBO and 205.9 BCFG from the three horizontal wells. One well—the Viosca Knoll 956A-3ST1 (Fig. 8-47)—held the Gulf of Mexico production record of 40,900 BOEPD for some time.

Seismic and well log expression

The J sand is associated with a high-amplitude, laterally-continuous seismic reflection (Fig. 8-46). Isochron maps reveal radially-divergent, finger-like areas suggestive of distributary channels. Sinuous zones of low amplitude on horizontal time slices are interpreted as younger channels that eroded the J sand and were later infilled with shale. Some shingling on seismic records is apparent in the updip direction, changing downdip to continuous, parallel reflections.

Well logs within the high amplitude, thicker, central portion of the fan exhibit a sharp-based, blocky to slightly fining-upward sand (Fig. 8-16). Well logs within the moderate amplitude portion consist of fining-upward log patterns.

Thickness, lateral continuity and aspect ratio

The J sheet sands range in thickness from 15 to 18 m, whereas the overlying channel-levee deposits are 3-21m thick (Fig. 8-16). Data on lateral continuity of beds and aspect ratios have not been published.

Vertical connectivity and net:gross

In the axial portion of the sand, vertical connectivity and net sand are high. Both features decrease toward the margins.

Sedimentary texture, composition and structures determined from core and borehole image logs

Axial sands are massive, tabular-bedded, fine-grained, and moderately sorted. Sands near the margins contain classical turbidite (Ta-e) sedimentary structures. Borehole image logs have not been published.

Reservoir quality

Porosity averages 30%. Permeability of the sheet sandstone ranges from 640 to 2680 md in core. Channel-levee permeabilities are much less.

Drive mechanism

Production has shown that aquifer support in the field is negligible.

Long Beach Unit, Wilmington Field, southern California, USA

Key references

Location

Wilmington Field is the largest of several giant oil fields in the Los Angeles Basin of southern California. The Long Beach Unit comprises the southeastern part of the field, in part lying offshore and in part underlying the city of Long Beach.

Significance

The Wilmington Field is a very mature field, having been discovered in 1936. Development began in the Long Beach Unit in 1965. It went on waterflood soon after, mainly to maintain reservoir pressure in order to reduce subsidence beneath the city of Long Beach. With later geologic study of one zone in the Long Beach Unit—the Ranger Zone—it was determined that more selective perforation and waterflooding might prove effective in increasing production from untapped sands isolated by laterally continuous shales. Additional drilling did later prove successful. In other zones—called the Tar Zone and Terminal Zone—steam flood projects were designed and successfully implemented using horizontal wells. As described below, in all these projects, knowledge of the stratigraphy and reservoir characteristics was instrumental in successful addition of hundreds of millions of barrels of new reserves.

Trap

The field is a faulted, asymmetric anticline, formed during the early Pliocene, which is truncated by a mid-Pliocene erosional unconformity. The field is part of a larger, Neogene wrench- tectonic setting.

Size

The field is approximately 29 mi (18 km) long and 8 mi (4.9 km) wide and encompasses 13,500 acres. It consists of 7 main reservoir zones, divided into 52 subunits. The reservoir zones are, from the base upward—237, Ford, Union Pacific, Lower Terminal, Upper Terminal, Ranger, and Tar Zone.

Age and depositional environment

Upper Miocene and Pliocene sediments were deposited in upper middle (500-1000 m) to lower middle (1500-2000 m) bathyal water depths, about 30-50 km from the coeval shelf edge.

Hydrocarbons in place, production history, and well/field rates

More than 2.6 BB of the original estimated 9 BBOIP have been produced from more than 5000 wells in Wilmington Field. Total original oil in place for the Long Beach Unit is 3.8 BB. More than 1500 wells have been drilled within this unit through a number of zones and subzones. In the late 1960s, unit-wide oil production peaked at >100,000 BOPD. Initial oil production from some of the newer horizontal wells in Long Beach Unit has exceeded 600 bbl/day, with about 300bbl/day with 80% water cut from average wells. Total unit production in 2003 was 38,000 bbl/day. Of the seven main reservoir zones, the most productive is the Ranger Zone.

Seismic and well log expression

Prior to 1995, there were very few available old, 2D seismic lines. In 1995, a 3D seismic survey was shot, but results were inconclusive (Otott et al., 1996). Well logs through the Ranger Zone typically show a blocky pattern for thick, basin-floor, amalgamated sheet sands, and a more serrated pattern for more distal-layered sheet sands (Figs. 8-28-15; Fig. 8-48).

Figure 8-48.

Regional stratigraphic cross section of the Ranger Zone, Long Beach Unit, Wilmington Oil Field, California. Various reservoir sub-zones are shown by the letters. Locations of major faults are also shown, but their vertical offset is not shown on this stratigraphic cross section. The datum is a laterally continuous shale within the Ranger Zone directly above the Fo sub-zone. Note that the yellow and blue sheet sand packages are offset, suggesting they were deposited in a compensation-style manner with the blue package thinning over the top of the thickest part of the underlying yellow sand package. After Slatt et al. (1993). Reprinted by permission of Springer-Verlag.

Figure 8-48.

Regional stratigraphic cross section of the Ranger Zone, Long Beach Unit, Wilmington Oil Field, California. Various reservoir sub-zones are shown by the letters. Locations of major faults are also shown, but their vertical offset is not shown on this stratigraphic cross section. The datum is a laterally continuous shale within the Ranger Zone directly above the Fo sub-zone. Note that the yellow and blue sheet sand packages are offset, suggesting they were deposited in a compensation-style manner with the blue package thinning over the top of the thickest part of the underlying yellow sand package. After Slatt et al. (1993). Reprinted by permission of Springer-Verlag.

Thickness, lateral continuity, and aspect ratio

Packages of sheet sands within the Ranger Zone are laterally continuous on the order of kms. Because near-vertical faults bisect the structure, many of the sands and shales extend the entire length of individual fault blocks, thus isolating reservoir sands into horizontal and vertical compartments (Fig. 8-49). Individual and amalgamated sheet sands average 0.7 m thick. Compensation bedding is exhibited at both a large scale of sand packages (Fig. 8-49), and at the smaller, bed scale. Because the field is so large, its contained sand packages may be longer and wider than the confines of the field, so that regional aspect ratios have not been determined to our knowledge.

Figure 8-49.

Cross section showing the horizontal well course of UP 955 through the D1 sand, Long Beach Unit, Wilmington Field, California. After Clarke and Phillips (2003). Reprinted with permission of AAPG.

Figure 8-49.

Cross section showing the horizontal well course of UP 955 through the D1 sand, Long Beach Unit, Wilmington Field, California. After Clarke and Phillips (2003). Reprinted with permission of AAPG.

Knowledge of the lateral continuity of both sands and shales was particularly valuable in planning horizontal wells for steam-flood in the Tar Zone. In one structural block, the bottom of a single sand, the D1 sand, was targeted (Fig. 8-49). Horizontal drilling rates were fast (up to 183 m/hr) in the sands, but much slower in the shales. By using a model of good sand and shale bed continuity across the block, the drill team was able to successfully geosteer wells to avoid the shales, thus improving drilling efficiency. Four such wells were successfully drilled within a 4.5 m target window. In a similar project in the Terminal Zone, a geologic model of good continuity was used to geosteer a U-turn around a fault in order to steam flood into two sands, the 2.4 m thick Hx0j and the 1.8 m thick Hx0, which are separated by the continuous Hx0sh shale (Fig. 8-50).

Figure 8-50.

Block diagram showing the horizontal well trace in the Hx0 sandstones of the Long Beach Unit, Wilmington Field, California. Note the curved well path. After Clarke and Phillips (2003). Reprinted with permission of AAPG.

Figure 8-50.

Block diagram showing the horizontal well trace in the Hx0 sandstones of the Long Beach Unit, Wilmington Field, California. Note the curved well path. After Clarke and Phillips (2003). Reprinted with permission of AAPG.

Vertical connectivity and net:gross

Vertical connectivity and net:gross vary according to whether a stratigraphic interval is composed of thick, amalgamated sheet sands, or thinner, layered sheet sands. For the interval illustrated in Figs. 13-2 to 13-15, net sand is 98% for the upper, thick-bedded, amalgamated sheet sand interval and 45% for the lower, thin-bedded, layered sheet sand interval. In the well shown in Figs. 13-2 to 13-15, the amalgamated sands are interpreted to have been deposited in a more proximal setting than the layered sheet sands, with the boundary between the two representing a depositional sequence boundary and seaward shift in the depositional axis.

Sedimentary texture, composition and structures determined from core and borehole image logs

Greater than 1000 m of cores have been described and published. Sands are unconsoli-dated, often ungraded, and sometimes oil-coated, making it difficult to interpret individual beds, contained sedimentary structures, and amalgamation surfaces. Where visible, most sands are massively bedded, though many exhibit normal-size grading (Bouma Ta). Sands range from very fine-grained to coarse-grained. Pebbly sands and sandy gravels are also present in some of the thicker Ranger Zone sands. There is a positive correlation between bed thickness and grain size of the sands (Chapter 13). Shales are extremely dense and lithified.

Borehole image logs have not been published to our knowledge, though they have been obtained from several wells in the field. It is anticipated that borehole image logs exhibit the same type of sedimentary features as observed in other sheet sand reservoirs.

Reservoir quality

In the Ranger Zone unconsolidated sands, porosities average about 28%. Permeability varies from an average of 288 md for beds <2 ft (0.7 m) thick to 457 md for beds >2 ft (0.7 m) thick (Table 13-2, Long Beach Unit, (Chapter 13). Several individual beds have permeabilities in excess of a darcy.

Drive mechanism

The entire field is on secondary waterflood recovery.

Miller Field, Viking Graben, North Sea, UK

Key references

Location

The Miller Field is located in the southern portion of the Viking Graben in the UK sector Blocks 16/7b and 18/8b of the North Sea. The field is 270 km (170 miles) northeast of Aberdeen, Scotland.

Significance

Miller field was discovered in 1983, following several mid-1970s discoveries in the gravel-rich Brae complex to the west. The field was brought on line in 1992, and began to decline in production in 1997. Oil is 37.5 API, depleted in CO2, and sour.

The reservoir initially was subdivided into four zones (A-D; Fig. 8-51). As part of a gas-injection project for secondary recovery, a full field reservoir characterization revealed several subtle, yet important heterogeneities that significantly impacted reservoir performance. Eight distinct architectural elements were recognized in the field, based on net:gross, lithofacies, and bed thickness (Figs. 8-51, 8-52). These elements reflect the different facies within the sheets, and intervening shale intervals. A reservoir model was then built using these units, focusing on three levels of heterogeneities: (a) shales between reservoir zones, (2) heterogeneities within the reservoir zones, and (3) impermeable lithotypes.

Figure 8-51.

Wireline log cross section across the Miller field. Four high net:gross reservoir intervals (A-D) are present. After Garland et al. (1993). Reprinted with permission of The Geological Society.

Figure 8-51.

Wireline log cross section across the Miller field. Four high net:gross reservoir intervals (A-D) are present. After Garland et al. (1993). Reprinted with permission of The Geological Society.

Figure 8-52.

Schematic cross section showing the eight reservoir elements identified and modeled in the Miller Field. After Garland et al. (1999). Reprinted with permission of The Geological Society.

Figure 8-52.

Schematic cross section showing the eight reservoir elements identified and modeled in the Miller Field. After Garland et al. (1999). Reprinted with permission of The Geological Society.

Reservoir modeling results indicated that water can override shales, suggesting that waterflood may have bypassed small oil accumulations. In addition, a realistic scheme for analyzing the effectiveness of gas injection was the presence of gas underunning shales. The multiple realizations from the model indicated there was still considerable uncertainty with the model results. Details maintained in the reservoir model are essential to maximizing the potential for infill drilling to extend the life of the field.

Trap

The field consists of reservoirs draping over a structural nose. There is a structural trap to the southwest, east, and north, and a stratigraphic trap to the northwest and west (Fig. 8-53).

Figure 8-53.

Seismic profile across the Miller and South Brae fields, southern Viking Graben, North Sea. Note the subtle closure of the Miller Field. After McClure and Brown (1992). Reprinted with permission of AAPG.

Figure 8-53.

Seismic profile across the Miller and South Brae fields, southern Viking Graben, North Sea. Note the subtle closure of the Miller Field. After McClure and Brown (1992). Reprinted with permission of AAPG.

Size

The Miller Field is 17.4 mi2 (45 km2) in area. The field is 14 mi (8.5 km) in maximum length, and varies in width from 3 to 6 km. The height of the original oil column was 310 ft (103.6 m).

Age and depositional environment

The reservoirs are Late Jurassic (Kimmeridgian) in age, deposited in a sand-rich deep-water system. The sheet sands were deposited at the terminus of a channelized lobe. Farther west, slightly older conglomeratic sandstones were deposited in debris aprons adjacent to an active faulted highland area (Brae trend).

Hydrocarbons in place, production history, and well/field rates

The original oil in place for Miller field was 640 MMBO; ultimate recoveries are about 300 MMSTB of oil and 0.57 Tcf. Peak production rates were 130,000 BOPD. The 16/8b-AO2 well produced at an average rate of 20,700 BOPD.

Seismic and well log expression

The field corresponds to one to two laterally continuous seismic reflections, with subtle mounding and pinchout to the west (Fig. 8-51). The producing reservoirs have a blocky shape on gamma-ray logs, with thin interbedded shales. Each reservoir sandstone unit is 100 feet (30 m) thick (Fig. 8-52).

Thickness, lateral continuity, and aspect ratio

The maximum thickness of the reservoir is 360 ft (120 m). The minimum lateral continuity of sandstones is 4 km (Fig. 8-51). No aspect ratios have been published.

Vertical connectivity and net:gross

The vertical connectivity is good within each of the four main reservoir zones (Fig. 8-51). Shales tend to act as permeability barriers between each of the four main zones. The net:gross of the reservoir is typically > 0.75.

Sedimentary texture, composition and structures determined from core and borehole image logs

The reservoir sandstones are dominantly fine- to medium-grained, structureless, and occur in 1 m thick beds with varying amounts of amalgamation. No borehole image logs have been published.

Reservoir quality

Porosity values range from 12 to 23%, and permeability values range from 50 to 1200 md.

Drive mechanism

There is little primary water support. Therefore, the entire field was developed initially with water injection to maintain reservoir pressure. The field is now in secondary recovery with gas injection and water flooding.

Campos Basin, Brazil

Sheet sandstones are important reservoirs in the Campos Basin of Brazil. Unconfined sand-rich turbidite lobes account for 43% of 27.5 TCFGIIP and 42% of 52.7 BBOIIP in Brazilian deepwater reservoirs (Bruhn, 1998). Cretaceous reservoirs are mostly trough-confined, gravel/sand-rich lobes (e.g. Roncador, Namorado, and Jubarto), or sand/mud-rich lobes (the Albian reservoir of Albacora). Cenozoic reservoirs tend to be less confined and generally have wide areal extent (Fig. 8-10), except where they have been incised by younger channels. These fields include Albacora, Marlim, Albacora Leste, Marlim Sul, Barracuda, and Caratinga. Reservoir porosities range from 25-35 %, and permeabilities between 0.2 to 2 darcies.

The deepwater reservoirs of the Campos Basin present many development challenges. The reservoirs are fairly shallow in their occurrence, 1-2 km below the sea floor, with cool temperatures (35-70°C). This affects a number of factors including low compaction, low viscosity for oils, relatively small percentages of dissolved gas, low reservoir pressures, and the significant potential for biodegradation (occurs up to 65°C). Oil quality is also a concern with these reservoirs because of the waxy oils that have caused production and pipeline problems. Oil gravities are 14-27 °API, a function of both biodegradation and waxy oils. In spite of these challenges, production has progressed in this basin.

Most deepwater wells have typical rates of 10,000-15,000 BOPD, and one well in Mar-lim Sul produces at 34,200 BOPD. Despite the low gravity oil found in most deepwater fields, extensive water injection has been used for increasing production.

Most of the deepwater reservoirs have solution gas drive, with the notable exception is the upper Oligocene/lower Miocene Albacora Field. Water maintenance has been used to maintain pressure and increase oil production for several deepwater fields (Marlim, Marlim Sul and Espadarte fields). By 2005, 19 deepwater fields will have water injection for water maintenance.

In spite of the apparent good rock properties, recovery efficiencies vary from 19-45%. The Marlim Field, despite being undersaturated, has an expected ultimate recovery between 40 and 45%, due to an efficient water injection. Other fields have considerably lower recovery rates due to the factors described above.

Summary: Lessons learned

  1. 1.

    Sheet sands are deposited at the terminus of deepwater channels. Sheet sands are classified into layered and amalgamated sheets. Layered sheet sands are interbedded sand and mud packages. Amalgamated sheet sands are dominantly sand beds with fewer interbed-ded muds.

  2. 2.

    In plan view, sheets can have several morphologies, including lobate, distributary, and “dendritic.” Environments transition from the updip channels to sheets.

  3. 3.

    Sheets are areally widespread in both confined and unconfined basins. Their areal extent is often controlled by the shape of the receiving basin.

  4. 4.

    On seismic reflection data, sheets appear as one to several parallel reflections with good continuity. They commonly lap out against the edges of the basin, or thin beneath resolution of the seismic data.

  5. 5.

    Layered sheet sands are typically 5-15m in thickness. Amalgamated sheet sand and san-stone packages may be thicker. Wireline log patterns show blocky (amalgamated) to upward thinning/fining (layered) or serrated patterns. Rates of change of thickness of individual beds and packages of sheet sandstone beds are 0.2-0.4% (m/100 m).

  6. 6.

    Because sands forming the sheets have been transported relatively long distances, sheets often are sufficiently sorted to provide good porosity and permeability relative to other sands within the same depositional system. Sheet sand reservoirs may be found 10’s of km basinward of their coeval shelf.

  7. 7.

    Characteristic sedimentary features in cores are massive/graded (Bouma Ta) beds with non-erosive bases and conformable, non-erosive bed contacts.

  8. 8.

    Shales at various scales are important because they too are laterally extensive, and offer the potential for isolating individual sheet sands and sandstones, and packages of sheet sands and sandstones. In some reservoirs, this results in multiple fluid contacts and depletion rates. Development scenarios should make use of the sealing capacity of shales for selective waterflooding and horizontal drilling.

  9. 9.

    Sheet sands and sandstones can be incised by channels that are filled with different types of sands and muds (shales).

  10. 10.

    Although sheet sands and sandstones are considered to be some of the best deepwater reservoirs, each field has its own set of characteristics that make it a challenge to produce. Several case studies of fields with sheet reservoirs indicate that the initial reservoir models were overly simplistic, and the actual complexity of the reservoir was only discovered with field production.

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Figures & Tables

Figure 8-1.

Three-dimensional perspective of an isochron of one depositional lobe with sheet sands draped over seafloor bathymetry. Deposit is in one intraslope minibasin created from shale deformation on the Nigerian continental slope, Block 221. The maximum isochron values are shown in red (100 msec). Inset shows the same area with an amplitude extraction draped over bathymetry. Three distinct areas with sheets are outlined. The vertical “stripes” represent an acquisition “footprint” of the 3-D data. After Pirmez et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-1.

Three-dimensional perspective of an isochron of one depositional lobe with sheet sands draped over seafloor bathymetry. Deposit is in one intraslope minibasin created from shale deformation on the Nigerian continental slope, Block 221. The maximum isochron values are shown in red (100 msec). Inset shows the same area with an amplitude extraction draped over bathymetry. Three distinct areas with sheets are outlined. The vertical “stripes” represent an acquisition “footprint” of the 3-D data. After Pirmez et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-2.

Seismic horizon slice taken 20 ms below sea floor in one intraslope basin, late Quaternary, northern deep Gulf of Mexico. Two distinct upfan channel belts (A, B) to the right (north) change downfan to channel mouth lobes. Also present are basin margins, mud volcano, and “slumps.” Location of Figure 8-8 is shown. After Beaubouef et al., 2003. Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-2.

Seismic horizon slice taken 20 ms below sea floor in one intraslope basin, late Quaternary, northern deep Gulf of Mexico. Two distinct upfan channel belts (A, B) to the right (north) change downfan to channel mouth lobes. Also present are basin margins, mud volcano, and “slumps.” Location of Figure 8-8 is shown. After Beaubouef et al., 2003. Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-3.

(a) Map of the youngest depositional lobe in the Mississippi fan, northern deep Gulf of Mexico. Box illustrates the area shown in detail in Figure 8-3 (b).

Figure 8-3.

(a) Map of the youngest depositional lobe in the Mississippi fan, northern deep Gulf of Mexico. Box illustrates the area shown in detail in Figure 8-3 (b).

Figure 8-3.

(b) SeaMARC I sidescan sonar image of distal Mississippi Fan lobe. Small channels (high back-scatter-white) are surrounded by areas of low backscatter (dark) suggesting the channel deposits formed as a series of interfingering channelized flows of sand and silt. White dots indicate where cores were collected. After Twichell et al., 1995. Reprinted with permission of Chapman-Hall and Kevin Pickering.

Figure 8-3.

(b) SeaMARC I sidescan sonar image of distal Mississippi Fan lobe. Small channels (high back-scatter-white) are surrounded by areas of low backscatter (dark) suggesting the channel deposits formed as a series of interfingering channelized flows of sand and silt. White dots indicate where cores were collected. After Twichell et al., 1995. Reprinted with permission of Chapman-Hall and Kevin Pickering.

Figure 8-4.

Stereometric display of the amplitude extraction of the yellow event about 150 ms below the sea floor (Fig. 8-5) from a portion of the late Quaternary, upper Brunei continental slope. Upslope channel changes downdip to a channelized lobe and then to a sheet deposit. Location of seismic profile in Fig. 8-5 is shown. After Demyttenaere et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-4.

Stereometric display of the amplitude extraction of the yellow event about 150 ms below the sea floor (Fig. 8-5) from a portion of the late Quaternary, upper Brunei continental slope. Upslope channel changes downdip to a channelized lobe and then to a sheet deposit. Location of seismic profile in Fig. 8-5 is shown. After Demyttenaere et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-5.

Seismic profile from the continental slope of Brunei showing near-surface channelized lobe. Yellow horizon indicates surface from which Figure 8-4 was extracted. See Figure 8-4 for location of profile. After Demyttenaere et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-5.

Seismic profile from the continental slope of Brunei showing near-surface channelized lobe. Yellow horizon indicates surface from which Figure 8-4 was extracted. See Figure 8-4 for location of profile. After Demyttenaere et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-6.

RMS amplitude extraction 170 msec below the seafloor in one intraslope minibasin in the Brunei continental slope. Upslope channel passes through shale ridges to elongated, sheet deposit. Margin consists of intraslope basins associated with shale features and strike-slip tectonics. After Demyttenaere et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-6.

RMS amplitude extraction 170 msec below the seafloor in one intraslope minibasin in the Brunei continental slope. Upslope channel passes through shale ridges to elongated, sheet deposit. Margin consists of intraslope basins associated with shale features and strike-slip tectonics. After Demyttenaere et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-7.

(a) Seismic profile from latest Pleistocene submarine fan, Makassar Strait, eastern Borneo. The vertical succession consists of a series of laterally continuous, high-amplitude reflections at the base (sheets), overlain by packages of laterally migrating channels that evolve upward into a single aggradational channel with lateral migration. Arrow marks the level of the horizon slice. (b) Amplitude extraction map taken 48 msec below the sea floor showing the distributary channel patterns changing downfan to sheet deposits. After Posamentier et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-7.

(a) Seismic profile from latest Pleistocene submarine fan, Makassar Strait, eastern Borneo. The vertical succession consists of a series of laterally continuous, high-amplitude reflections at the base (sheets), overlain by packages of laterally migrating channels that evolve upward into a single aggradational channel with lateral migration. Arrow marks the level of the horizon slice. (b) Amplitude extraction map taken 48 msec below the sea floor showing the distributary channel patterns changing downfan to sheet deposits. After Posamentier et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-8.

Three high-resolution seismic profiles from one shallow intraslope minibasin, northern deep Gulf of Mexico. Proximal (A) and medial (B) profiles cross the upfan channelized systems. (C) Distal profile crosses the sheet deposits. Note that the lobes A and B have slightly mounded appearance amongst the laterally continuous sheet-like reflections that lapout against the side of the basin. The deposits are up to 50 msec in twtt. See Figure 8-2 for location of profiles. After Beaubouef et al. (2003). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-8.

Three high-resolution seismic profiles from one shallow intraslope minibasin, northern deep Gulf of Mexico. Proximal (A) and medial (B) profiles cross the upfan channelized systems. (C) Distal profile crosses the sheet deposits. Note that the lobes A and B have slightly mounded appearance amongst the laterally continuous sheet-like reflections that lapout against the side of the basin. The deposits are up to 50 msec in twtt. See Figure 8-2 for location of profiles. After Beaubouef et al. (2003). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-9.

Seismic profile across the Marlim and Marlim Sul fields, Campos Basin, offshore Brazil. Prominent seismic amplitude can be traced across the profile from both fields. See Figure 8-10 for amplitude extraction of the horizon. After Bruhn (2001). Reprinted with permission of AAPG and Carlos Bruhn.

Figure 8-9.

Seismic profile across the Marlim and Marlim Sul fields, Campos Basin, offshore Brazil. Prominent seismic amplitude can be traced across the profile from both fields. See Figure 8-10 for amplitude extraction of the horizon. After Bruhn (2001). Reprinted with permission of AAPG and Carlos Bruhn.

Figure 8-10.

Amplitude extraction of the top Marlim and Marlim Sul Field, Campos Basin, offshore Brazil. Note the three updip channels (arrows) that feed the lobe-shaped sheet sands. After Bruhn (2001). Reprinted with permission of AAPG and Carlos Bruhn.

Figure 8-10.

Amplitude extraction of the top Marlim and Marlim Sul Field, Campos Basin, offshore Brazil. Note the three updip channels (arrows) that feed the lobe-shaped sheet sands. After Bruhn (2001). Reprinted with permission of AAPG and Carlos Bruhn.

Figure 8-11.

Wireline log from the Marlim field, Campos Basin, Brazil. Four distinct amalgamated sheets are present (labeled L1-L4), each 20-40 m (66-132 feet) thick. After Bruhn (2001). Reprinted with permission of AAPG and Carlos Bruhn.

Figure 8-11.

Wireline log from the Marlim field, Campos Basin, Brazil. Four distinct amalgamated sheets are present (labeled L1-L4), each 20-40 m (66-132 feet) thick. After Bruhn (2001). Reprinted with permission of AAPG and Carlos Bruhn.

Figure 8-12

(A) Flattened seismic profile across the Greater Auger minibasin showing the relationships between the Auger and Macaroni fields. Multiple sheet sands are interpreted to be present that extend across most of the basin. (B) Interpreted stratigraphic fill packages between two wells. Two kinds of facies are present. Yellow intervals are interpreted as onlapping fill facies (i.e. sand –rich sheets), and the orange are channel-fill facies (“bypass facies”). Gamma ray logs from each field illustrate layered sheet (LS), amalgamated sheet (AS) sands, and amalgamated channel (AC) sands. After Booth et al., 2000. Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-12

(A) Flattened seismic profile across the Greater Auger minibasin showing the relationships between the Auger and Macaroni fields. Multiple sheet sands are interpreted to be present that extend across most of the basin. (B) Interpreted stratigraphic fill packages between two wells. Two kinds of facies are present. Yellow intervals are interpreted as onlapping fill facies (i.e. sand –rich sheets), and the orange are channel-fill facies (“bypass facies”). Gamma ray logs from each field illustrate layered sheet (LS), amalgamated sheet (AS) sands, and amalgamated channel (AC) sands. After Booth et al., 2000. Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-13.

Flattened seismic profiles across one intraslope minibasin in the northern deep Gulf of Mexico. A sheet deposit (Cbh facies) onlaps the condensed section (D facies) and dipping depositional surface. Red dipping lines mark the edge of channels (Bh facies) that eroded the sheet. See Figure 8-14 for amplitude extraction of the sheet, and location of the profiles. After Prather et al. (1998). Reprinted with permission of AAPG.

Figure 8-13.

Flattened seismic profiles across one intraslope minibasin in the northern deep Gulf of Mexico. A sheet deposit (Cbh facies) onlaps the condensed section (D facies) and dipping depositional surface. Red dipping lines mark the edge of channels (Bh facies) that eroded the sheet. See Figure 8-14 for amplitude extraction of the sheet, and location of the profiles. After Prather et al. (1998). Reprinted with permission of AAPG.

Figure 8-14.

Amplitude extraction of the sheet sand shown in Figure 8-13. Distinct edge to the sheet can be seen onlapping the slope. Note the fairly uniform amplitude within the sheet. Location of seismic profiles in Figure 8-13 are shown. After Prather et al. (1998). Reprinted with permission of AAPG.

Figure 8-14.

Amplitude extraction of the sheet sand shown in Figure 8-13. Distinct edge to the sheet can be seen onlapping the slope. Note the fairly uniform amplitude within the sheet. Location of seismic profiles in Figure 8-13 are shown. After Prather et al. (1998). Reprinted with permission of AAPG.

Figure 8-15.

Seismic volume rendered display from offshore Nigeria showing four discrete zones with different facies. Note that the lower zone shows sequences dominated by sheet sands (basin–floor fans). Only the highest amplitude voxels are visible. After Radovich (2002). Reprinted with permission Gulf Coast Section SEPM Foundation.

Figure 8-15.

Seismic volume rendered display from offshore Nigeria showing four discrete zones with different facies. Note that the lower zone shows sequences dominated by sheet sands (basin–floor fans). Only the highest amplitude voxels are visible. After Radovich (2002). Reprinted with permission Gulf Coast Section SEPM Foundation.

Figure 8-16.

Composite gamma ray and resistivity wireline logs through the Ram-Powell field, northern Gulf of Mexico. Note the different shape log curves for different reservoirs. (i.e. architectural elements). Sheet sands are illustrated at the top of the log (J sand). After Craig et al., 2003. Reprinted with permission of AAPG.

Figure 8-16.

Composite gamma ray and resistivity wireline logs through the Ram-Powell field, northern Gulf of Mexico. Note the different shape log curves for different reservoirs. (i.e. architectural elements). Sheet sands are illustrated at the top of the log (J sand). After Craig et al., 2003. Reprinted with permission of AAPG.

Figure 8-17.

RMS amplitude map and geologic interpretation for a 40 MS window in upper Miocene sequence, Cocuite Field, Veracruz Basin, Mexico. Sheet sands are cut by faults (linear features). Sediment transport was from the northwest to the southeast. Five wireline logs illustrate both layered and amalgamated sheet sands in the interval. Scale on wireline logs is in meters. After Arreguin (2003). Reprinted with permission of Marco J. J. Arreguin.

Figure 8-17.

RMS amplitude map and geologic interpretation for a 40 MS window in upper Miocene sequence, Cocuite Field, Veracruz Basin, Mexico. Sheet sands are cut by faults (linear features). Sediment transport was from the northwest to the southeast. Five wireline logs illustrate both layered and amalgamated sheet sands in the interval. Scale on wireline logs is in meters. After Arreguin (2003). Reprinted with permission of Marco J. J. Arreguin.

Figure 8-18.

Schematic drawing of different facies types in northern Gulf of Mexico. Three types of sheet sands (C1-3) are present. After Shanley et al. (2000). Reprinted with permission Gulf Coast Section SEPM Foundation.

Figure 8-18.

Schematic drawing of different facies types in northern Gulf of Mexico. Three types of sheet sands (C1-3) are present. After Shanley et al. (2000). Reprinted with permission Gulf Coast Section SEPM Foundation.

Figure 8-19.

Map showing (a) location of most common outcrops of sheet sandstones used by companies for outcrop characterization/reservoir modeling (Table 8-1 ), and (b) location of producing fields discussed in the text.

Figure 8-19.

Map showing (a) location of most common outcrops of sheet sandstones used by companies for outcrop characterization/reservoir modeling (Table 8-1 ), and (b) location of producing fields discussed in the text.

Figure 8-20.

(a) Cross section based on pseudo gamma ray logs of the Kilcloher Cliff Section, Upper Carboniferous Ross Formation, western Ireland. The lower section is composed of layered sheet sandstones with a net:gross of 54%, and 3% sand-on-sand bed contacts. The upper section is composed of amalgamated sheet sandstones with 90% net:gross and 67% sand-on-sand bed contacts. Length of the outcrop is approximately 660 m (2000 feet). After Chapin et al. (1994) Reprinted with permission of Gulf Coast Section SEPM Foundation.

Figure 8-20.

(a) Cross section based on pseudo gamma ray logs of the Kilcloher Cliff Section, Upper Carboniferous Ross Formation, western Ireland. The lower section is composed of layered sheet sandstones with a net:gross of 54%, and 3% sand-on-sand bed contacts. The upper section is composed of amalgamated sheet sandstones with 90% net:gross and 67% sand-on-sand bed contacts. Length of the outcrop is approximately 660 m (2000 feet). After Chapin et al. (1994) Reprinted with permission of Gulf Coast Section SEPM Foundation.

Figure 8-20.

(b) Outcrop photograph of the layered and amalgamated sheet sandstones at Kilcloher Cliff Section. After Sullivan et al. (2000). Reprinted with permission of Gulf Coast Section SEPM Foundation.

Figure 8-20.

(b) Outcrop photograph of the layered and amalgamated sheet sandstones at Kilcloher Cliff Section. After Sullivan et al. (2000). Reprinted with permission of Gulf Coast Section SEPM Foundation.

Figure 8-21.

Outcrop photograph of sheet sandstones, Grootvontein section, Permian Skoorsteenberg Formation, South Africa. Correlation panel with measured sections show lithofacies, and degree of amalgamation within the sheets. Photograph shows a portion of the outcrops described in the correlation panel. After Sullivan et al. (2000). Reprinted with permission of Gulf Coast Section SEPM Foundation.

Figure 8-21.

Outcrop photograph of sheet sandstones, Grootvontein section, Permian Skoorsteenberg Formation, South Africa. Correlation panel with measured sections show lithofacies, and degree of amalgamation within the sheets. Photograph shows a portion of the outcrops described in the correlation panel. After Sullivan et al. (2000). Reprinted with permission of Gulf Coast Section SEPM Foundation.

Figure 8-22.

Strike and dip outcrop correlation sections of the Permian Skoorsteenberg Formation, South Africa. There is a systematic decrease in thickness in the west to east dip direction, but the south to north strike section shows no such change. Shales also extend the length of the strike section, and would be fluid flow barriers in an analogous reservoir. Shales are also long and increase in abundance along the down-dip direction. There are fewer shales in the more proximal area to the west. After Wickens and Bouma (2000). Reprinted by permission of Gulf Coast Section SEPM Foundation.

Figure 8-22.

Strike and dip outcrop correlation sections of the Permian Skoorsteenberg Formation, South Africa. There is a systematic decrease in thickness in the west to east dip direction, but the south to north strike section shows no such change. Shales also extend the length of the strike section, and would be fluid flow barriers in an analogous reservoir. Shales are also long and increase in abundance along the down-dip direction. There are fewer shales in the more proximal area to the west. After Wickens and Bouma (2000). Reprinted by permission of Gulf Coast Section SEPM Foundation.

Figure 8-23 (b).

Note the presence of both thinning- and thickening-upward cycles within the sheets, the flat tops and bases to the beds that are separated by thin shale zones. After Beaubouef et al. (1999). Reprinted with permission of the AAPG.

Figure 8-23 (b).

Note the presence of both thinning- and thickening-upward cycles within the sheets, the flat tops and bases to the beds that are separated by thin shale zones. After Beaubouef et al. (1999). Reprinted with permission of the AAPG.

Figure 8-23 (a).

Outcrop photograph of the sheet sandstones, Colleen Canyon section, Permian Brushy Canyon Formation, west Texas.

Figure 8-23 (a).

Outcrop photograph of the sheet sandstones, Colleen Canyon section, Permian Brushy Canyon Formation, west Texas.

Figure 8-24.

(A) Schematic measured stratigraphic section (Morris, 1971) and outcrop gamma ray log (DeGray East) of the DeGray Lake Spillway section of the upper Jackfork Group, Pennsylvanian, Arkansas. These sections are correlated to a well log from the Shell Rex-Timber #1-9 well, drilled through the same stratigraphic section 9.5 km to the southwest (Slatt et al., 2000). The two wells form an oblique depositional strike orientation, and represent a minimum distance down the depositional axis (from the outcrop to the well), because major faults occur between the two areas. (B) Outcrop photograph shows the entire 300+m (1000 feet) thick DeGray Spillway section. (C) Photograph showing details of a 27 m (81 feet) thick interval of layered (lower part of interval) to amalgamated (upper part of interval) sheet sandstones which occurs within the Spillway section (box). Rate of change of thickness for this interval is calculated to be 12.5 m/km or 1.25%.

Figure 8-24.

(A) Schematic measured stratigraphic section (Morris, 1971) and outcrop gamma ray log (DeGray East) of the DeGray Lake Spillway section of the upper Jackfork Group, Pennsylvanian, Arkansas. These sections are correlated to a well log from the Shell Rex-Timber #1-9 well, drilled through the same stratigraphic section 9.5 km to the southwest (Slatt et al., 2000). The two wells form an oblique depositional strike orientation, and represent a minimum distance down the depositional axis (from the outcrop to the well), because major faults occur between the two areas. (B) Outcrop photograph shows the entire 300+m (1000 feet) thick DeGray Spillway section. (C) Photograph showing details of a 27 m (81 feet) thick interval of layered (lower part of interval) to amalgamated (upper part of interval) sheet sandstones which occurs within the Spillway section (box). Rate of change of thickness for this interval is calculated to be 12.5 m/km or 1.25%.

Figure 8-25.

Schematic cross section showing two types of depositional edges to sheet sandstones (yellow): (a) gradational depositional pinchout along a flat surface, (b) onlap onto an inclined surface. The type of edge in a reservoir can have a pronounced effect on volumetric calculations. After Hurst et al. (1999). Reprinted with permission of AAPG.

Figure 8-25.

Schematic cross section showing two types of depositional edges to sheet sandstones (yellow): (a) gradational depositional pinchout along a flat surface, (b) onlap onto an inclined surface. The type of edge in a reservoir can have a pronounced effect on volumetric calculations. After Hurst et al. (1999). Reprinted with permission of AAPG.

Figure 8-26.

Diagrams showing different aspects of the upper Miocene, Mt. Messenger Formation, New Zealand. (A) Wireline logs of the Pukearhue #1 well drilled immediately downdip of outcrops of equivalent strata. Four sheet sandstones (referred to as basin-floor fan complex) are shown on the logs. These same four sandstone packages crop out a few km to the north. (B) Schematic cross section of the four sheet sandstones. Each sandstone package (yellow) is erosionally based, and is separated by marls and shales (brown). The northwest end of this section occurs along a beach, so that the vertical stratigraphy is visible. In the third dimension (inland), the sandstones can be discontinuously traced about 8 km inland from the coast, where they pinch out against slope shales. Proportions of sandstones at different locations are shown by the pie diagrams. (c) Location of the Pukearuhe #1 well in relation to a north-south 2D seismic line. The four sheet sandstones correlate to four high amplitude, continuous seismic reflections. Presumably, the reflections are a result of the acoustic contrast between the sandstones and intervening marls/shales. After Browne and Slatt (2002). Reprinted with permission of AAPG.

Figure 8-26.

Diagrams showing different aspects of the upper Miocene, Mt. Messenger Formation, New Zealand. (A) Wireline logs of the Pukearhue #1 well drilled immediately downdip of outcrops of equivalent strata. Four sheet sandstones (referred to as basin-floor fan complex) are shown on the logs. These same four sandstone packages crop out a few km to the north. (B) Schematic cross section of the four sheet sandstones. Each sandstone package (yellow) is erosionally based, and is separated by marls and shales (brown). The northwest end of this section occurs along a beach, so that the vertical stratigraphy is visible. In the third dimension (inland), the sandstones can be discontinuously traced about 8 km inland from the coast, where they pinch out against slope shales. Proportions of sandstones at different locations are shown by the pie diagrams. (c) Location of the Pukearuhe #1 well in relation to a north-south 2D seismic line. The four sheet sandstones correlate to four high amplitude, continuous seismic reflections. Presumably, the reflections are a result of the acoustic contrast between the sandstones and intervening marls/shales. After Browne and Slatt (2002). Reprinted with permission of AAPG.

Figure 8-27.

Pie diagrams illustrating the proportion of various sedimentary facies in the Permian Skoorsteenberg sheet sandstones, South Africa. Note that the most common facies is a structureless (massive) sandstone. Structureless sandstones have also been noted as being most common in other sheet sandstones examined by the authors. After Morris (2000). Reprinted with permission of Gulf Coast Section SEPM Foundation.

Figure 8-27.

Pie diagrams illustrating the proportion of various sedimentary facies in the Permian Skoorsteenberg sheet sandstones, South Africa. Note that the most common facies is a structureless (massive) sandstone. Structureless sandstones have also been noted as being most common in other sheet sandstones examined by the authors. After Morris (2000). Reprinted with permission of Gulf Coast Section SEPM Foundation.

Figure 8-28.

Core photographs of the amalgamated sheet sands of the Lower Yellow reservoir, Mars Field, northern deep Gulf of Mexico. Photographs show cores under normal and UV light (showing gold fluoresence of oil). Sands are massive to planar laminated. Wireline log on the right shows the response of the cored interval. After Cumming (2002). Reprinted by permission of Gulf Coast Section SEPM Foundation.

Figure 8-28.

Core photographs of the amalgamated sheet sands of the Lower Yellow reservoir, Mars Field, northern deep Gulf of Mexico. Photographs show cores under normal and UV light (showing gold fluoresence of oil). Sands are massive to planar laminated. Wireline log on the right shows the response of the cored interval. After Cumming (2002). Reprinted by permission of Gulf Coast Section SEPM Foundation.

Figure 8-29.

Core photograph of layered sheets sands of the Upper Yellow reservoir, Mars field, northern deep Gulf of Mexico. Photographs show cores under normal and UV light (showing gold fluoresence of oil). Sand beds exhibit primarily planar laminations changing upward to ripple laminations. After Cumming (2002). Reprinted by permission of Gulf Coast Section SEPM Foundation.

Figure 8-29.

Core photograph of layered sheets sands of the Upper Yellow reservoir, Mars field, northern deep Gulf of Mexico. Photographs show cores under normal and UV light (showing gold fluoresence of oil). Sand beds exhibit primarily planar laminations changing upward to ripple laminations. After Cumming (2002). Reprinted by permission of Gulf Coast Section SEPM Foundation.

Figure 8-30.

STAR (copyright Baker-Hughes Inc.) borehole image log from the Barrel Springs 7-22 well, Dad Sandstone Member, Upper Cretaceous Lewis Shale, Wyoming. (A) Static image showing sandstones (yellow), very-fine grained sandstones and siltstones (orange) and mudstone and shales (reddish-brown to black). Flat, non-scoured bases of Bouma Ta and Tb bed couplets are shown, along with a single scour surface.(B) Dynamic normalized image from the Barrel Springs 7-22 well showing chaotic bedding due to rapid dewatering of supersaturated sand. (C) Dynamic normalized image from the Barrel Springs 7-22 well showing convolute bedding compared with similar outcrop features, and vertical dewatering pipes. After Witton-Barnes et al. (2000). Reprinted with permission of Gulf Coast Section SEPM Foundation.

Figure 8-30.

STAR (copyright Baker-Hughes Inc.) borehole image log from the Barrel Springs 7-22 well, Dad Sandstone Member, Upper Cretaceous Lewis Shale, Wyoming. (A) Static image showing sandstones (yellow), very-fine grained sandstones and siltstones (orange) and mudstone and shales (reddish-brown to black). Flat, non-scoured bases of Bouma Ta and Tb bed couplets are shown, along with a single scour surface.(B) Dynamic normalized image from the Barrel Springs 7-22 well showing chaotic bedding due to rapid dewatering of supersaturated sand. (C) Dynamic normalized image from the Barrel Springs 7-22 well showing convolute bedding compared with similar outcrop features, and vertical dewatering pipes. After Witton-Barnes et al. (2000). Reprinted with permission of Gulf Coast Section SEPM Foundation.

Figure 8-31.

Borehole image of a coarsening- and cleaning-upward, layered to amalgamated sheet sand interval from a Pliocene reservoir in the northern deep Gulf of Mexico. Thin, water-bearing sands are shown in the lower portion of the interval and thicker, oil sands are shown in the upper part. The gamma-ray log on the left shows a cleaning-upward pattern. After Slatt et al. (1994). Reprinted with permission of Gulf Coast Section SEPM Foundation.

Figure 8-31.

Borehole image of a coarsening- and cleaning-upward, layered to amalgamated sheet sand interval from a Pliocene reservoir in the northern deep Gulf of Mexico. Thin, water-bearing sands are shown in the lower portion of the interval and thicker, oil sands are shown in the upper part. The gamma-ray log on the left shows a cleaning-upward pattern. After Slatt et al. (1994). Reprinted with permission of Gulf Coast Section SEPM Foundation.

Figure 8-32.

Map of the Auger minibasin, northern Gulf of Mexico, showing the original estimates of the Auger “S” sand aquifer distribution (blue area), and the current estimate after initial production and pressure matching (pink area). The current estimate is that the aquifer is approximately equal to the size of the Auger minibasin. After Kendrick (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-32.

Map of the Auger minibasin, northern Gulf of Mexico, showing the original estimates of the Auger “S” sand aquifer distribution (blue area), and the current estimate after initial production and pressure matching (pink area). The current estimate is that the aquifer is approximately equal to the size of the Auger minibasin. After Kendrick (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-33.

Seismic profile across the Auger Field, Garden Banks 427, northern Gulf of Mexico. Reservoirs are associated with high amplitude (red) events that onlap and pinch out against the structure. Amplitude extraction is from the S-1 level and shows the oil-water contact. After Booth et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-33.

Seismic profile across the Auger Field, Garden Banks 427, northern Gulf of Mexico. Reservoirs are associated with high amplitude (red) events that onlap and pinch out against the structure. Amplitude extraction is from the S-1 level and shows the oil-water contact. After Booth et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-34.

Wireline log cross section showing the distribution of sheet sands in the Auger Field, northern Gulf of Mexico. Pink interval is amalgamated sheet sands. Blue interval is layered sheet sands. The continuous shale datum separates the two sand types. After McGee et al. (1994). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-34.

Wireline log cross section showing the distribution of sheet sands in the Auger Field, northern Gulf of Mexico. Pink interval is amalgamated sheet sands. Blue interval is layered sheet sands. The continuous shale datum separates the two sand types. After McGee et al. (1994). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-35.

Graph showing the pressure history match for the Auger S sand for initial production. The green dashed line shows the predicted pressure decline associated with the original estimated aquifer volume. The solid green line is the expected pressure history of an aquifer that is 53 times greater than the reservoir volume. The black squares indicate the actual pressure data. After Kendrick (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-35.

Graph showing the pressure history match for the Auger S sand for initial production. The green dashed line shows the predicted pressure decline associated with the original estimated aquifer volume. The solid green line is the expected pressure history of an aquifer that is 53 times greater than the reservoir volume. The black squares indicate the actual pressure data. After Kendrick (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-36.

Pulsed neutron capture (PNC) log from the Auger S sands, A-9 well, Auger Field. Gamma ray log is shown on the left, and a Pulsed Neutron Capture log is shown in the middle. The Pulsed Neutron Capture (PNC) log records replacement of oil by water during development. Years in which the logging runs were made are shown on the right graph as horizontal axis (1994-97), with each year represented by a different color. Note that there are four separate trends in the PNC log over the three year interval. These trends begin and end at some of the shales, indicating they are sealing shales which isolate sands above and below. Some linear trends continue across shales, indicating these shales are not sealing. After Kendrick (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-36.

Pulsed neutron capture (PNC) log from the Auger S sands, A-9 well, Auger Field. Gamma ray log is shown on the left, and a Pulsed Neutron Capture log is shown in the middle. The Pulsed Neutron Capture (PNC) log records replacement of oil by water during development. Years in which the logging runs were made are shown on the right graph as horizontal axis (1994-97), with each year represented by a different color. Note that there are four separate trends in the PNC log over the three year interval. These trends begin and end at some of the shales, indicating they are sealing shales which isolate sands above and below. Some linear trends continue across shales, indicating these shales are not sealing. After Kendrick (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-37.

Map showing the location of the Mars Field, and surrounding allochthonous salt, Mississippi Canyon, northern Gulf of Mexico. Nearby fields (Ursa, Crosby) are shown. After Reynolds (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-37.

Map showing the location of the Mars Field, and surrounding allochthonous salt, Mississippi Canyon, northern Gulf of Mexico. Nearby fields (Ursa, Crosby) are shown. After Reynolds (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-38.

Seismic profiles across the Mars Field, northern Gulf of Mexico, illustrating the Mars Yellow reservoir. Note (a) Lower Yellow Sand, indicated by AE1 reflection, has good lateral extent, (b) the top of the AE1 is scoured into and filled with AE3 unit, and (c) is overlain by AE 8 channel. Time based-gamma logs (yellow) are displayed on the seismic. After Reynolds (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-38.

Seismic profiles across the Mars Field, northern Gulf of Mexico, illustrating the Mars Yellow reservoir. Note (a) Lower Yellow Sand, indicated by AE1 reflection, has good lateral extent, (b) the top of the AE1 is scoured into and filled with AE3 unit, and (c) is overlain by AE 8 channel. Time based-gamma logs (yellow) are displayed on the seismic. After Reynolds (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-39.

Schematic cross section across the Yellow Reservoir, Mars Field, northern Gulf of Mexico. Architectural elements are based on core, wireline log, and seismic data. Elements 1 and 2 correspond to the Lower Yellow Interval, whereas elements 5-8 correspond to the Upper Yellow interval. After Reynolds (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-39.

Schematic cross section across the Yellow Reservoir, Mars Field, northern Gulf of Mexico. Architectural elements are based on core, wireline log, and seismic data. Elements 1 and 2 correspond to the Lower Yellow Interval, whereas elements 5-8 correspond to the Upper Yellow interval. After Reynolds (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-40.

Seismic profile across the Mensa Field, Mississippi Canyon 731, northern deep Gulf of Mexico. Reservoir is noted by the prominent seismic amplitude. After Pfeiffer et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-40.

Seismic profile across the Mensa Field, Mississippi Canyon 731, northern deep Gulf of Mexico. Reservoir is noted by the prominent seismic amplitude. After Pfeiffer et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-41.

Wireline log cross section across the Mensa Field, Mississippi Canyon blocks 686, 687, 730, and 731, northern deep Gulf of Mexico. Two discrete sheets are present: I-A (upper) and I-B (lower). The two sheets amalgamate to the right of the profile. The lower sheet pinches out to the left. After Pfeiffer et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-41.

Wireline log cross section across the Mensa Field, Mississippi Canyon blocks 686, 687, 730, and 731, northern deep Gulf of Mexico. Two discrete sheets are present: I-A (upper) and I-B (lower). The two sheets amalgamate to the right of the profile. The lower sheet pinches out to the left. After Pfeiffer et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-42.

Seismic profile across Mensa Field. The profile is from a higher frequency data set and shows the time-based gamma ray logs and the two amalgamated sheet sands, I-A and I-B. The inset map shows the location of the profile across the field. After Pfeiffer et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-42.

Seismic profile across Mensa Field. The profile is from a higher frequency data set and shows the time-based gamma ray logs and the two amalgamated sheet sands, I-A and I-B. The inset map shows the location of the profile across the field. After Pfeiffer et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-43.

Schematic cross section across the Mensa Field, northern deep Gulf of Mexico. This section was drawn after the integration of the higher frequency seismic data with well information. Additional data defined three discrete sheets, two of which are in pressure communication. After Pfeiffer et al. (2000). Reprinted with permission of the Gulf Coast Section SEPM Foundation.

Figure 8-43.