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An Integrated Approach to Characterization and Modeling of Deep-water Reservoirs, Diana Field, Western Gulf of Mexico*
By
Morgan
D. Sullivan,1
J. Lincoln Foreman,2 David C. Jennette,3 David Stern,2
Gerrick N. Jensen,4 and Frank J. Goulding4
Search and Discovery Article #40153 (2005)
Posted May 9, 2005
*Online
version of article with same title by same authors in AAPG Memoir 80, 2004,
1ExxonMobil Upstream Research Company, Houston, Texas, U.S.A.; Current affiliation: Department of Geosciences, California State University, Chico, California U.S.A. ([email protected])
2ExxonMobil Upstream Research Company, Houston, Texas, U.S.A.
3ExxonMobil Upstream Research Company, Houston, Texas, U.S.A.; Current affiliation: Bureau of Economic Geology, The University of Texas, Austin, Texas, U.S.A. ([email protected])
4ExxonMobil Exploration Company, Houston, Texas, U.S.A.
Abstract
layered
downdip. This
subsurface data, however, does not have the resolution to provide the
dimensional and architectural information required to populate an object-based
three-dimensional geologic model for more accurate flow simulation and
well-performance prediction. To solve these uncertainties, deep-water outcrop
analog data from the Lower Permian Skoorsteenberg Formation in the Tanqua Karoo
Basin, South Africa, and the Upper Carboniferous Ross Formation in the Clare
Basin, western Ireland, were integrated with the seismic and well data from the
Diana field. Bed-scale reservoir architectures were quantified with photomosaics
and by correlation of closely spaced measured sections. Bed continuity and
connectivity data, along with vertical and lateral facies variability
information, also were collected, as these factors ultimately control the
reservoir behavior. From these measurements, a spectrum of channel dimensions
and shapes were compiled to condition the modeled objects. These dimensions were
compared to Diana specific seismic and well data and adjusted accordingly. The
advantage of the resulting Diana geologic model is that it incorporates geologic
interpretation, honors all available information, and models the reservoir as
discrete objects with specific dimensions, facies juxtaposition, and
connectivity. This study provides the framework for optimal placement of wells
to maximize the architectural and facies controls on reservoir performance
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Introduction
The Diana field is situated in
the western Gulf of Mexico 260 km (160 mi) south of Galveston in
approximately 1430 m (4700 ft) of water (Figure
1). ExxonMobil is the operator with 66% interest, whereas British
Petroleum (BP) holds a 33% interest. Diana is the second largest of
several discoveries recently made in the Diana Subbasin and has in
excess of 100 MMBOE of recoverable hydrocarbons from the upper Pliocene
A-50 reservoir. The turbiditic sandstones and mudstones that comprise
the A-50 reservoir at the Diana field were deposited as a lowstand fan
in an intraslope basin setting. The field is located on the east flank
of a north-south The challenge at the Diana field
was to predict the production performance of a channelized deep-water
reservoir with a relatively thin oil rim and a large gas cap (Figure
1). Associated development costs are high, requiring an optimization
program to ensure a successful project. These predictions were
challenged further by variable-quality seismic data, a reservoir
thickness expressed by a single-cycle seismic event, only limited
appraisal wells, and the likelihood for subseismic reservoir variability
that could control the economic viability of the project. To assist with
reserve assessments and optimization of depletion strategies, deep-water
outcrop analog data were integrated with seismic and well data to
produce a detailed object-based In the Diana study, two outcrop analogs were found to be most applicable to the penetrated subsurface reservoirs based on similarities in grain size, facies associations, and interpreted sand-body architecture. These were the Lower Permian Skoorsteenberg Formation in the Tanqua Karoo Basin, South Africa, and the Upper Carboniferous Ross Formation in the Clare Basin, western Ireland. These deep-water turbidite successions have been studied widely in recent years by Collinson et al. (1991), Bouma and Wickens (1994), Chapin et al. (1994), Sullivan et al. (1998), Bouma (2000), Elliot (2000), Martinsen et al. (2000), Morris et al. (2000), and Sullivan et al. (2000a, b). The main purpose of this current outcrop study was to provide the data necessary to help assess future prospects and newly discovered fields with analogous reservoir characteristics. To better understand and apply the observations and learnings from this outcrop analog study, normal-incidence forward seismic models were constructed for both the Skoorsteenberg and Ross Formations. These models illustrate both the seismic facies of the individual outcrops using Diana subsurface rock properties (density and velocity) and the resolution limits of typical seismic data. By combining dimensional and architectural data from outcrops with seismic, well-log, and core data from the subsurface, it is possible to construct more accurate reservoir models for deep-water turbidite sandstones for Diana and other fields. Such studies are important because they greatly reduce the uncertainties associated with reservoir assessment parameters for economically important deep-water turbidite sandstones.
Deep-Water Outcrop Analogs
Outcrop analogs span a critical gap in both scale and resolution between
seismic and wellbore data. The integration of appropriate outcrop
analogs, core, well-log, and seismic data can provide the detailed
geometric properties required for interpreting the reservoir
architecture at a subseismic or flow-unit scale. The Lower Permian
Skoorsteenberg Formation in Tanqua Karoo Basin, South Africa, and the
Upper Carboniferous Ross Formation in the Clare Basin, western Ireland,
are both composed of stacked turbiditic sandstones and mudstones
deposited in a channelized basin-floor fan setting. These laterally
continuous outcrops provide an excellent opportunity to characterize
detailed bed-scale reservoir architectures and internal heterogeneities
that affect the producibility of deep-water sand bodies in both
depositional strike and dip perspectives. The selection of appropriate
outcrop analogs, however, is extremely important. The criteria for
choosing the outcrops of the Skoorsteenberg and Ross Formations as
analogs for A-50 reservoir at Diana was based on comparison of key
reservoir characteristics such as grain size, lithofacies, net-to-gross
(ratio of sandstone vs. mudstone), and sand-body architecture. Because
of the strong similarities between the selected outcrop analogs and the
A-50 reservoir, dimensional and architectural data from these outcrops
can be used to help constrain an object-based three-dimensional (3-D)
geologic Based on detailed characterization, the deep-water sandstones present in the outcrop localities can be divided into proximal, transition from proximal to medial, and medial fan settings (Figure 2). Distal fan deposits are also present but were not a focus of this study because of their limited reservoir potential and relatively poor exposure. The presented proximal-to-distal subdivision is for an idealized slope-to-basin transition. It is recognized, however, that it is the change in the slope gradient that ultimately controls the degree of channelization (Imran et al., 1998). Therefore, appropriate outcrop analogs for subsurface data sets need to be selected based on similarities in interpreted sand-body architecture and not on interpreted similarities in location in a slope-to-basin profile.
Proximal FanThe most proximal exposures of both the Skoorsteenberg and Ross Formations are dominated by compensationally stacked, erosionally confined channels and interchannel sheets. These narrow proximal fan channels are typically less than 400 m (1300 ft) wide and 5-12 m (16-39 ft) thick, with aspect ratios (width vs. thickness) ranging from 30:1 to 80:1 (Figures 3, 4). Net-to-gross ratios for individual measured sections range from 70 to 95%, with an average of approximately 90%. Two distinct styles of channel fills are recognized. The proximal fan channels of the Skoorsteenberg Formation are typically filled from axes to margins by amalgamated, thick-bedded (>30 cm), fine- to medium-grained, massive sandstones (Figure 3). Massive sandstones commonly grade upward into thick-bedded, fine-grained, planar-stratified sandstones and rare thin-bedded (<30 cm), very fine- to fine-grained, current-ripple-stratified sandstones. The interchannel strata are comprised of nonamalgamated thin- to thick-bedded current-ripple-laminated sandstones and interbedded laminated silty mudstones. In contrast, the proximal fan channels in the Ross Formation exhibit a lateral degradation in reservoir quality. They are dominated by highly amalgamated massive to cross-bedded sandstones in an axial position that grade laterally into progressively thinner-bedded, less-amalgamated massive sandstones toward the margins (Figure 4). This difference in the lateral degree of amalgamation, from axis to marginal, for the proximal fan channels of the Skoorsteenberg and Ross Formations may suggest differences in the scale and size of the turbidity currents that deposited the sandstones. The vertically and laterally amalgamated massive sandstones, which comprise the channel fills in the Skoorsteenberg Formation, are interpreted to have been deposited by high-concentration turbidity currents that completely filled the channels and, therefore, display no variations from axis to margin (Figure 3). Overbanking of these turbidity currents is interpreted to have produced the distinct interchannel association dominated by low-concentration turbidites (planar- and current-ripple-stratified sandstones). By contrast, the distinct axis-to-margin variations in the Ross Formation suggest that the turbidity currents that deposited these sandstones were underfit relative to the channels (Figure 4). This conclusion is also supported by the general lack of low-concentration turbidite-dominated interchannel deposits in the Ross Formation.
Transition from Proximal to Medial Fan
Dominating the transition from proximal to medial fan settings for both
the Skoorsteenberg and Ross Formations are compensationally stacked,
very broad (high aspect ratio) weakly confined channels. These channels
are as much as 1000 m (3270 ft) wide and 8-13 m (26-42 ft) thick (Figures
5, 6). Their bases tend to be
nonerosional, suggesting that they are primarily aggradational in
origin. In general, these channels do not infill erosional scours;
instead, they are compensationally stacked because of preexisting highs
related to underlying channels. Individual channelized sand bodies can
be further subdivided into distinct channel-axis and channel-margin
facies associations. Highly amalgamated, massive sandstones characterize
channel-axis deposits. Away from the axis, beds become distinctly less
amalgamated and extremely continuous to produce laterally extensive,
Medial Fan
Medial fan deposits are also similar for both the Skoorsteenberg and
Ross outcrops and are comprised of extremely broad, unconfined channels
or sheets (Figure 7). The bases of these
sand-prone sheets tend to be nonerosional, comparable to the broad
channels of the proximal to medial fan transition. They also appear to
be compensationally stacked or laterally offset because of depositional
highs related to underlying sand bodies. Individual sheets are 3-7 m
(10-23 ft) thick, with narrow, amalgamated axes and more sheetlike,
Forward Seismic Modeling Of Deep-Water Outcrops
The major uncertainties associated with exploration and development of deep-water reservoirs are predrill predictions of net-to-gross and assessment of reservoir continuity and net-to-gross away from well penetrations. Based on recent drilling results for deep-water petroleum reservoirs, successfully estimating reservoir continuity and net-to-gross away from well penetrations requires correct interpretation of reservoir type. ExxonMobil's postdrill analyses in several deep-water basins have shown that the information required to successfully predict these parameters is often embedded in the seismic response of reservoirs. The challenge for seismic analysis, therefore, is the proper interpretation of these seismic responses. The paucity of well control and the abundance of high-quality 3-D seismic data at the exploration and development scales require interpretation of reservoir type, or environment of deposition, to be performed using detailed seismic facies analysis. Key criteria of ExxonMobil's deep-water seismic facies scheme include external geometry (e.g., truncation, onlap, mounding, etc.), amplitude strength and continuity (e.g., high-amplitude continuous vs. high-amplitude semicontinuous), and attribute map patterns. Because of the nonuniqueness inherent in seismic facies analysis, translation of these seismic facies into depositional environments requires careful selection of an appropriate analog, be it either subsurface or outcrop based. In the case of outcrops, architectural analysis can provide the characteristics of the fundamental units that comprise subsurface reservoirs. Different architectural elements yield different seismic signatures, such as channels vs. sheets and axial vs. marginal lithofacies associations. Typically, these elements are at or below seismic resolution. Additional challenges of applying the outcrop analogs appropriately to a seismic response are related to the signatures of individual sand bodies, which can vary with the seismic bandwidth and rock properties. Lastly, most single channels and sheets stack to form complexes, and the interplay between these different individual sand bodies can also modify their seismic signatures. Normal-incidence forward seismic models have been constructed using GXII seismic modeling software for both the Skoorsteenberg and Ross Formations to calibrate the appropriate outcrop analogs to the Diana subsurface data. These models are shown in Figures 8, 9, 10 and illustrate both the seismic facies of individual outcrops using subsurface rock properties (density and velocity) from the Gulf of Mexico and the resolution limits of typical seismic data. All forward seismic models were generated using vertical-incidence ray tracing and a zero-phase Ricker wavelet. A trough (red) represents a negative impedance boundary, and a peak (black) represents a positive impedance boundary. Each of the outcrops discussed in the previous section would be seismically expressed as a single cycle at the bandwidth and rock properties of the deep-water Gulf of Mexico. These models provide a link between the architectures observed in outcrop and seismic data in the same way synthetic seismograms link well-log and core data to seismic data. The comparative seismic response
of the medial, transition from proximal to medial, and proximal portions
of the Skoorsteenberg and Ross Formations reveals that the variations in
sand-body architecture and degree of vertical and lateral amalgamation
are manifested as changes in amplitude strength and continuity and
subtle changes in isochron. As would be expected, the Individual channels from the proximal to medial fan transition of the Ross Formation are not resolvable except at the highest frequency (Figure 9). At the channel-complex scale, however, the lateral change from high net-to-gross axis to lower net-to-gross margin is reflected clearly in a lateral degradation of amplitude strength. This indicates that these distinct lateral changes in sand percentage should be seismically detectable. The vertically and laterally amalgamated, high net-to-gross proximal fan channels of the Skoorsteenberg Formation also display a high- to moderate-amplitude, moderately continuous seismic character (Figure 10). In contrast to the medial fan sheets, however, modeling of these outcrops exhibits greater evidence of variation in isochron because of the channelized nature of the outcrops. Each of these forward seismic models is subtly different. These differences reflect the proximal to distal variations that are inherent in many deep-water depositional systems. Integrating the knowledge from detailed analysis of these deep-water outcrops and forward seismic modeling can provide important information concerning variations in reservoir architecture and net-to-gross values that can ultimately control the development potential of many deep-water reservoirs.
Diana Subsurface DataFigures 11-15
Based on detailed analysis, the 3-D seismic data at the Diana field appears to be of variable quality and does not allow direct geometric analysis of reservoir elements (Figure 1B). To assist with assessment, deep-water outcrop analog data and forward seismic modeling were integrated with seismic and well data to produce a more accurate characterization of the reservoir. Seismic amplitude extractions for the A-50 reservoir display distinct stripes in the in-line direction that are interpreted to be related to the acquisition of the survey. This complicates any quantitative attribute analysis of the reservoir and restricts the application of seismic amplitude map patterns to delineate sand-body trends and dimensions. Qualitative examination of vertical seismic in-lines and cross-lines, however, provides valuable information concerning the architecture of the reservoir elements (Figures 11, 12). The A-50 sands are low impedance where they are hydrocarbon charged and are typically represented by a single-cycle seismic event (trough-peak pair) with a trough (red = negative impedance boundary) at the top and a peak (black = positive impedance boundary) at the base on zero-phase data. The proximal portion of the Diana
field, which includes the Diana 2 and Diana 3 well penetrations, is
represented by high-amplitude, continuous seismic character above the
gas-oil contact (Figure 11). The observed
amplitude dimming toward the Diana 3 location is fluid related (change
from gas to oil) and is not associated with variations in net-to-gross (Figures
13, 14, 15A).
This suggests that, if variation in net-to-gross and reservoir
architecture exists in this portion of the reservoir, it is below
seismic detection. Furthermore, forward seismic modeling indicates that
both high net-to-gross, amalgamated proximal fan channels (Figure
10) and moderate net-to-gross, The medial portion of the field
(Diana 1 well penetration) has a distinctly different seismic character
than the updip portion of the reservoir (Diana 2/Diana 3 region) and is
represented by a high-amplitude, semicontinuous seismic character above
the gas/oil contact (Figure 12A). Forward
seismic modeling shows that lateral change from high net-to-gross to
lower net-to-gross should be reflected by a degradation of amplitude
strength (Figure 9). This suggests that the
lateral variation in seismic character of the A-50 sands in the vicinity
of Diana 1 is caused by seismically detectable variations in
net-to-gross and reservoir architecture. Well penetrations confirm this
interpretation, as Diana 2 was drilled in a higher-amplitude portion of
the reservoir and encountered approximately 85% net-to-gross (Figure
15A). Diana 3 also is extremely high net-to-gross (Figures
13, 14, 15A),
but it was drilled in the oil leg and, as a result, has a lower
amplitude. In contrast, Diana 1 is drilled in a lower amplitude within
the gas cap, and the net-to-gross is significantly lower (approximately
65%). Laterally away from the Diana 1 penetration, the amplitudes
brighten, and this is interpreted to reflect more axial, higher
net-to-gross portions of the reservoir (Figure
12A). The seismic character of this segment of the reservoir,
therefore, suggests a less-channelized reservoir than updip (Figure
12C). In fact, the seismic character is very similar to the forward
seismic Excellent core coverage in the
Diana field also enables close calibration of seismic and well data. The
cored interval is comprised of stacked, sharp-based, upward-fining
channels (Figures 13,
14). Individual channel-fill successions can
be subdivided into channel-axis, channel off-axis, and channel-margin
associations in a similar fashion as the outcrops of the Skoorsteenberg
and Ross Formations (Figures 3,
4, 5,
6, 7).
Channel-axis deposits are characterized by highly amalgamated, massive
sandstones deposited from high-concentration turbidity currents (Figures
13, 14). The channel off-axis
association is composed of stacked, semi- to nonamalgamated, massive to
planar-stratified sandstones and interlaminated mudstones (Figure
14). The channel-margin deposits contain a variety of lithofacies
and are characterized by a heterolithic mixture of interbedded
sandstones and mudstones (Figures 13,
14). Statistical foot-by-foot comparisons of
log curves vs. core-described lithofacies were used to interpret
depositional facies in uncored portions of wells. Blocked wells were
further used to condition an object-based geologic Integration of seismic, well-log,
and core data with forward seismic models of deep-water outcrop analogs,
therefore, suggests a more channelized reservoir updip (Figure
11), becoming more distributive and sheetlike downdip (Figure
12). This subsurface data, however, does not have the resolution to
provide the dimensional and architectural data required to populate a
geologic
Diana
Reservoir
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FIGURE 16. Single-channel (facies
body) |
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FIGURE
18. Net-to-gross map generated from the facies |
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FIGURE
19. Side scan sonar image for Mississippi Fan illustrating
the detailed sand-body architecture. The bright colors represent
more sand-prone regions of the fan. The map pattern of this
modern fan, which has been rotated to match the orientation of
the Diana net-to-gross |
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FIGURE
20. Oil saturation maps for the Diana oil rim for the first
4 yr of production. Note that the Diana gas cap and aquifer are
not shown. The updip portion of the reservoir has higher initial
oil saturations because of its higher porosities and also starts
making high water cuts earlier than the downdip portion of the
reservoir because of its more amalgamated character and better
reservoir quality. The smaller cell size observed at the
proximal portion of the |
To solve these uncertainties,
dimensional and architectural data (e.g., width vs. thickness
measurements) from the Skoorsteenberg and Ross deep-water outcrops (Figures
3, 4, 5,
6, 7) were
compared to the interpreted thickness data derived from the
Diana-specific seismic, well-log, and core data and were adjusted
accordingly (Figures 13,
14, 15A). From
these measurements, a spectrum of channel dimensions and shapes was
collected. Comparison of the forward seismic models of the
Skoorsteenberg and Ross deep-water outcrops to the actual Diana seismic
data was made to select the appropriate architectural data to populate
the reservoir model (Figures 11,
12, 15). In
addition to the collection of channel dimensions and shapes, bed
continuity, and lateral and vertical facies, variability data also were
gathered from both outcrop analogs and well logs/core to condition the
reservoir model, as these factors ultimately control the reservoir
behavior (Figures 6,
13, 14).
In the case of the Diana field,
this data was used to help maximize the development of the relatively
thin, yet economically important oil rim. This was accomplished by
building a detailed object-based reservoir model, which integrated both
subsurface and outcrop data. The model was built using ExxonMobil
proprietary code for modeling deep-water reservoirs and the reservoir
modeling system IRAP-RMS object-based modeling tool. This model consists
of discrete objects (facies bodies), each with specific dimensions,
facies juxtapositions, and continuity. This type of modeling is
appropriate in data-limited situations where a facies model is based on
a conceptual interpretation of reservoir architecture. The reason for
choosing this technique to model the Diana reservoir included (1) the
poor quality of the seismic data, (2) limited well penetrations, (3)
interpretation of the reservoir being comprised of channels with
distinct lateral changes in facies (axis to margin), (4) interpretation
of updip to downdip changes in channel architecture and net-to-gross,
and (5) desire to apply a concept-driven geologic model that
incorporated outcrop analog information.
The fundamental object in this
reservoir model is a turbidite-dominated deep-water channel. In the
Diana model, individual channels are narrow updip and become wider and
less amalgamated downdip (Figures 16,
17), as observed in the outcrops of both the
Skoorsteenberg and Ross formations (Figures 3,
4, 5,
6, 7). Modeled
channels are divided into proximal, medial, and distal regions with
their own specific set of characteristics. Channels are subdivided
further into axis, off-axis, and margin associations. Lateral
degradation in reservoir quality from axis to margin is interpreted from
core data, as observed in the outcrops of the Skoorsteenberg and Ross
Formations (Figures 3,
4, 5,
6, 7). Shales
were inserted as objects in a fine-layer (0.1 m) framework. The spatial
distribution of shales in a given facies type is random (e.g., there was
no preferential placement of shale either areally or vertically in the
3-D model volume). The volume of shale added to a facies depended on the
net-to-gross of the facies type (e.g., axis vs. margin). Shale
dimensions were obtained from the Skoorsteenberg and Ross Formations (Figure
6). Shale objects in the model are square or rectangular in shape,
and their dimensions depend on facies type (e.g., axis vs. margin) and
location (e.g., proximal vs. distal).
The final model contains more
than 100 individual channels, each one stochastically generated from a
range of possible widths and thicknesses (Figures
16, 17, 18).
The facies objects were inserted first at the well locations and then
subsequently inserted stochastically into interwell regions according to
geologic constraints (e.g., vertical stacking patterns), until volume
targets were met. Net-to-gross maps, which were generated by calculating
the average value of the sand-shale parameter at a given X, Y
location in the model, provide an indication of how the net sand is
distributed in the model (Figure 18). The
resulting net-to-gross maps strongly resemble modern deep-water systems,
such as the Mississippi Fan (Figure 19), and
further support this integrated study. Each facies and subfacies body
was then populated with petrophysical properties using Gaussian
simulation drawn from subfacies property histograms generated from
available well data. To preserve the facies architecture and
heterogeneity expected in a channel-dominated deep-water setting, the
rock property modeling was performed in individual channel objects.
Based on this modeling effort and flow simulation, significant variations in reservoir performance exist from updip to downdip (Figure 20). The development strategy for the Diana field is to produce oil initially from horizontal wells high in the oil rim. Once water breaks through in significant quantities, these wells will be recompleted in the gas cap. The goal is to maximize oil production while minimizing water production and movement of oil into the gas cap. Typically, reservoir models are scaled up for flow simulation. However, in this case, the updip portion of the reservoir was actually scaled down to preserve its more channelized and amalgamated nature (Figure 20). The updip portion of the reservoir has higher initial oil saturations because of its higher porosities. It also starts producing water earlier than the downdip portion of the reservoir because of its higher porosities and more channelized nature. This study, therefore, predicts significant variations in reservoir producibility that exist across the Diana field. This information was used to place wells in optimum locations to maximize the architectural controls on reservoir performance and has had a significant impact on the final development strategy for the field.
Conclusions
This study shows the importance of incorporating outcrop analogs in the analysis of subsurface reservoirs. Outcrop research is critical because the observed updip to downdip variability in sand-body geometry, continuity, and net-to-gross of deep-water reservoirs affects both the exploration and production potential of these sandstones. Commonly, this variability, as in the case of the A-50 reservoir at the Diana field, is at or below seismic resolution, and well penetrations are typically limited. Properly calibrated deep-water outcrops can provide constrained geometric and architectural data to fill the gaps between wells or stochastic modeling uncertainties below the resolution of seismic data. Dimensional and architectural data from outcrops and forward seismic modeling can therefore be integrated with seismic and wellbore data to build regional depositional models to better understand reservoir distribution and delineate exploration plays. Deep-water outcrop data can also be used to help populate object-based models that can be used to more accurately predict well performance, connected volumes, and recovery efficiencies for newly discovered fields. Furthermore, the integration of seismic, well-log, core, and outcrop data with object-based models provides the framework for optimal placement of wells to maximize the architectural controls on reservoir performance. The bottom-line impact of this type of integrated analysis has been a significant reduction in the range of uncertainty attached to reservoir assessment parameters for deep-water sandstones, both in the Diana Subbasin and in many other areas where exploration and development of deep-water reservoirs is currently occurring.
References Cited
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Chapin, M.A., P. Davies, J.L. Gibson, and H.S., Pettingill, 1994, Reservoir architecture of turbidite sheet sandstones in laterally extensive outcrops, Ross Formation, western Ireland, in P. Weimer, A.H. Bouma, and B.F. Perkins, eds., Submarine fans and turbidite reservoirs: Gulf Coast Section SEPM Foundation, Fifteenth Annual Research Conference, p. 53-68.
Collinson, J.D., O.J. Martinsen, and A. Kloster, 1991, Early fill of the Western Irish Namurian Basin: A complex relationship between turbidites and deltas: Basin Research, v. 3, p. 223-242.
Elliot, T., 2000, Depositional architecture of a sand-rich, channelized turbidite system: the Upper Carboniferous Ross Sandstone Formation, western Ireland, in P. Weimer, R.M. Slatt, A.H. Bouma, and D.T. Lawrence, eds., Deep-water reservoirs of the world: Gulf Coast Section SEPM Foundation, Twentieth Annual Research Conference, p. 342-373.
Imran, J., G. Parker, and N. Katopodes, 1998,
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Martinsen, O.J., T. Lien, and R. Walker, 2000, Upper Carboniferous deep water sediments, western Ireland: Analogues for passive margin turbidite plays, in P. Weimer, R.M. Slatt, A.H. Bouma, and D.T. Lawrence, eds., Deep-water reservoirs of the world: Gulf Coast Section SEPM Foundation, Twentieth Annual Research Conference, p. 533-555.
Morris, W.R., M.H. Scheihing, H. de V. Wickens, and A.H., Bouma, 2000, Reservoir architecture of deep-water sandstones: Examples from the Skoorsteenberg Formation, Tanqua Karoo Sub-basin, South Africa, in P. Weimer, R.M. Slatt, A.H. Bouma, and D.T. Lawrence, eds., Deep-water reservoirs of the world: Gulf Coast Section SEPM Foundation, Twentieth Annual Research Conference, p. 629-666.
Sullivan, M.D., and P. Templet, 2002, Characterization of fine-grained deep-water turbidite reservoirs: Examples from Diana Sub-Basin, western Gulf of Mexico, in P. Weimer, M. Sweet, M.D. Sullivan, J. Kendrick, D. Pyles, and A. Donovan, eds., Gulf Coast Section SEPM Foundation: Deep-water Core Workshop, northern Gulf of Mexico, CD-ROM, p. 75-92.
Sullivan, M.D., J.L. Foreman, M. Devries, and A. Khan, 1998, Application of deepwater outcrop analogs to 3-D reservoir modeling: An example from the Diana field, western Gulf of Mexico, in M.R. Mello and P.O. Yilmaz, eds., International AAPG Meeting Extended Abstracts Volume, Rio de Janeiro, Brazil, November 8-11, 1998, p. 24-25.
Sullivan, M.D., J.L. Foreman, D.C. Jennette, D. Stern, and A. Liesch, 2000a, Application of deepwater outcrop analogs to 3-D reservoir modeling: An example from the Diana field, western Gulf of Mexico, in R. Shoup, J. Watkins, J. Karlo, and D. Hall, eds., AAPG/Datapages Discovery Series No. 1: Integration of geologic models for understanding risk in the Gulf of Mexico, p. 1-14.
Sullivan, M.D., G.N. Jensen, F.J. Goulding, D.C. Jennette, J.L. Foreman, and D. Stern, 2000b, Architectural analysis of deep-water outcrops: Implications for exploration and production of the Diana Sub-basin, western Gulf of Mexico, in P. Weimer, R.M. Slatt, A.H. Bouma, and D.T. Lawrence, eds., Deep-water reservoirs of the world: Gulf Coast Section SEPM Foundation, Twentieth Annual Research Conference, p. 1010-1032.
Twichell, D.C., W.C. Schwab, and N.H. Kenyon, 1995, Geometry of sandy deposits at the distal edge of the Mississippi Fan, Gulf of Mexico, in K.T. Pickering, R.N. Hiscott, N.H. Kenyon, F. . Lucchi, and R.D.A. Smith, eds., Atlas of deep water environments: Architectural style in turbidite systems: London, Chapman and Hall, p. 282-286.
Acknowledgments
The authors would like to thank Dave Larue, Mike DeVries, Arfan Khan, DeVille Wickens, and Arnold Bouma for their assistance in collecting outcrop data from the Skoorsteenberg Formation. Ian Moore, Chris Armstrong, Kevin Keogh, and Trevor Elliot are also thanked for their assistance in collecting portions of the outcrop data from the Ross Formation. Permission to publish this paper was granted by ExxonMobil Upstream Research and by BP Exploration. The authors would also like to thank Grant Wach, William Schweller, Jim Borer, Michael Grammer, and Ray Sullivan for reviewing and improving this paper. In addition, we would like to acknowledge Ed Garza for all of his assistance in producing the illustrations presented in this paper