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Exploration and Appraisal Challenges in the Gulf of Mexico Deep-Water
Wilcox: Part 1—Exploration Overview, Reservoir Quality, and Seismic
Imaging
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Lewis, Jennifer
Clinch, Simon
Meyer, Dave
Richards, Matt
Skirius, Christine
Stokes, Ron
Zarra, Larry
Chevron North America Exploration and Production
Company
1500 Louisiana Street
Houston, Texas 77002
jnnl@chevron.com
Abstract
The deep-water Wilcox trend covers more than
34,000 mi2, extending across the Alaminos Canyon,
Keathley Canyon, and Walker Ridge protraction areas,
plus parts of adjacent protraction areas and Mexican
territorial waters. Discoveries are in turbidite sands that
have been deposited in lower slope channels and ponded fans to regionally extensive basin floor fan systems.
Primary trap styles are compressional Louann saltcored symmetrical box folds, symmetrical salt pillows,
and asymmetrical salt cored thrust anticlines. More than
20 wildcat wells have been drilled in the Wilcox Trend.
Recoverable reserves for each of the 12 announced discoveries range from 40 to 500 million barrels of oil
(MMBO). Ultimately, the Wilcox trend has the potential for recovering 3 to 15 billion barrels of oil reserves
(BBO) from these discoveries and additional untested
structures. Many technical issues need to be resolved to
move the billions of barrels of resources trapped in
deep-water Wilcox structures to recoverable economic
reserves. Exploration challenges include well depths up
to 35,000 feet subsea, water depths ranging from 4,000
to 10,000 feet, and salt canopies from 7,000 to more
than 20,000 feet thick. Allochthonous salt covers 90%
of the trend, complicating regional reconstructions and
resolution of individual structures. Appraisal challenges
include: delineating and modeling reservoir quality,
The Paleogene of the Gulf of Mexico and Caribbean Basins: Processes, Events, and Petroleum Systems
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sand distribution, and flow capability; improving complex sub-salt images; and developing cost effective
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The Wilcox Formation is an important petroleum
trend in the northwestern Gulf of Mexico coastal plain.
Earliest production was established in south and southeast Texas in the late 1920’s. Continued exploration
delineated fluvial, deltaic, and shallow marine sandstone reservoirs ranging from the Burgos Basin in
northeast Mexico to Texas, Louisiana, Mississippi, and
Alabama. Estimated recoverable reserves (EUR) from
the onshore Wilcox trend exceed 30 trillion cubic feet
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drilling, completion, facility, and infrastructure designs.
Introduction
(TCF) of gas. Most of the onshore reserves are gas, and
most have already been produced.
Recent discoveries in the deep-water Gulf of
Mexico document a significant petroleum resource in
turbidite channel and fan systems that are deep basin
equivalents to the onshore Wilcox trend. These deepwater Wilcox turbidite reservoirs are located more than
250 miles downdip from delta systems in the onshore
Wilcox subsurface section, and extend for more than
300 miles across the deep basin (Fig. 1).
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Objectives
The purpose of this two-part paper is to review
the critical obstacles and challenges that must be overcome in order for the deep-water Wilcox trend to move
from a highly successful exploration play to a profitable
producing trend. In Part 1, we review some of the
exploration challenges associated with exploring in a
high cost and high risk environment. We also discuss
subsalt seismic imaging and reservoir quality.
Part 2 is primarily focused on uncertainties relevant to permeability. We also address permeability
measurement and transforms, modeling, and factors
that affect local permeability distribution.
Exploration challenges
Some of the challenges involved in exploring the
deep-water Wilcox trend are a result of geographic
location in the basin. The trend extends across Alaminos Canyon, Keathley Canyon, and Walker Ridge, plus
Lewis et al.
parts of adjacent protraction areas (Fig. 1). The range of
water depths for the trend is from approximately 4,000
to 10,000 feet. The top of the Wilcox is as shallow as
12,000 feet in the Perdido Fold Belt area of Alaminos
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Canyon, and ranges to more than 30,000 feet subsea on
trend to the east. About 90 percent of this trend is
located under modern allocthonous salt canopies, which
range from 7,000 to more 20,000 feet thick.
Exploring at these depths for objectives below a
thick salt canopy involves complex drilling programs
using high-cost rigs, which are limited in number and
availability. Another complication of exploration in the
subsalt environment has been generally poor seismic
resolution in conventional 3D seismic surveys. Recent
seismic wide-azimuth (WAz) towed streamer acquisition and processing has greatly enhanced the ability to
confidently map the subsalt environment (Lewis and
Neal, 2007). However, individual sandstone reservoirs
remain below seismic resolution.
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fined fan systems in Walker Ridge. Stratigraphy and
depositional systems of the deep-water Wilcox trend
are discussed in detail in a separate paper at this conference (Zarra, 2007).
The first significant deep-water Wilcox penetration was the Baha well, drilled in 2001 in Alaminos
Canyon Block 557. Although this well was a dry hole, it
did find 4,500 feet of Wilcox turbidites containing a 12
foot oil zone (Fig. 3). The Baha #2 well was soon followed by discoveries at Trident (Alaminos Canyon
Block 903) in late 2001 and Great White (Alaminos
Canyon Block 857) in 2002. In late 2002 and 2003, the
Wilcox trend was extended more than 250 miles to the
east with the Cascade (Walker Ridge Block 206), Chinook Deep (Walker Ridge Block 469), and St. Malo
(Walker Ridge Block 678) discoveries in Walker Ridge
(Fig. 4). The emergence and development of the deepwater Wilcox trend was reviewed in detail by Meyer et
al. (2005) and Meyer et al. (2007).
The only production test in the trend has been at
the Jack #2 well (Walker Ridge 758). The Jack well
location is in 7,000 feet of water, and the tested interval
is greater than 25,000 feet subsea. In September 2006,
Chevron announced a sustained flow rate of over 6,000
barrels of oil per day from approximately 40% of the
reservoir. Test results significantly increase the understanding of trend deliverability (Rains et al., 2007).
The first phase of discovery in the prolific deepwater Wilcox trend began in March 2001 with the plugging of the BAHA #2 well and concluded in September
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Exploration results to date indicate that the probability of finding sandstone reservoirs in the deep-water
Wilcox section is high, as all of the exploration and
appraisal wells in this trend have encountered some turbidite sandstones. This depositional system traverses
approximately 400 miles, from Alaminos Canyon in the
west, to Atwater Valley in the east (Fig. 2). Integrated
well and seismic interpretations define a turbidite succession up to 6,000 feet thick in Alaminos Canyon, and
about 2,500 feet thick in eastern Walker Ridge. Stratigraphic analysis of more than 20 wells across this trend
documents a regionally extensive series of turbidite systems. Depositional settings for these turbidites range
from leveed channels, ponded fans, and channelized
fans in Alaminos Canyon, to channelized and unconLewis et al.
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2006 with the press release of the Jack #2 flow-test.
During this 5 ½ year period, seventeen wildcats resulted
in twelve discoveries that found over 15 billion barrels
of oil in place (Fig. 1). The deep-water Wilcox trend
exploration success rate of 70% is two times greater
than the 35% success rate for the entire deep-water Gulf
of Mexico. Approximately 2 billion barrels of oil equivalent (BBOE) of resource have been discovered in
Wilcox turbidites, accounting for 14% of the 16 BBOE
total resource discovered to date in all deep-water Gulf
of Mexico trends. Over $2 billion have been spent to
drill, delineate, and test relatively well imaged saltcored anticline structures that lay either outboard of the
Sigsbee Escarpment (Fig. 4A) or just within the subsalt environment at the distal edge of the Sigsbee Canopy system (Fig. 4B). This high-cost, high-potential,
deep-water Wilcox trend has a potential ultimate
reserve range of 3 to 15 BBOE with a mean of 8 BBOE
reserves (Meyer et al., 2005).
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The next generation of exploration and drilling
was initiated by the 2006 Kaskida discovery in Keathley
Canyon Block 292. This was the first Wilcox sub-salt
wildcat located significantly inboard of the Sigsbee
Escarpment and penetrated a much more complex seismic imaging area (Fig. 5). Complexities in this northern
tier of Wilcox prospects included a more dynamic salt
tectonic history, which influenced both depositional and
diagenetic components of the Wilcox petroleum system.
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Prospective structures are typically juxtaposed
against salt roots or welds resulting in 3-way dip-component trap closures. Approximately 70% of the deepwater Wilcox Trend lies within this structural province,
a factor that has influenced the next generation of seismic acquisition and processing. The success of this new
technology will play a major factor in unlocking the
potential of the Wilcox in this area.
Seismic imaging challenges
As industry progresses into appraisal and development of deep-water subsalt fields, answers to new and
increasingly detailed questions are sought in an effort to
minimize risk and optimize project value. However,
with only a handful of well penetrations and generally
poor quality subsalt seismic data, many structural uncertainties remain. Key uncertainties such as faulting,
compartmentalization, and overall structural geometry
all play prominent roles in determining well placement
Lewis et al.
and well count, factors that impact ultimate recovery,
development scenarios, and project economics.
The seismic data quality covering this frontier
area is typical of many subsalt images. Data at the reservoir level are low frequency (~10 Hz dominant) and
contaminated with remnant multiple noise, making
characterization of key reservoir uncertainties such as
faulting an onerous undertaking at best. Amplitude
analysis of the reservoir is inappropriate given the mod401 Session I
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est angle of incidence (mid-20° range), weak and
uneven subsalt illumination, and the lack of a fluid
response in consolidated, grain-supported rocks.
Much of the structural uncertainty on maps interpreted from subsalt pre-stack depth migrated data
(PSDM) can be attributed to poor vertical resolution
and velocity error. Velocities in the initial vendor speculative PSDM analyses do not resolve a regional lowvelocity layer nor incorporate anisotropy in the model
that results in a seismic image which is, in general, too
deep and steep. Furthermore, the salt model lacks detail
in key areas which also degrades the subsalt image.
Subsequent products incorporate more detail in their
sediment velocities and salt models, but with few wells,
subsalt velocity resolution is limited by geometry of the
salt canopy, which allows a subsalt angle of incidence
of no more than 25°.
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To date, all PSDM products covering subsalt Wilcox fields show acoustic artifacts resulting from
attempts at multiple attenuation. In some products, the
remnant multiples overwhelm the primary events. In
others, the multiples are removed but at the expense of
often severe primary attenuation. Perhaps most distressing is that when remnant multiples are migrated, “wavefronted” noise trains combine with primary events, and
may resemble the geometry of a faulted anticline, which
is a reasonable geologic scenario. Needless to say, given
few wells and a weak seismic image, characterization of
the structure, much less the reservoir, presents a considerable challenge. Our basic assertion is that in a deepwater, sparse well setting, better seismic data quality
leads to better decisions. Hence, we should do everything possible to improve the quality of seismic data.
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Seismic resolution issues are compounded by a
low signal-to-noise ratio. Over many structures in this
region, the water bottom and top salt are separated by a
thin sheath of sediment while the reservoirs are beneath
an undulating salt layer that can exceed 10,000 feet
thick. The challenging result of this configuration is
that water bottom and top salt multiples commonly
coincide with and contaminate primary energy at the
reservoir level. A representative example of the effect
of top salt and water bottom multiples on seismic quality is shown for a seismic transect at the Jack field
(Fig. 6).
Lewis et al.
Recently, industry has recognized a step-change
improvement in subsurface imaging in deep-water subsalt settings with wide-azimuth (WAz) towed streamer
acquisition and processing. Presented with the opportunity for a similar improvement in the data quality over a
Chevron-operated field, an integrated modeling effort
was undertaken to understand the best approach to
enhance signal-to-noise through new seismic acquisition (Lewis and Neal, 2007). Results suggest that WAz
uplift is primarily due to inherent multiple suppression,
and to a much lesser extent, enhanced illumination and
increased fold. Upfront multiple attenuation through
acquisition offset allows for gentler parameterization of
demultiple algorithms, leaving more opportunity to pre402 Session I
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serve the integrity of primary energy. Early data
analysis indicates that the WAz survey contributes to a
higher quality subsalt image, facilitating a clearer
understanding of structure, faulting, and perhaps
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stratigraphy. Increased confidence in interpretation can
lead to improved characterization of risk and uncertainty throughout the entire appraisal process.
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Reservoir quality challenges
Understanding the factors affecting porosity and
permeability is paramount for reservoir modeling in the
appraisal and development stages of project maturation.
The reservoir sections at the Jack and St. Malo structures are very thick, consisting of approximately 1,400
to 1,600 feet of turbidite deposits within moderately
high energy, basin floor distributary fan to channelized
fan systems. The gross depositional facies described for
the Wilcox 1 (upper unit) and Wilcox 2 (lower unit) are
remarkably consistent across a large portion of Walker
Ridge, showing similar depositional characteristics over
this large area. Coring to-date of the reservoir intervals
on these structures (917 ft. total of conventional core)
still only samples less than 20% to 30% of the potential
reservoir section, and there is more extensive core coverage for the Wilcox 1. The core samples, however,
form the basis of our understanding of reservoir quality
and are used to link petrologic analyses to depositional
facies. Also, the conventional core data are calibrated to
the electric log responses so that the logs can be used to
more accurately predict reservoir quality over intervals
with no core control. Calibrated logs are employed to
populate reservoir characteristics in static and dynamic
Lewis et al.
reservoir models from which all economic and production forecasts are based.
One of the key technical challenges for commerciality of the Wilcox trend is reservoir quality and how
it relates to flow capability. Wilcox reservoir rocks are
generally characterized by low permeability, with measured core permeability typically less than 10
millidarcys (md). Measured core porosity values range
from approximately 15% to 25%, but within this porosity range, permeability can vary over three orders of
magnitude. The large range in permeability data provides a difficult challenge for accurate permeability
modeling, where this range must be reduced to less than
an order of magnitude. To achieve this goal, we have
generated electrofacies to group rocks with similar fluid
flow properties. By adopting fluid flow-based electrofacies at Jack and St. Malo, the range in permeability at
any given porosity has been reduced by half. Outside
core control, the use of a single transform has the potential to introduce large biases. To reduce the possibility
of this potential bias, it is important to implement multiple permeability transforms from various data sources
and compute the average of all transforms.
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Although low permeabilities are characteristic,
measurements up to ~200 md have been documented
within certain intervals. Measured core permeabilities
are generally higher in the deeper Wilcox 2 compared
to the Wilcox 1. In addition, the highest permeabilities
are not always associated with the highest porosities.
The controls on permeability are found to be a complex
interplay of depositional facies, compaction, and
diagenesis. The ability to accurately predict porosity
and permeability at the prospect and regional scales will
determine our success at development well placement
and play longevity.
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shows no correlation to permeability except for the
well-sorted tractional (Tt) deposits of the channelized
facies. Except for these tractional (Tt) deposits, depositional facies are not easily characterized by grain size or
sorting. Overall, textural attributes are first order depositional controls on reservoir quality and permeability
for the Wilcox.
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Typical Wilcox reservoir rock is described as
very fine-grained, lithic-rich, thinly interbedded to massive sandstone. However, differences in sandstone
depositional facies, texture, and grain composition are
observed within the Wilcox 1 and Wilcox 2 that have an
impact on reservoir quality. The Wilcox 1 represents
unconfined deposition within the inner, middle, and
outer portions of a distributary fan system. In contrast,
the Wilcox 2 represents deposition within a channelized
fan system. Highest measured permeabilities are associated with some better sorted, relatively coarser-grained,
planar laminated to graded tractional deposits associated with a channel axis lithofacies association. For
both the Wilcox 1 and the Wilcox 2, grain sizes are
characteristically very fine; average grain sizes range
from coarse silt to fine sand, and sorting is generally
moderate to poor. In general, better permeability correlates to better sorting and lower clay content. Grain size
Lewis et al.
In addition to very fine grain size, Wilcox reservoir rocks are also characterized by high lithic grain
content. Sandstones are classified as feldspathic litharenites and show a distinctive trend to more quartz
grain-rich compositions in the Wilcox 2 (Fig. 7). The
generally more quartz-rich grain composition of the
Wilcox 2, along with slightly coarser grain sizes and
better sorting, likely reflects the increased energy of a
channelized depositional setting. Lithic grain types in
both the Wilcox 1 and Wilcox 2 are generally similar,
the most abundant being finely crystalline, schistose
metamorphics. Other important grain types are variably
altered silicic volcanics and sedimentary rock fragments such as shale, and mica grains (muscovite and
biotite). Although the proportions of volcanic (VRF),
metamorphic (MRF), and sedimentary (SRF) rock
fragment grain types are generally similar for the Wilcox 1 and 2 (Fig. 7), depth trends of some grain types
and slightly shifting lithic grain type abundance
between wells may indicate slight changes in the source
of sediment input over time. Depth trends in clay types
are also apparent in the data, reflecting changing detrital mineralogy as well as a diagenetic overprint.
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Diagenetic effects are assessed in terms of compaction and cementation. Compaction due to effective
stress has a greater effect on Wilcox 1 sandstone due to
its higher content of ductile grain types, particularly
altered volcanic and micaceous metamorphic lithic
types. The Wilcox 2 sandstone is richer in rigid quartz
grains, and as such, is less prone to porosity loss from
compaction (Fig. 8). In addition, because of the higher
abundance of micaceous metamorphic lithics and mica
grains in the Wilcox 1, grain shapes tend to be elongate
compared to the more equant-shaped quartz grains
common in Wilcox 2. This difference in grain shape
affects grain packing arrangement at deposition that
will subsequently influence pore size and pore geometry with continued compaction and cementation.
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particularly chlorite grain coatings, and carbonate minerals. Chlorite clay is observed in the highest
permeability samples as nearly complete grain coatings
that inhibit quartz cementation. Quartz cement is more
abundant, on average, in Wilcox 2 compared to Wilcox
1 because more quartz grains are present as nucleation
sites and also because deeper and hotter conditions are
more conducive to cementation. However, the presence
of minor to moderate amounts of quartz cement does
not necessarily detract from the overall reservoir quality
of higher permeability samples in Wilcox 2.
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In addition to the effects of compaction, cementation also plays a role in Wilcox reservoir quality.
Cementation is dominantly controlled by temperature
and occurs primarily as quartz overgrowths on detrital
quartz grains. Other cements include authigenic clays,
Touchstone diagenetic modeling is being applied
to the Jack and St. Malo assets to yield porosity and
permeability predictions for current and future
appraisal well locations based on 2D and 3D geohistory
models. Model results, based on analogs calibrated to
conventional core, depositional facies and electrofacies,
should guide our interpretations of permeability distribution across these large structures.
Conclusions
Since 2001, more than two dozen wells have been
drilled into the deep-water Wilcox. While geologic success rates are very high, economic viability for some
discoveries remains uncertain. Complex reservoir
rocks, complicated geohistories, and low permeabilities, require a significant focus on reservoir quality and
Lewis et al.
basin histories. Water depth, reservoir depth, and poor
seismic imaging provide added complications. Solutions in progress include: WAz seismic surveys,
petrologic work on whole core, detailed formation evaluation of logs, basin modeling, and diagenetic
modeling.
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References
Lewis, J., and S. Neal, S, 2007, Wide -azimuth seismic at the
subsalt Jack asset: Is it worth the early investment?:
The Leading Edge, v. 26, no. 9, in press.
Meyer, D., L. Zarra, D.B. Rains, R. Meltz, and T. Hall, 2005,
Emergence of the Lower Tertiary Wilcox trend: World
Oil, v. 226, no. 5, p. 72–77.
Meyer, D., L. Zarra, and J. Yun, 2007, From BAHA to Jack,
Development of the Lower Tertiary Wilcox Trend in
the Deep-water Gulf of Mexico: Sedimentary Record,
v. 5, no. 3, in press.
Rains, D. B., L. Zarra, D. Meyer, 2007, The lower Tertiary
Wilcox trend in the deep-water Gulf of Mexico:
AAPG National Convention, Long Beach, California,
29 p. http://www.conferencearchives.com/aapg2007/
sessions/player.html?sid=07041202
(last accessed
September 5, 2007).
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Lewis et al.
Zarra, L., 2007, Chronostratigraphic Framework for the Wilcox Formation (Upper Paleocene–Lower Eocene) in
the Deep-Water Gulf of Mexico: Biostratigraphy,
Sequences, and Depositional Systems: GCSSEPM
Foundation 27th Annual Bob F. Perkins Research
Conference, in press.
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Figure 1. Deep water Gulf of Mexico trend map showing relevant wells and possible areal extent of the Wilcox turbidite trend. Summary of wildcat wells is tabulated from press releases and interpreted from publicly available data (as of
July, 2007). Locations for seismic lines shown on Figures 2 through 6 are also indicated on this map.
Lewis et al.
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Figure 2. Regional 2D time seismic transect and interpreted cross section extend ~425 miles, from the Perdido Fold Belt to the Mississippi Fan Fold Belt, outboard
of the modern allocthonous salt canopy. On this section the Wilcox is an essentially tabular unit, thinning from west to east.
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Figure 3. The Baha #2 well was located on a thrusted, symmetrical box fold in the Perdido Fold Belt area of Alaminos
Canyon. This 2001 wildcat was the first significant penetration of deep-water Wilcox turbidites and documented a
working petroleum system.
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Figure 4. (A) The 2002 Cascade wildcat was drilled on a well imaged salt cored anticline outboard of the modern allocthonous salt canopy. This was the first Wilcox discovery in Walker Ridge. (B) The 2003 St Malo wildcat was drilled on a salt cored anticline and was the first subsalt discovery in the deep-water Wilcox
trend.
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Figure 5. The 2006 Kaskida discovery in Keathley Canyon Block 292 was the first Wilcox subsalt wildcat located significantly inboard of the Sigsbee Escarpment. This well penetrated a more complex seismic imaging area than wells closer
to the outboard edge of the salt canopy.
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Figure 6. At Jack, three significant free-surface multiples associated with water bottom (wb) and top salt (ts) map
directly to the reservoir level. The structure is relatively well illuminated for the subsalt but multiples coincide with and
contaminate the reservoir signal, imposing a significant challenge in reservoir imaging.
Lewis et al.
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Figure 7. Normalized Quartz (Q), Feldspar (F), and Lithic (L) sandstone compositions for Wilcox 1 (upper unit) and
Wilcox 2 (lower unit). Ternary plot in upper right shows normalized total volcanic (VRF), metamorphic (MRF), and
sedimentary (SRF) lithic compositions for the Wilcox 1 and 2.
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Figure 8. Representative photomicrographs of Wilcox 1 (left) and Wilcox 2 (right) sandstone taken at the same magnification (100X). These photos illustrate the general change in reservoir sandstone grain composition and texture
between the lithic-rich Wilcox 1 and the more quartz grain-rich and slightly coarser-grained Wilcox 2.
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