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Figure Captions
Figure
1. Example of a regional seismic line from the eastern Gulf of Mexico
that illustrates limited disruption, by salt, of the shallow
stratigraphic section. Note that deep wells have penetrated several of
the potential source intervals.
Figure
2. Interpreted hydrocarbon-systems map for the northern Gulf of Mexico
Basin. Each hydrocarbon system comprises a family of oils and gases
having similar compositions and interpreted to have originated from a
common source interval. Stars indicate selected major deep-water
discoveries.
Figure
3. Stratigraphic column showing the Mesozoic source intervals (arrows)
for the offshore Gulf of Mexico. Note that source intervals coincide
with second-order transgressions in a sequence-stratigraphic framework
(e.g., Haq et al., 1988).
Figure
4. Gulf of Mexico regional seep-distribution map based on more than 5200
sea- bottom dropcores plus sea-surface slicks identified on
remote-sensing data. (A) abundant/large oil seeps with prevalent thermogenic gas; (B) abundant/large oil seeps with less thermogenic gas;
(C) abundant/large oil seeps with only limited thermogenic gas; and (D)
limited hydrocarbon seepage. Within areas A, B, and C, nearly 75% of the
sea- bottom dropcores contain moderate or substantial quantities of oil,
compared with only about 12% within area D. Within area A, more than 25%
of the oil-bearing sea- bottom dropcores also contain substantial
quantities of thermogenic (headspace) gas, compared with less than 5% in
area C.
Click here for sequence of Figure 2
(hydrocarbon-systems map) and Figure 4 (seep-distribution map).
Figure
5. Example of a biodegradation profile within a single sea- bottom
dropcore from Ewing Banks. Total depth of the core is about 5 ft (1.5
m). Biodegradation is apparent in both the oils (GCs) and the headspace
gas. The intensity of biodegradation appears to decrease with depth. MFI
= maximum fluorescence intensity, used to evaluate oil concentrations.
Figure
6. Comparison of deepest oil sample from sea- bottom dropcore in Figure 5
with a nearby reservoired oil sample. Although the GC indicates that the
seep oil has undergone a markedly higher degree of biodegradation, the
more biodegradation-resistant terpane and triaromatic steroid biomarkers
are quite similar, indicating that both samples
are probably derived
from the same source (Tithonian).
Figure
7. Whole-oil gas chromatogram and terpane bio-marker (m/z 191) scan of a
sea- bottom sediment extract from offshore Florida containing the
signature of carbonate-sourced oil (peaks highlighted in green)
overprinted with recent organic matter (peaks highlighted in blue).
Interpretations of source family and hydrocarbon maturity for the
petroleum can be made in “windows” in which the interference by recent
organic matter is limited.
Figure
8. Sea- bottom dropcore grid within Viosca Knoll, designed to evaluate
the utility of seeps for defining the limit of field extent as indicated
by seismic-amplitude anomalies (shaded area).
Although the MFI values
over the amplitude anomaly appear to be somewhat higher than for
dropcores near the right and upper limits of the grid, these data do not
provide the capability to closely constrain the limits of the anomaly.
Some of the largest MFI values are from dropcores collected near the
intersection of the cross-stratal migration pathway with the seafloor.
Figure
9. Example of a seismic line showing the source intervals and several
potential hydrocarbon migration pathways (compliments of Veritas Marine
Services).
Figure
10. Example of a seismic line showing the interpreted cross-stratal
migration pathway to a large discovery in the southern Mississippi
Canyon. Hydrocarbon migration is interpreted to occur up the collapsed
salt stock, then near the salt/sediment interface, and finally up small
faults to the seafloor.
Figure
11. Example of a seismic line showing a close-up of a seafloor mound
interpreted to represent a chemosynthetic community over the cross-stratal
migration pathway illustrated in Figure 10.
MFI values from nearby
dropcores are projected onto the line.
Figure
12. Comparison of a seep oil with the oil from a nearby discovery.
Although the oil in the seep is heavily biodegraded and the reservoired
oil is not, the strong similarity of terpane biomarkers suggests that
both oils derive from a common source.
Table Caption
Table
1. Northern Gulf of Mexico Basin source intervals (ages), hydrocarbon
families, and summary of established rock-oil ties.
Return
to top.
Continued exploration success in the
northern U.S. Gulf of Mexico Basin requires a thorough understanding of
all elements of the hydrocarbon systems. To this end, Exxon (now
ExxonMobil) has carried out an integrated study to assess sources,
maturation, and migration pathways of known and potential hydrocarbon
plays in the offshore U.S. Gulf of Mexico. Exxon’s multidisciplinary
approach has involved development of a regional geologic framework
through the interpretation of 2-D and 3-D seismic data, identification
and mapping of potential source intervals, and delineation of likely
migration path-ways. This approach permits evaluation of hydrocarbon
migration from mature source intervals to known accumulations and
potential reservoirs, as identified by seismic-amplitude anomalies.
The recognition of widespread, and often
intense, oil and natural-gas seepage on the Gulf of Mexico Slope has
contributed significantly to our understanding of the hydrocarbon
systems. As part of this study, we analyzed a large number of sea- bottom
dropcores (>5000) and identified surface slicks from remote-sensing
data. The sea- bottom dropcores were obtained from existing proprietary
dropcore programs, industry consortia, and geotechnical shallow-hazard
surveys. Characterization of oils and natural gases in seeps has allowed
us to extend our hydrocarbon-family and hydrocarbon-maturity maps far
beyond well control. Moreover, abundant seepage documents active
hydrocarbon migration on the Gulf of Mexico Slope and provides a means
to identify effective migration pathways. Major hydrocarbon
accumulations on the slope are commonly associated with intense seepage
at the seafloor intersection of the corresponding cross-stratal
migration pathways. Thus, seeps provide information that potentially can
be used to help rank possible migration pathways to prospects. In
addition, the geochemical composition of seep hydrocarbons (as
interpreted from biomarkers) can provide important predrilling
information about the likely properties of unbiodegraded oils (e.g., API
gravity and sulfur content). Oil properties can have a significant
impact on production and refinement costs and therefore on product
value. By providing advance knowledge about the likely oil properties,
seeps can make a major contribution to the economic evaluation of a
potential hydrocarbon accumulation.
The sources for oils reservoired in the
young Tertiary section of the offshore Gulf of Mexico have been
enigmatic in the past, because of a paucity of source-rock penetrations
in offshore drilling. Many approaches have been used to infer source
intervals. For example, Nunn and Sassen (1986) used maturation modeling
to suggest that Cretaceous and lower Tertiary sediments were the
probable sources of oils in the offshore Louisiana continental-slope
area. Our approach was to focus on an initial study area east of the
present-day Mississippi River Delta where the Tertiary section thins and
wells have penetrated deep potential source rocks. This area was also
selected because the complete stratigraphic section can be imaged on
seismic sections, because of only limited interference from shallow
salt. To the west, where secondary and even tertiary salt features are
abundant in the shallow section, samples of organic-rich rock (dated by
microfossils) have been obtained from sheaths overlying salt diapirs.
These samples have provided access to source rocks in areas where they
typically lie far below current drilling depths. When combined with
known, effective source-rock penetrations from the onshore northern Gulf
basin and integrated within a regional geologic framework, these data
provide a strong basis for source-age
interpretations (Wenger et al., 1994).
Geochemical compositions
of reservoired and seep hydrocarbons provide a perspective on the
regional characteristics and maturity of their respective source rocks.
Oil and, to some extent, natural-gas compositions constrain such
source-rock characteristics as organic-matter type, clastic versus
carbonate facies, elevated versus normal salinity, level of maturation
and, to a lesser extent, age. In all, more than 2000 reservoired oils,
600 reservoired natural gases, and 3000 hydrocarbon-bearing sea- bottom
dropcores from the northern Gulf basin have been analyzed. Source-rock
ages and the oil types (families) related to each source interval are
based on direct comparison of biomarkers to source-rock extracts (e.g.,
Peters and Moldowan, 1993) as well as inferences drawn from hydrocarbon
compositions and constraints of the geologic framework.
To the east of the
present-day Mississippi River Delta, source intervals occur at depths
between about 16,000 and 35,000 ft (4900–10,700 m) and are generally
visible on seismic sections because of only limited interference by
small, simple salt bodies above source levels (Figure 1). In contrast,
to the west, the source intervals commonly occur at depths between
30,000 and 45,000+ ft (9200–13,700+ m), and seismic visibility is
hampered by the presence of multilayered salt sills and/or salt welds
with complex geometries formed by sediment loading. Interpretation of
hydrocarbon families and source intervals in this more complex setting
was guided by extending westward the observations and methodologies
developed in the east and north. Most 2-D seismic surveys designed to
image common reservoir intervals are generally inadequate to only
marginally adequate for imaging deeper source intervals and migration
pathways. These data are typically high (60–75) fold, acquired with
4000–4500 m of cable, and recorded to 8 seconds (s). Dramatic
improvements in imaging the total hydrocarbon system are provided by a
longer cable (6000 m), 3-D versus 2-D acquisition, and longer recording
times (15 s). To date, 3-D data collected using a 6000-m cable have
provided some of the best resolution (Gross et
al., 1995). We used more than 3500 mi 2 (9100 km 2 ) of 3-D seismic data
and 25,000 line-mi (40,250 line-km) of 2-D seismic data within the area east of the Mississippi
River Delta, including a 4-mi (6.4-km) grid of 6000-m cable data,
recorded to 15 s. A similar amount of seismic data was interpreted to
the west of the Mississippi River Delta,
on the Louisiana Shelf and Slope and the Texas Slope.
Return
to top.
Knowledge of the effective
source rocks for an area is critical to understanding the overall
hydrocarbon system. Critical source-rock penetrations both offshore and
on-shore in the northern Gulf of
Mexico Basin, when integrated into a regional geologic framework,
provide a strong basis for interpreting source age and distribution
(Figure 2). The youngest effective
source interval identified in the northern Gulf basin is in lower
Tertiary strata, centered on the Eocene (Table 1). No significant
Oligocene or younger source rocks have been identified. Oils from the
lower Tertiary source have been divided into three sub-types: Tertiary
Marine, Tertiary Intermediate, and Tertiary Terrestrial. They reflect a
genetically related continuum of hydrocarbons derived from varying
mixtures of marine-algal and higher-plant organic matter related to the
distribution of shale facies within (or distal to) the Tertiary delta
system. Direct correlations to source rocks have been made for all lower
Tertiary oil types (McDade et al., 1993). Variations in source-rock
character are consistent with the distribution of oil subtypes and with
paleofacies of the Eocene deltaic system. Source-rock ties from onshore
have been extrapolated to similar oils on the offshore shelf and slope,
assuming a corresponding relationship to depositional facies.
Organic-rich rocks of Eocene age have been penetrated offshore in
sheaths overlying salt diapirs, although the high level of maturity
precluded direct rock-oil ties based on geochemical compositions.
Regional differences in
the original organic-matter composition of the lower Tertiary source
appear to explain much of the variation in the resulting hydrocarbon
compositions (distribution of oil versus gas). The marine-source subtype
appears to produce a greater proportion of oil, whereas the
terrestrial-source subtype appears to be more gas prone. This conclusion
contrasts with interpretations in which the prevalence of thermogenic
natural gases and gas condensates on the Texas Shelf and onshore has
been attributed to higher source maturity (e.g., Thompson et al., 1990).
The next-older source
interval identified is in Upper Cretaceous strata, centered on the
Turonian. Turonian source rocks are clay-rich shales with dominantly
marine organic matter that generates low-sulfur oils (Marine–Low
Sulfur–No Tertiary Influence). Direct oil-to-source-rock ties have been
made offshore, east of the present Mississippi River Delta, and onshore
in the Tuscaloosa trend of Louisiana and Mississippi and the Giddings
trend of Texas (see also Wagner et al., 1994). Offshore, we interpret a
basinward loss of Turonian source rocks based on seismically displayed
thinning of the interval and disappearance of the oil type. In south
Texas, a more calcareous (moderate-sulfur) oil type
(Calcareous–Undifferentiated Cretaceous) may result, in part from a
facies change in the Turonian, although this oil type has also been tied
directly to a Lower Cretaceous marine calcareous shale. High-sulfur oils
from the Sunniland trend
(Carbonate–Elevated Salinity–Lower Cretaceous) of the South Florida
Basin are derived from Lower Cretaceous strata, centered on the Aptian.
The source for most reservoired
thermogenic hydrocarbons on the Gulf of Mexico Slope is interpreted to
be uppermost Jurassic, centered on the Tithonian. Organic-rich
calcareous shales of Tithonian age have been penetrated and sampled
within wells in the area east of the present Mississippi River Delta.
Although the high maturity level of these shales makes geochemical
correlation (using biomarkers) with early-mature hydrocarbons on the
slope difficult, extrapolation of source character from oils constrains
the age of the appropriate facies in the area of occurrence for this oil
type. Geographic variations in source facies are probably responsible
for differences in sulfur content and associated geochemical parameters
(Moderate Sulfur, Moderately High Sulfur, and High-sulfur oil subtypes)
of unbiodegraded oils. Oils and stains of these subtypes (distinct from
older Oxfordian oils) occur in Cretaceous reservoirs on the Florida
Shelf where the Tertiary and Upper Cretaceous sections are immature.
Hydrocarbons occurring in many uppermost Jurassic and Lower Cretaceous
reservoirs along the onshore northern rim of the Gulf basin, which are
geochemically distinct from the two older oil types described below,
have also been tentatively ascribed to a Tithonian source
(Calcareous–Upper Jurassic or Lower Cretaceous?). These oils have never
been encountered in Oxfordian or older reservoirs. The Tithonian has
also been reported to be the major source of oils in the Mexican Gulf of
Mexico (González-Garciá and Holguin-Quiñones, 1992).
Upper Jurassic (Oxfordian)
carbonate-sourced oils (Carbonate–Elevated Salinity–Jurassic oil type)
are common across the northern rim of the Gulf basin from northeast
Texas to Florida (Oehler, 1984; Wenger et al., 1990). The distinctive
geochemical signature of this oil type puts extremely tight constraints
on the age of the source facies. Organic-rich, postmature carbonates
from Mobile Bay provide a correlative rock tie. Seeps and stains of this oil type in the deep central
Gulf confirm a widespread deep basin occurrence of the source interval,
assuming minimal changes in facies.
Finally, hydrocarbons from a Triassic
lacustrine source have been encountered along the bounding faults of the
northern Gulf basin. These hydrocarbon liquids display a strong (and
unusual) fermenting bacterial input from the source facies. Although
they are postmature where penetrated, paleontologic and palynologic
analyses of organic-rich Triassic cores from northeast Texas have
confirmed the nonmarine (i.e., the lacustrine) nature of the
depositional environment and have provided a basis for correlation with
these geochemically unusual liquids (Schumacher and Parker, 1990; James
et al., 1993).
The four key source intervals in the
offshore Gulf of Mexico (centered on lower Tertiary, Upper Cretaceous,
Upper Jurassic–Tithonian, and Upper Jurassic–Oxfordian strata) coincide
with second-order transgressions in a sequence-stratigraphic framework
(Figure 3). Core and cuttings analyses indicate that source richness can
vary considerably within an interval, possibly reflecting local or
temporal variations in the environment.
Return
to top.
Remote-sensing (satellite)
techniques are useful screening tools for identifying potential
hydrocarbon seepage in a basin (e.g., MacDonald et al., 1993). Various
techniques, such as Landsat Thematic Mapper and Synthetic Aperture
Radar, can image hydrocarbon slicks remotely on the sea surface.
Hydrocarbons on the sea surface often dampen ripples and reduce the
reflectivity of water, making slicks appear as darker patterns on the
sea surface. Remote-sensing techniques are often expedient because large
offshore areas can be screened rapidly and in a cost-effective manner.
Application of multiple techniques and/or multitemporal images raises
confidence in the interpretation of authentic natural surface slicks.
Abundant natural slicks generally indicate an active hydrocarbon system (e.g., MacGregor,
1993; Kornacki et al., 1994) and may provide some evidence of
hydrocarbon charge limits.
Slick distributions
provide an initial guide to areas that are candidates for site-specific,
sea- bottom sediment coring surveys. Numerous factors can affect both the
interpretation of authentic seepage and
the location of surface slicks relative to source vents on the sea
bottom . These factors include wind velocity and direction, currents,
cloud cover, meteorologic conditions, marine vegetation, and
anthropogenic pollution. After candidate areas have been
identified, the next step is to verify the sea- bottom source of the
hydrocarbons. High-resolution 2-D and 3-D seismic data, sometimes
complemented by side-scan sonar surveys, are used to identify sea- bottom
features from which dropcores can be collected. Potential targets
include the surface expressions of deep-cutting faults and diapirs, as
well as such other water- bottom features as mounds and pockmarks. Many
such water- bottom features in the deep-water Gulf of Mexico contain
small quantities of hydrocarbons that have migrated from depth.
Dropcores collected over targeted water- bottom features are analyzed for
the presence and geochemical characteristics of petroleum hydrocarbons.
SEA- BOTTOM HYDROCARBON SEEPS
The Gulf of Mexico Slope
contains widespread areas of oil and gas seepage (Figure 4) that have
allowed investigators to extend hydrocarbon-system maps and predictions
of hydrocarbon type and properties far beyond well control. The utility
of seeps as a tool for interpreting hydrocarbon characteristics and
distribution, however, is limited by several factors. First, the
hydrocarbons (both oil and gas) in large seeps are often highly
biodegraded. Large seeps provide sites for complex chemosynthetic
communities that live off seeping oil and natural gas (MacDonald
et al., 1996). Biodegradation appears to be a rapid process. In
laboratory simulations, heavy biodegradation can occur within a few
weeks (e.g., Connan, 1984). Interestingly, many large seeps in the Gulf
of Mexico appear to be more intensely biodegraded than smaller seeps
are, despite the apparently greater influx of fresh hydrocarbons. This
difference may result because the greater in-flux of hydrocarbons
associated with large seeps increases the likelihood that a large
chemosynthetic community will be established at that site. Second, the
abundance and geochemical compositions of petroleum
hydrocarbons can be obscured by recent organic-matter components
indigenous to the sea- bottom sediments that are extracted along with
oil. The biologic signal must be “subtracted” to give the thermogenic
signature that provides information on the source and thermal maturity
of the seep oil. As illustrated below, both biodegradation and the
overprint of recent organic matter can be factored into interpretations
of the characteristics of seep oil extracted from sea- bottom sediments.
Figure 5 illustrates the intense
hydrocarbon biodegradation that can be encountered in dropcores
collected on the Gulf of Mexico Slope. In this particular example, only
about 5 ft (1.5 m) of sediments was recovered, although most Gulf of
Mexico dropcores recover about 15 ft (4.6 m) of sediment. The limited
penetration likely results from an authigenic carbonate hard-ground
surface formed in response to hydrocarbon seepage. Canned headspace gas
concentrations and whole-extract gas chromatograms (GCs) are shown for
three sections sampled from the core. Oil concentrations are evaluated
by the maximum fluorescence intensity (MFI) measured on sea- bottom
sediment extracts (Brooks et al., 1983, 1986) and by the appearance of
whole-extract gas chromatograms. MFIs in this core range from 230,000 to
414,000 using a Perkin-Elmer 650-40 spectrophotometer.
All three samples from the dropcore
contained high levels of natural gas and oil, and a pronounced
biodegradation profile is evident in both the oil and gas compositions
over a depth range of less than 5 ft (1.5 m). Moderate to severe
biodegradation of oil and gas has occurred in the upper 2.5 ft (0.8 m)
of sediment. The extent of biodegradation is evident by depletion of n-alkanes,
large unresolved complex mixture (UCM) humps on the GCs, and
preferential removal of C3 and n-C 4 by microbial biodegradation of gas.
Entry or preservation of some fresh, unbiodegraded oil and gas between
4.5 and 5 ft (1.4–1.5 m) is indicated by the unbiodegraded character of
the GCs (n-alkanes intact) and the high proportion of n-C 4 to (i-C 4 +
n-C 4) in the headspace gas. Figure 6 shows comparative GC and biomarker
analyses for the seep and a nearby reservoired oil. Because the
reservoired oil is not biodegraded, the deepest (unbiodegraded) sample
from the dropcore is used for comparison. Biomarker compositions for the
reservoired oil and the seep are comparable, suggesting that the oils
belong to the same hydrocarbon family and originated from the same
source.
To evaluate the hydrocarbons in
sea- bottom sediments, the oil component is extracted with a solvent for
analysis. Seeps with limited quantities of hydrocarbons commonly will
show an overprint of recent organic components that are extracted by the
solvent along with the oil. In large seeps, the signature of recent
organic components is usually overwhelmed by high concentrations of oil.
For seeps with lesser amounts of oil, the biological signature must be
discounted in order to interpret the thermogenic signature correctly.
This differentiation is crucial, because only the thermogenic signature
provides information on the source and the thermal maturity of the
petroleum hydrocarbons. One benefit of interpreting petroleum
characteristics from lower-concentration seeps is that the biomarkers
typically are less altered by biodegradation, and they better reflect
primary petroleum signatures in those “windows” of the analyses where
recent organic-matter components do not co-elute and interfere with oil
components (Figure 7).
Seeps can be used to enhance our
understanding of several aspects of the hydrocarbon system, including
source maturation and migration timing. On the Gulf of Mexico Slope,
many large hydrocarbon accumulations have large seeps at the
intersection of the cross-stratal migration pathway with the seafloor.
For reasons discussed below, we interpret these large seeps to indicate
active, ongoing charge from the source rather than trap failure
resulting from inadequate seal or structural deformation subsequent to
hydrocarbon emplacement. Other authors, including Nunn and Sassen (1986)
and Kornacki et al. (1994), have reached similar conclusions about the
derivation of hydrocarbons in seeps. Because seeps appear to indicate
active migration from the source, they represent a positive indicator of
the potential effectiveness of the associated migration pathways. In contrast, if
hydrocarbons in seeps resulted from trap failure without active
recharge, then large seeps would likely be associated with under-filled
or dry structures.
Several lines of evidence support the
interpretation that pervasive seepage on the Gulf of Mexico Slope
results from active hydrocarbon generation and ongoing charge from the
source. First, the apparent volume of seeping hydrocarbons appears to
preclude the possibility that generation occurred in the past and that
hydrocarbons are currently leaking out of known or unidentified deep
reservoirs. For example, MacDonald et al. (1993) estimated that the
volume of hydrocarbons in surface slicks exceeds 120,000 barrels (bbl)
of oil per year. This estimate is conservative in that it includes only
oil from seeps large enough to create surface slicks that can be
identified using remote-sensing techniques. Lawrence and Anderson (1993)
estimated the ultimate potential of the deep-water Gulf of Mexico to be
between 8 billion and 10 billion bbl of oil equivalent (BBOE). Without
recharge, continuous seepage of 120,000 bbl of oil per year would
deplete this entire volume in less than 100,000 years. Second, large
seeps can occur on migration pathways with no known or inferred (from
seismic-amplitude anomalies) hydrocarbon accumulations at depth. Third,
Exxon has documented examples where the reservoired hydrocarbons in a
field are biodegraded, while seeps associated with the same migration
pathway contain fresh oil. The interpretation of ongoing generation is
interesting, given that seeps are abundant in areas where the source
intervals are currently buried to depths of 30,000 ft (9 km) or more
below mud line. Because it is an area of active generation and migration
of early-mature oils, the Gulf of Mexico Slope affords a rare
opportunity to calibrate maturation modeling methods.
Natural seeps contain varying mixtures
of oil, thermogenic natural gas, and biogenic gas. Because the gas
components are neither likely to be retained at the seafloor for an
extended period of time nor transported away from the migration pathway
and redistributed in sediments, we interpret an abundance of thermogenic
natural gas to indicate active migration at the specific site of the
dropcore. In contrast, modest amounts of oil imply hydrocarbon migration
in the general area of the dropcore. Seep compositions document that
both oils and natural gases are migrating simultaneously within
individual pathways. Because both products are available, the
hydrocarbon type contained within any particular trap (oil versus gas)
appears to be controlled by local factors of hydrocarbon charge or
retention in the reservoir. The composition of hydrocarbons in a seep
(oil versus gas), therefore, cannot generally be used to predict whether
a particular trap on the associated migration pathway will contain oil
or gas. Biogenic gas in seeps is identified by large components of
isotopically light (–60 to –80‰ d13C)
methane (e.g., Rice, 1993). Much of the biogenic methane associated with
seeps is probably formed at the seafloor by biodegradation of oil or
from indigenous organic matter in recent sediments. Consequently, the
presence of biogenic gas in a seep cannot be used as an indicator of the
likely products trapped at depth.
A small dropcore program was designed to
evaluate the use of seeps as direct indicators of the extent of a field
(Figure 8). A grid of 41 dropcores was extended from presumed
background, across the seismic-amplitude anomalies of a major discovery
on the eastern Gulf of Mexico Slope, and across the interpreted
migration pathway. Background MFI values were recorded in dropcores
represented along the right and upper parts of the figure. Substantially
higher MFI values were recorded near salt features and faults associated
with the likely cross-stratal migration conduit. Fluorescence intensity
generally decreases from right to left, away from cross-stratal
migration pathways. Anomalously high values over the field but away from
the principal cross-stratal migration conduit may suggest migration of
oil through seismically unresolvable pathways. However, the distribution
of MFI values across the grid in this example does not appear to closely
define the limits of the hydrocarbon accumulation as defined by the
seismic-amplitude anomaly.
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An understanding of source intervals,
coupled with the ability to image known and potential hydrocarbon
accumulations (from seismic-amplitude anomalies), facilitates the
evaluation of potential migration pathways within a basin. Most known
fields and discoveries in the offshore Gulf of Mexico require cross-stratal
migration to move hydrocarbons from known, deep source intervals to
young Tertiary reservoirs. The two most likely mechanisms for creating
cross-stratal conduits are salt movement and
faulting. To be effective, potential migration pathways must intersect
both the deep source intervals and the young reservoir levels. In some
areas, modern seismic data allow the entire inferred migration pathway
to be imaged. In cases where migration pathways extend to the seafloor,
sea- bottom hydrocarbon occurrences and surface slicks can be used to
document active migration.
In our study area,
migration pathways with the fewest segments (individual faults or
salt/sediment interfaces) and the greatest disruption between source and
reservoir levels appear to be the most effective. Consequently,
collapsed salt stocks appear to provide more effective migration
conduits than faults do, in areas where both features are present.
Vertical salt movement from the Middle Jurassic Louann Salt
(autochthonous salt) to allochthonous salt sills within the Tertiary
section rovides a strong disruption of the overlying sources and younger
strata. The disruption appears to be enhanced when the salt stock
pinches off from the mother salt, and the surrounding strata collapse as
the salt evacuates. Figure 9 illustrates several potential as well as
some unlikely migration pathways on the eastern Gulf of Mexico Slope.
Notice how the salt stock on the right part of the seismic line
penetrates all potential source intervals and provides a strong focus of
hydrocarbons into the cross-stratal conduit. Several seismic-amplitude
anomalies shallower in the section appear to connect to this pathway
extending below the shallow salt. The large fault on the lower left part
of the seismic line also cuts the potential source intervals, but the
dip of the source on the downthrown side of the fault appears to provide
less migration focus into the cross-stratal conduit in this 2-D view. A
somewhat smaller seismic-amplitude anomaly connects to the conduit
shallower in the section. Many other shallow faults on this part of the
line do not intersect the source intervals and thus would have limited
potential as effective migration conduits.
In many areas of the Gulf
of Mexico, the source intervals cannot be imaged on seismic sections,
making it difficult to evaluate the viability of potential migration
pathways. Fortunately, many of the
potential migration pathways reach the seafloor and can be evaluated for
direct evidence of hydrocarbon migration. Even so, the relationship
between seafloor hydrocarbon indicators and hydrocarbon accumulations at
depth is complex. Most large hydrocarbon accumulations on the Gulf of
Mexico Slope have large seeps at or near the intersection of the cross-stratal
migration conduit with the seafloor. However, some migration pathways
with large seeps at the seafloor do not have known or inferred
hydrocarbon accumulations at depth. Thus, a large seep at the seafloor
would be considered a positive indicator of hydrocarbon migration,
thereby reducing the risk for an associated seismic-amplitude anomaly,
but it would not be considered a definitive indicator of a hydrocarbon
accumulation.
Figure 10 illustrates the
interpreted migration pathway for a major discovery on the Gulf of
Mexico Slope. The interpreted collapsed salt stock is labeled
“salt-ascension zone” under the salt body. The collapsed salt stock
appears to be the main conduit connecting the uppermost Jurassic (Tithonian)
source interval to Miocene reservoirs. Figure 11 shows high-resolution,
shallow seismic data across a seafloor mound near the intersection of
the cross-stratal migration
conduit with the sea bottom . The seafloor mound is 200+ ft (60+ m) high
and more than 8000 ft (2500 m) wide. MFI values exceeding 2.5 million
indicate that the mound is a site of substantial oil and gas seepage.
The mound likely supports a chemosynthetic biological community that
lives off seeping oil and gas far below the photic zone. A wipeout zone
is present on the seismic line under the mound, probably the result of
large amounts of migrating gas. Oil collected in sea- bottom dropcores
from the intense seep over the migration pathway was geochemically
analyzed rior to drilling the discovery well. Geochemical
characteristics reflecting source depositional environment, facies, and
level of maturity, as interpreted from the seep nalysis, allowed
successful prediction of API gravity and sulfur content of the oil in
the reservoir prior to drilling the discovery well. This prediction was
especially significant because biomarker analysis of the seep suggested
that the oil would have a high sulfur content (2–3% S), whereas earlier
calculations had used the more highly valued “south Louisiana sweet”
bench-mark in economic models. Figure 12 shows a representative example
of oils eventually discovered at this prospect, compared with the seep
analysis. Oils in the stacked reservoirs were unbiodegraded, and most
had API gravities in the upper 20° range and sulfur contents from near
2% to almost 3%. Although the seep GC is heavily biodegraded, the
biomarkers in the seep are unaltered and are virtually identical to the
reservoired oil. This example illustrates the potential value of
geochemically characterizing seeps as a basis for predicting expected
hydrocarbon properties before drilling. Such information is valuable in
both prospect-specific and regional frontier contexts.
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An integrated-study approach to
understanding regional source distribution, hydrocarbon maturation
levels, and effective migration pathways in the deep-water Gulf of
Mexico has resulted in development of new play concepts and has helped
to improve Exxon’s exploration strategies.
Major offshore hydrocarbon systems are
derived from lower Tertiary (centered on Eocene), Upper Cretaceous
(centered on Turonian), and Upper Jurassic (centered on Tithonian)
source intervals. Regional variations in source facies result in
subfamilies within these hydrocarbon systems. Oxfordian
carbonate-sourced oils are common across the northern Gulf basin rim,
and lower-maturity hydrocarbons from this source are found in stains and
seeps in the deep central Gulf of Mexico.
Satellite-based tools for seep detection
have proved useful for screening large tracts of offshore acreage for
evidence of active hydrocarbon systems in a cost-effective manner.
Piston-core sampling of features imaged on the seafloor has provided
samples of oil that have been characterized geochemically. These samples
allow hydrocarbon-systems maps and prediction of hydrocarbon properties
to be extended far beyond well control.
Analysis of many sea- bottom sediments by
such high-resolution techniques as GC/MS and GC/MS/MS has allowed us to
place samples within a regional interpretive framework. This framework
has enabled us to understand complex signatures that included heavily
biodegraded petroleum compounds and the overprint of recent organic
matter. The regional framework has allowed estimation of likely
characteristics of reservoired oils over virtually the entire offshore
Gulf of Mexico.
Integration of seep data with
geophysical imaging of source rocks and potential migration pathways,
such as diapiric salt and major faults, has improved our understanding
of effective migration pathways. This understanding can be used to risk
the migration pathways associated with amplitude anomalies, which may
represent hydrocarbon accumulations, or any other trap. Potential
pathways that provide the greatest disruption and fewest segments
between source and reservoir levels (e.g., salt diapirs) appear to
provide the most effective migration conduits. The collection of
dropcores and analysis of seeps have been major contributors to our
current understanding of hydrocarbon migration on the Gulf of Mexico
Slope.
We thank Exxon Exploration Company (now
Exxon-Mobil) for permission to publish this paper. We would like to
acknowledge the contributions of many coworkers in the Gulf of Mexico,
and particularly Marilyn Smith for encouraging this publication. We also
thank Roger Sassen for many Gulf of Mexico discussions and for
permission to use selected analytical data from the Geochemical and
Environmental Research Group at Texas A & M University. The paper has
benefited from critical reviews by Jerry Atkinson, Flip Koch, Mark
Beeunas, Joe Curiale, and Kate Weissenburger.
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