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Hydrocarbon Systems Analysis of the Northern Gulf of Mexico: Delineation of
Hydrocarbon
Migration
Pathways Using Seeps and Seismic Imaging*
By
Kenneth C. Hood1, L. M. Wenger2, O. P. Gross3, S.C. Harrison4
Search and Discovery Article #40061 (2002)
* *Adapted for online presentation from article of the same title by the same authors published in AAPG Studies in Geology 48 and SEG Geophysical References Series No. 11, Surface Exploration case Histories: Applications of Geochemistry, Magnetics, and Remote Sensing, D. Schumacher and LA. LeSchack, eds.,p. 25-40. This publication may be purchased from AAPG Bookstore (http://bookstore.aapg.org). Authors performed research and prepared manuscript while employed by Exxon Exploration Company, Houston, Texas, U.S.A.
1-4 Current addresses: 1ExxonMobil Exploration Company, Houston, Texas, U.S.A.; 2ExxonMobil Upstream Research Company, Houston, Texas, U.S.A.; 3Esso Production Malaysia Inc., Kuala Lumpur, Malaysia; 4Consultant, Houston, Texas, U.S.A.
Widespread oil and gas seepage in
the offshore U.S. Gulf of Mexico has allowed the extension of hydrocarbon
systems and maturity maps far beyond well control. Analysis of sea-bottom
dropcores and imaging of sea-surface slicks have complemented Exxon’s
integrated, multidisciplinary study of sources, maturation, and migration
pathways. Our approach involved development of a regional geologic framework
through interpretation of 2-D and 3-D seismic data, identification and mapping
of potential source intervals, and delineation of likely
migration
pathways to
reservoirs and seismic-amplitude anomalies. Hydrocarbon compositions from more
than 2000 reservoired oils, 600 reservoired natural gases, and 3000
hydrocarbon-bearing, sea-bottom dropcores help constrain such source-rock
characteristics as organic-matter type, depositional facies, level of maturation
and, to some extent, age. East of the Mississippi River Delta, the complete
stratigraphic section is visible on seismic sections, and wells have penetrated
deep source intervals. To the west, correlative organic-rich rocks have been
sampled onshore and from sheaths overlying salt diapirs offshore. Integration of
these data into a regional geologic framework provides a strong basis for
hyrocarbon-systems interpretations.
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. All Eocene oil types (marine, intermediate, and terrestrial) have been tied to source rocks and are consistent with paleofacies distributions for the Eocene deltaic systems. Eocene oils and gases are prevalent on the Texas and Louisiana shelves and extend both onshore and onto the Texas Slope. Turonian oils have been tied to source rocks offshore (east of the Mississippi River Delta) and onshore (e.g., Tuscaloosa and Giddings trends). Based on seismic-image thinning of the interval and disappearance of diagnostic oils, we interpret a basinward loss of this source type. Elevated-sulfur oils and associated (cogenerated) gases on the upper Gulf of Mexico Slope are interpreted to have originated from a Tithonian source. High-maturity, organic-rich calcareous shales of this age have been penetrated in the eastern Gulf of Mexico, and Tithonian oils occur in Cretaceous reservoirs on the Florida Shelf where the Upper Cretaceous and Tertiary sections are immature. Oxfordian carbonate-sourced oils are common across the northern Gulf basin’s rim, and lower-maturity hydrocarbons from this source occur in stains and seeps in the deep central Gulf of Mexico.
Refinements in our understanding of Gulf of Mexico hydrocarbon systems have resulted
from this study. They have helped us to improve our exploration methodologies and have provided us with new play concepts
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(hydrocarbon-systems
Table CaptionINTRODUCTION
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
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
APPROACH AND GEOLOGIC FRAMEWORKThe 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 GULF OF MEXICO HYDROCARBON SYSTEMSKnowledge 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. REMOTE SENSING OF SEA-SURFACE SLICKSRemote-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 SEEPSThe 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
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
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
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
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