Click to view article in PDF format.
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
|
Click here for sequence of Figure 2 (hydrocarbon-systems map) and Figure 4 (seep-distribution map).
Table CaptionINTRODUCTIONContinued 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
APPROACH AND GEOLOGIC FRAMEWORK
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
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 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
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 SEEPS
The Gulf of Mexico Slope
contains widespread areas of oil and gas seepage (Figure 4) that have
allowed investigators to extend hydrocarbon-system
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
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
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 MIGRATION PATHWAY EVALUATION
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
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
In many areas of the Gulf
of Mexico, the source intervals cannot be imaged on seismic
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 CONCLUSIONSAn 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
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.
ACKNOWLEDGMENTSWe 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. REFERENCES CITEDBrooks, J. M., M. C. Kennicutt, and B. D. Carey, 1986, Offshore surface geochemical exploration: Oil & Gas Journal, v. 84, no. 42, p. 66–72. Brooks, J. M., M. C. Kennicutt, L. A. Barnard, G. J. Denoux, and B. D. Carey, 1983, Application of total scanning fluorescence to exploration geochemistry: Proceedings of the 15th Offshore Technology Conference, Houston, Texas, v. 3, p. 393–400. Connan, J., 1984, Biodegradation of crude oils in reservoirs, in J. Brooks and D. Welte, eds., Advances in Petroleum Geochemistry, v. 1: Academic Press (London) Ltd., p. 299–335. González-García, R., and N. Holguin-Quiñones, 1992, Geology of the source rocks of Mexico: Proceedings of the 13th World Petroleum Congress, v. 2, p. 95–104. Gross, O. P., K. C. Hood, L. M. Wenger, and S. C. Harrison, 1995, Seismic imaging and analysis of source and migration within an integrated hydrocarbon system study: Northern Gulf of Mexico Basin, in First Latin American Geophysical Conference, Rio de Janeiro, 4 p. Haq, B. U., J. Hardenbol, and P. R. Vail, 1988, Mesozoic and Cenozoic chronostratigraphy and cycles of sea-level change, in C. K. Wilgus et al., eds., Sea-level changes: An integrated approach: SEPM Special Publication no. 42, p. 71–108. James, A. T., L. M. Wenger, M. B. Melia, A. H. Ross, and C. P. Kuminez, 1993, Recognition of a new hydrocarbon play in a mature exploration area through integration of geochemical, palynologic, geologic, and seismic interpretations (onshore northern Gulf of Mexico): Program with Abstracts, 1993 AAPG Annual Meeting, New Orleans, Louisiana, U.S.A., p. 123. Kornacki, A. S., J. W. Kendrick, and J. L. Berry, 1994, Impact of oil and gas vents and slicks on petroleum exploration in the deep water Gulf of Mexico: Geo-Marine Letters, v. 14, no. 2/3, p. 160–169. Lawrence, D. T., and R. N. Anderson, 1993, Details confirm Gulf of Mexico deepwater as significant province: Oil & Gas Journal, v. 91, p. 93–95. MacDonald. I. R., J. F. Reilly Jr., S. E. Best, R. Venkataramaiah, R. Sassen, N.L. Guinasso, and J. F. Amos, 1996, Remote sensing inventory of active oil seeps and chemosynthetic communities in the northern Gulf of Mexico, in D. Schumacher and M. A. Abrams, eds., Hydrocarbon migration and its near-surface expression: AAPG Memoir 66, p. 27–37. MacDonald, I. R., N. L. Guinasso, S. G. Ackleson, J. F. Amos, R. Duckworth, R. Sassen, and J. M. Brooks, 1993, Natural oil slicks in the Gulf of Mexico visible from space: Journal of Geophysical Research, v. 98, p. 351–364. MacGregor, D. S., 1993, A new look at an old tool: The exploration significance of surface seeps: AAPG Bulletin, v. 77, p. 1644. McDade, E. C., R. Sassen, L. M. Wenger, and G. A. Cole, 1993, Identification of organic-rich Lower Tertiary shales as petroleum source rocks, south Louisiana: Gulf Coast Association of Geological Societies Transactions, v. 43, p. 257–267. Nunn, J. A., and R. Sassen, 1986, The framework of hydrocarbon generation and migration, Gulf of Mexico Slope: Gulf Coast Association of Geological Societies Transactions, v. 36, p. 257–262. Oehler, J. H, 1984, Carbonate source rocks in the Jurassic Smackover trend of Mississippi, Alabama, and Florida, in J. G. Palacas, ed., Petroleum geochemistry and source rock potential of carbonate rocks: AAPG Studies in Geology no. 18, p. 63–69. Peters, K. E., and J. M. Moldowan, 1993, The biomarker guide: Englewood Cliffs, New Jersey, Prentice-Hall, 363 p. Rice, D. D, 1993, Biogenic gas: Controls, habitats, and resource potential: USGS Professional Paper 1570, p. 58–606. Schumacher, D., and R. M. Parker, 1990, Possible pre-Jurassic origin for some Jurassic-reservoired oil, Cass Co., Texas, in D. Schumacher and B.F. Perkins, eds., Gulf Coast oils and gases—Their characteristics, origin, distribution, and exploration and production significance: Gulf Coast Section SEPM Foundation Ninth Research Conference, p. 59–68. Thompson, K. F. M., M. C. Kennicutt II, and J. M. Brooks, 1990, Classification of offshore Gulf of Mexico oils and gas condensates: AAPG Bulletin, v. 74, p. 187–198. Wagner, B. E., Z. Sofer, and B. L. Claxton, 1994, Source rock in the Lower Tertiary and Cretaceous, deep-water Gulf of Mexico: Gulf Coast Association of Geological Societies Transactions, v. 44, p. 729–736. Wenger, L. M., L. R. Goodoff, O. P. Gross, S. C. Harrison, and K. C. Hood, 1994, Northern Gulf of Mexico: An integrated approach to source, maturation, and migration, in N. Scheidermann, P. Cruz, and R. Sanchez, eds., Geologic aspects of petroleum systems: First Joint AAPG-AMGP Hedberg Research Conference, 5 p. Wenger, L. M., R. Sassen, and D. Schumacher, 1990, Molecular characteristics of Smackover, Tuscaloosa and Wilcox reservoired oils in the eastern Gulf Coast, in D. Schumacher, ed., Geochemistry of Gulf Coast oils and gases: Gulf Coast Section SEPM Foundation Ninth Research Conference, p. 37–57. |