Tertiary Source Rocks Research Articles

Source-dependent biomarker properties of five crude oils from the Gulf of Suez, Egypt

Five crude oils from some producing wells in the southern part of the Gulf of Suez were characterized using a variety of organic geochemical parameters. The results reveal significant differences within the oils from the Gulf of Suez basin that suggest two oil types and one mixed type. Type 1 oils from Ras Fanar and East-Zeit fields show a high relative abundance of gammacerane indicating a marine saline-source depositional environment. Another related feature of these oils is the predominance of C 35 over C 34 17α( H)-homohopanes. Type 2 oils from Gama and Amal-9 wells show oleanane indices over 20%, indicating that they originated from an angiosperm-rich, Tertiary source rock. Type 3 oil from Amal-10 well has geochemical characteristics intermediate between those of types 1 and 2. This may reflect mixing of oils from the sources of both types 1 and 2. The geochemical characteristics of the oils vary sufficiently to suggest multiple sources. The type 1 oils possess geochemical characteristics consistent with Upper Cretaceous Brown Limestone or Lower Eocene Thebes Formation carbonate source rocks. Type 2 oils are very similar in geochemical character to the Lower Miocene Rudeis Formation source rocks.

Diamondoid hydrocarbon ratios: novel maturity indices for highly mature crude oils

Diamondoid hydrocarbons have been identified in oil and source rock samples from the Tarim, Yinggehai, Qiongdongnan and other Chinese basins. Two diamondoid hydrocarbon ratios have been used as novel high-maturity indices to evaluate the maturation and evolution of crude oils and condensates in these Chinese basins. The two ratios, 1-MA/(1-MA + 2-MA) (%) (MAI = methyl adamantane index) and 4-MD/(1-MD + 3-MD + 4-MD) (%) (MDI = methyl diamantane index) were found to increase with increasing vitrinite reflectance. The initial values for the ratios are ca. 50 and 30%, respectively. Diamondoid hydrocarbons are products of rearrangement of polycyclic hydrocarbons and their ratios are found to be affected by organic input to a minor extent. Based on this study, crude oils from the Tarim Basin are generally believed to be very mature ( R o > 1.1%). The Cambrian-Ordovician source beds are the major source rocks of crude oils and natural gases in this basin. Condensates from the Tarim, Yinggehai and Qiongdongnan Basins have higher maturities, equivalent to R o values of 1.6–2.0%. Gases and condensates from the Yinggehai and Qiongdongnan basins are generated mainly from Tertiary source rocks below 4000–5000 m.

Geochemical Modelling of the Principal Source Rocks of the Barinas and Maracaibo Basins, Western Venezuela: ABSTRACT

This study presents a geochemical modelling of the principal source rocks in the western Venezuelan Basins. The area covers more than 100,000 km{sup 2}, and includes Lake Maracaibo and Barinas Basins. The geochemical modelling recognizes three source rocks: (1) A principal, K3-K4-K5 Cretaceous sequences, represented by La Luna, Capacho and Navay formations, (2) a secondary, corresponding to the T4 Oligocene sequence, represent by the Carbonera Formation, and (3) an accessory source rock, K7-K8 Paleocene sequences, represented by the carbonaceous shales and coals of the Orocue Group and Marcelina Formation. Three periods of hydrocarbon expulsion were defined for La Luna Formation (Early Eocene-Late Eocene, Middle Miocene-Early Miocene and Early Miocene-Holocene) and a principal period of hydrocarbon expulsion for Orocue Group and Carbonera Formation (Plio-Pleistocene and Middle Miocene Plio-Pleistocene). The 90% of hydrocarbons generated correspond to the principal source rock La Luna Formation, and the 10% to Tertiary source rocks (Carbonera Formation and Orocue Group). Five petroleum systems were identified: Lake Maracaibo, southwest of the Lake Maracaibo Basin, the Lara nappes, the extensive basins of eastern Zulia and the Barinas subbasin.

Geochemistry of oil seeps and rock samples of the Early Tertiary section from the Northandean Flank of the Venezuelan Andes

An organic geochemical study of oil seeps and Early to Middle Tertiary source rocks of the Northandean Flank (NAF) of the Venezuelan Andes range was performed to establish the possible contribution of terrestrial source rocks to the oil accumulations in the unexplored southern part of the Maracaibo Basin. Source rocks were identified within the Paleocene Barco and Los Cuervos Formations, and the Late Eocene-Oligocene Carbonera Formation. Biomarker distributions indicate a terrigenous organic source for these units. Geochemical modeling performed by Parnaud et al. (1995), indicated Plio-Pleistocene oil generation for the Orocué Group and Middle Miocene to Plio-Pleistocene oil generation for the Carbonera Formation. Geochemical modeling also indicates that the quantity of crude oil expelled by the Carbonera Formation is four times that expelled by the Orocué Group (Barco and Los Cuervos Formations). A northeast to southwest variation from marine to terrestrial oil seeps was identified based on sterane and terpane distributions. The marine oil seeps appear to be derived from the La Luna source rocks. The characteristics of the mixed oils suggest contributions from different sources (La Luna and a terrestrial source rock) most likely the Orocué Group or Carbonera Formation coals. Source facies similar to those in the Los Cuervos and Carbonera Formations coals are most likely the main source rocks of terrestrial oil seeps in the NAF.

Thermal and Petroleum-Generation History of the Mississippian Eleana Formation and Tertiary Source Rocks, Yucca Mountain Area, Southern Nye County, Nevada: ABSTRACT

Thermal and Petroleum-Generation History of the Mississippian Eleana Formation and Tertiary Source Rocks, Yucca Mountain Area, Southern Nye County, Nevada: ABSTRACT

Source Rocks, Thermal History and Oil in the Carson Sink and Buena Vista Valley, West Central Nevada: ABSTRACT

Rock-Eval, gas chromatography, mass spectrometry, and thermal history reconstruction data from six wells suggest that Tertiary rocks in the Carson Sink and Buena Vista Valley areas are marginally mature to overmature with respect to hydrocarbon generation and have locally expelled oil. The lacustrine Tertiary calcareous mudstones and marls in these wells have a total organic carbon (TOC) range from 0.1 to 3 wt.-%, with modes at about 0.5 to 0.7, 1.5, and 2 to 3 wt-% TOC. However, in the Standard Amoco Carson Sink 1 well, some of these samples have up to 3 wt-% less TOC than reported by Hastings (1979) and these are thought to represent drill cutting samples that have been depleted in more TOC rich rock chips. Even if the TOC data are biased, these TOC-depleted samples are still oil-prone rocks, with hydrogen indices commonly above 400 mg hydrocarbon/g C, and some samples with TOC in the 2-3 wt.-% range. Analysis of an oil show at Kyle Hot Springs in Buena Vista Valley revealed a wax-rich, low sulfur oil probably from a carbonate-rich, hypersaline lacustrine source rock. This oil could be generated from strata similar to those analyzed above. Other Tertiary source rocks in the twomore » valleys consist of lenses of humic coals that appear to be gas prone. Shows of biogenic(?) gas from shallow wells in Tertiary to Holocene lacustrine strata are common in the Carson Sink. Mesozoic rocks locally may have remaining hydrocarbon generation potential in the Stillwater Range which lie along the eastern margin of the Carson Sink. Published conodont alteration index data shows that the Paleozoic rocks are overmature. Reconstructed thermal histories of the Carson Sink and Buena Vista Valley areas, indicate petroleum is presently being generated. Mechanisms for petroleum generation are rapid burial (140 m/m.y.) in a high geothermal gradient (45 to 110{degrees}C/km), and hydrothermal and contact metamorphism.« less

The Molecular Fossil Record of Oleanane and Its Relation to Angiosperms

Oleanane has been reported in Upper Cretaceous and Tertiary source rocks and their related oils and has been suggested as a marker for flowering plants. Correspondence of oleanane concentrations relative to the ubiquitous microbial marker 17alpha-hopane with angiosperm diversification (Neocomian to Miocene) suggests that oleanane concentrations in migrated petroleum can be used to identify the maximum age of unknown or unavailable source rock. Rare occurrences of pre-Cretaceous oleanane suggest either that a separate lineage leads to the angiosperms well before the Early Cretaceous or that other plant groups have the rarely expressed ability to synthesize oleanane precursors.

Geopressure evolution, hydrocarbon generation and migration in the Beaufort-Mackenzie Basin, Canada: results from two-dimensional quantitative modelling

Three cross-sections of onshore and offshore areas of the Beaufort-MacKenzie Basin were used to simulate geopressure evolution, hydrocarbon generation and migration processes of the Tertiary section using a two-dimensional model. Two analytical approaches were used: (1) adjusting geological, geophysical and geochemical parameters to obtain the best fit between the model results and regional geological data in a one-dimensional manner; and (2) reconstructing the basin evolutionary history in a two-dimensional manner. The model results indicate that the present day distributions of geopressure and maturity levels at different locations have been modified by late Miocene uplift and erosion, followed by rapid deposition of the late Miocene-Pleistocene lperk sediments. Although the occurrence of oil and gas has no obvious relationship to geopressure at the present day, the evolution of geopressure in strata older than the Mackenzie sequence plays an important part in the maturation of Tertiary source rocks. Geopressure in these older formations caused an increase in thermal gradient and porosity in the deep formations. The analysis indicates that the timing of hydrocarbon generation and the evolution of geopressure are critical factors in the development of horizontal migration (Reindeer reservoirs) versus vertical migration (Kugmallit reservoirs).

Preliminary investigation of oil and source rock organic geochemistry from selected Tertiary basins of Thailand

Selected samples of crude oils and extracts from source rocks obtained from six Thailand Tertiary basins of the central plain and of the Gulf of Thailand regions were examined for geochemical properties and molecular compositions. Analyses were performed using GC, CGCMS and carbon isotope mass spectrometry. Though these results should be viewed as preliminary, the results are significant in terms of a regional understanding of the petroleum geochemistry of Thailand. Results from bulk geochemical properties and biomarker assemblages characterize derivatives of organic sources deposited in lacustrine environments. The organic matter is mainly derived from algae with varying amounts of higher plant material. However, an observed variation in the pristane/phytane ratios among the samples may imply differences in depositional oxicity. On the other hand, basinal differences in sedimentation rates, or in the oxygen concentration of the varying waters and/or sediment pore-waters resulted in spatial heterogeneities in the quantity and degree of preservation of the organic matter. In addition, a degree of physical separation between these paleo-lacustrine environments is indicated by differences in paleosalinity, e.g. the hypersaline biomarker, gammacerane, which is restricted to samples from the offshore Gulf of Thailand basins. Maturity parameters for these Tertiary oils and source rock extracts were determined using biomarker analyses of T s/T m, 22S/22S + 22R C 31 hopane, C 30 moretane/hopane, 20R/20S + 20R C 29 sterane, and aromatic compounds. Though the samples demonstrate an overall relatively low level of maturity as specified by the biomarker index, a degree of individual basinal variability is also distinguishable. The observed differences in the maturity values indicate regional heterogeneity among the basin thermal histories, suggesting differences in geothermal gradients and/or in the basin subsidence rates.

The distribution of aromatic hydrocarbons in source rocks from a well in the Qaudam Basin

The aromatic fractions in eleven samples from Tertiary source rocks from a well in the Qaidam Basin were analysed by GC-MS and ninety compounds were identified. These compounds are mainly naphthalene series, phenanthrene series and dibenzothiophene series, but chrysene, pyrene, fluorene, dibenzofuran, biphenyl, fluoranthene, benzonaphthothiophene, benzopyrene, benzofluoranthene and retene are also commonly found Some compounds change as regularly as the burial depth changes from 2800 to 4400 m, and these data can be used to determine the maturity level. The existence of retene may suggest a terrestrial plant input and the high content of dibenzothiophene can be related to a hypersaline environment.

A New Oil-Generation Model for Pine and Railroad Valleys, Nevada

The two oil-productive areas of Nevada, Pine Valley and Railroad Valley, show remarkably similar structural patterns and thermal histories. Both valleys are bounded on the east and below by a major low-angle west-dipping extensional fault into which steeper east- and west-dipping normal faults gather. In both valleys, the major fault bounds a brittly deformed upper plate which contains Devonian, Mississippian, and Tertiary source or reservoir rocks or both. Both lower plates contain Cretaceous( ) intrusive rocks. The authors propose that late Tertiary extension in both areas brought cool upper crustal rocks, including Paleozoic and Cenozoic sedimentary rocks that were immature with respect to hydrocarbon generation, into contact with hotter lower plate rocks that had been previously deeply buried - as deep as midcrustal levels in places along the eastern margin of Railroad Valley. They suggest that extension may have been sufficiently rapid that very high thermal gradients existed across the major low-angle extensional fault (structural detachment) in both areas. This model implies that Mesozoic to early Tertiary compressional deformation is not a major factor in contemporary oil occurrences in Nevada, and that late Tertiary extension and associated events probably destroyed any oils that may have been produced by earlier thermalmore » maturation. The model also implies that oil generation is still occurring in areas where hotter lower plate rocks are producing increased heating of source rocks in the upper plate that have remaining oil-generative capacity. This model is being tested by a variety of petrographic, geochemical, isotopic, and other paleogeothermal techniques.« less

Maturation sequence of Tertiary crude oils in the Qaidam Basin and its significance in petroleum resource assessment

This paper deals systematically with the geochemical analysis of 54 samples of Tertiary source rocks and crude oils in the western part of the Qaidam Basin. Taking the isomerization degree of C 29 sterane biomarker as the indicator of maturity, a complete evolution sequence of crude oils from immature, low mature, mature, to high mature stages corresponding to the transformation products of organic matters in different evolutional periods, has been found in the basin. It can be seen from the data presented that the widespread existence of immature petroleum and crude oil maturation sequences in the Tertiary terrestrial sedimentary basins in China is an important geochemical characteristic, a result which goes against the limitations imposed by the theory that hydrocarbons are formed from kerogens. This new concept has practical significance in petroleum exploration and petroleum resource evaluation by maturity grading. Our study shows that most of the oils discovered recently in the Qaidam Basin are low matured. However, the prospects for oil discoveries of other hydrocarbon-forming stages, particularly mature oils at greater depth, are bright.

Lower Tertiary and Upper Cretaceous Source Rocks in Louisiana and Mississippi: Implications to Gulf of Mexico Crude Oil (1)

The Lower Tertiary Sparta Formation, Wilcox Group, and the Midway Group in southern Louisiana include organic-rich source facies that generate crude oil at relatively high thermal maturities. The Wilcox Group is an important source of Wilcox crude oil, and regional kerogen variations explain two crude oil subfamilies. Wilcox crude oils in downdip areas of southern Louisiana migrated short distances, but long-range lateral migration (about 150 km) best explains Wilcox crude oils far updip from mature source rocks. Crude oils in Oligocene and younger reservoirs in southern Louisiana migrated vertically from deep lower Tertiary source rocks. Some crude oils in Upper Cretaceous Tuscaloosa reservoirs were emplaced by long-range lateral migration from Tuscaloosa source rocks. G ven little evidence of upper Tertiary source rocks and the overmaturity problems of Mesozoic source rocks, most crude oils in upper Tertiary and Pleistocene reservoirs of the Gulf continental shelf are best explained by vertical migration from deep lower Tertiary source rocks. Even so, it is simplistic to assume an exclusive lower Tertiary origin. Many Tertiary and Pleistocene crude oils of this study probably include an overprint of high-maturity hydrocarbons from Mesozoic sources.

Geochemistry and Habitat of the Oils in Italy (1)

All varieties of liquid petroleum, ranging from condensates (>50 degrees API) to immature sulfur-rich heavy oils (as low as 5 degrees API), have been found in Italy. However, nonbiodegraded heavy oils account for about 70 percent of the total original oil in place. Geochemical analyses indicate that 11 oil groups are present in the Italian basins and two main types of source rocks have been identified: Triassic carbonates and Tertiary shales. About 95 percent of the oils were originated from Middle and Upper Triassic carbonates containing type II kerogen [about 1 percent 4total organic carbon (TOC) and 500 mg hydrocarbon/g TOC]. Only a relatively minor amount of oil was generated by Tertiary shales containing type III kerogen with TOC generally less than 1 percent. Timing of generation and migration and bulk properties of oils were controlled by geodynamic histories of the three main Italian geologic settings: (1) Apennine and Southern Alp thrust belts, (2) foredeep (depression bordering the thrust belts), and (3) foreland (nondeformed African continental margin). Within the Apennine thrust belts, deep burial during the Neogene resulted in the generation of substantially lighter oils, not only from deeply buried Triassic but sometimes also from Tertiary source rocks. In the late Neogene, foredeep depocenters located in the central Adriatic and southern Sicily, high subsidence (up to 1000 m/m.y.), a low geothermal gradient (22 degrees C/km), and compressional tectonics caused the generation of immature heavy oils generally at depths below 5000 m nd temperatures greater than 100 degrees C. Rapid burial and higher geothermal gradients (32 degrees C/km), which occurred since the Jurassic, resulted in the generation of light oils from the Late Cretaceous to the Oligocene in the southern sector of Adriatic foreland.

STRUCTURE AND HYDROCARBON POTENTIAL OF THE TARIM BASIN (NW CHINA) FROM SATELLITE IMAGERY

The Tarim Basin, NW China, whose total area is 560,000 sq. kms, is one of the largest inland basins in the world, with sediments around 15,000 m thick. The Tarim Block is a small continental plate, which is being over‐ridden at its western end from both the north and south, by the Eurasian and Indian continents, respectively. Abundant oil and gas accumulations are predicted to occur within the basin.Detailed analysis of Landsat imagery, integrated with published geological and geophysical data, has provided the basis for a re‐examination of the structural geology of the area, and has enabled a new interpretation of the tectonic development of the northern part of the Tarim Basin to be made.The region discussed in this paper is the northern margin of the Tarim Basin, including the Kalpin Uplift (Kalpintag), North Tarim Depression and Kuruktag Uplift. Remarkable geological structures outcrop in these areas, and are clearly visible on satellite imagery.The NW and SW margins of the Tarim Basin are dominated by compression; while the NE and SE margins are dominated by left‐lateral strike‐slip movements. South of the Kalpintag, west‐directed thrusting occurs in Palaeozoic platform sediments, which may have some production potential where they are buried beneath Neogene sediments.On the NW basin margin; where thrusting is predominant, crustal shortening is estimated to be around 50%. In the Kuqa Depression (the northern sector of the North Tarim Depression), Tertiary evaporites seal Mesozoic source rocks. The configuration above the décollement is discordant, and the spectacular Tertiary surface structures are not very prospective.The Kuruktag (at the NE corner of the Tarim Basin) is an area of compressional grabens which may contain both Mesozoic and Tertiary source rocks. These grabens are potential analogues of basins in southern California.Important structural features interpreted here include several major thrust complexes, and strike‐slip fault systems. In addition to detecting fault traces, a number of important fold structures were mapped and analysed using the imagery, and the resulting maps represent an improvement on existing publications. Tectonic features, particularly folds and faults near the basin margin, may provide traps for hydrocarbon accumulations.As a result of this study, many potential hydrocarbon traps, which merit close attention by geophysical field‐survey techniques such as seismic reflection, have been defined.

中国南海，珠江口堆積盆地の第三系陸成根源岩について

中国南海，珠江口堆積盆地の第三系陸成根源岩について

Geochemistry of carbonate source rocks and crude oils in Jurassic salt basins of the Gulf Coast

Abstract The lower member of the Jurassic Smackover Formation is a source rock for crude oil across the northern Gulf Rim from east Texas to Florida. Type-I crude oils occur in Smackover reservoirs of east Texas, north Louisiana, south Arkansas, and Mississippi, and were generated by algal-derived kerogen preserved in an anoxic environment. Type-II crude oils in Smackover reservoirs of Alabama and Florida reflect an origin from kerogen with a terrestrial component preserved in a less anoxic environment. Thermal maturity differences across the Gulf Rim caused generation and destruction of crude oil to occur at much shallower depths in east Texas, north Louisiana, and south Arkansas than in Mississippi, Alabama and Florida. Jurassic through Cretaceous timing of migration and faulting permitted vertical migration of Type-I Smackover crude oils to many Upper Jurassic, Lower Cretaceous and Upper Cretaceous reservoirs along the Gulf Rim. Vertical migration of Type-II crude oils was less significant, especially in Alabama, because of evaporite barriers to migration. The high contents of hydrogen sulphide and carbon dioxide in deep, hot Smackover reservoirs are related to thermochemical sulphate reduction that has driven early destruction of methane. Compositionally distinct crude oils from Upper Cretaceous and Lower Tertiary siliciclastic source rocks are found in reservoirs south of the Gulf Rim.

Generation and migration of oil in the Maturin Subbasin, Eastern Venezuelan basin

Regional geochemical evaluation of the possible Cretaceous and Tertiary source rocks and oil-oil and oil-source rock correlation studies, have identified the calcareous shales and limestones of the Upper Cretaceous, Querecual and San Antonio Formations of the Guayuta Group, with amorphous marine type II organic matter, as the source rocks for oil in the Maturin Subbasin. The deposition of the source rocks took place on a passive continental margin whilst the generation and migration of oil occurred in a foreland basin during Miocene-Recent times. The oils found in the northern part of the subbasin in different reservoirs (Cretaceous, Eocene, Oligocene, Miocene and Pliocene formations) are of mature, marine type with or without bacterial alteration. Geochemical data indicate that some of these oils were mixed with the highly altered residue of a previously accumulated oil. Based on maturity and migration modelling, it appears that the oils essentially migrated from active, Upper Miocene-Recent, kitchens in the Cretaceous source rocks below the main thrusts. The highly altered residue was formed during the Upper Miocene by the biodegradation of oil migrating during the Middle and Upper Miocene. Large areas of mature to overmature Cretaceous source rocks (now exposed in the Interior Mountain Front) were in active oil kitchens during the Lower and Middle Miocene before being involved in thrusting around 12 Myr BP. Long distance (150–300 km) southward lateral migration of oils during the Middle Miocene gave rise to the altered moderately mature marine oils in the shallow Miocene stratigraphic reservoirs of Cerro Negro (Orinoco Oil Belt) in the southern fringe of the subbasin.

Origin of Crude Oil in Eastern Gulf Coast: Upper Jurassic, Upper Cretaceous, and Lower Tertiary Source Rocks: ABSTRACT

Analysis of rock and crude oil samples suggests that three source rocks have given rise to most crude oil in reservoirs of the eastern Gulf Coast. Carbonate source rocks of the Jurassic Smackover Formation are characterized by algal-derived kerogen preserved in an anoxic and hypersaline environment, resulting in crude oils with distinct compositions. Migration commenced during the Cretaceous, explaining the emplacement of Smackover-derived crude oil in Jurassic and in some Cretaceous reservoirs. Upper Cretaceous clastic and carbonate source rocks are also present. Much crude oil in Upper Cretaceous reservoirs has been derived from organic-rich marine shales of the Tuscaloosa Formation. These shales are characterized by algal and higher plant kerogen, resulting in distinct crude oil compositions. Migration commenced during the Tertiary, but was mostly focused to Upper Cretaceous reservoirs. Lower Tertiary shales, including those of the Wilcox Formation, are quite organic-rich and include downdip marine facies characterized by both algal and higher plant kerogen. Crude oils in lower Tertiary reservoirs are dissimilar to crude oils from deeper and older source rocks. Migration from lower Tertiary shales commenced during the late Tertiary and charged Tertiary reservoirs. Although most crude oil in the eastern Gulf Coast has been emplaced by short-range migration,more » often with a strong vertical component, some long-range lateral migration (> 100 km) has occurred along lower Tertiary sands. The framework of crude oil generation and migration onshore has important implications with respect to origin of crude oil in the Gulf of Mexico.« less

Significance of Anoxic Slope Basins to Occurrence of Hydrocarbons Along Flexure Trend, Gulf of Mexico: A Reappraisal: ABSTRACT

Recently, Tertiary anoxic slope basins have been proposed as the sources for much of the oil occurring along the Flexure Trend in the Gulf of Mexico. The intraslope basins are thought to have been formed in response to salt diapirism and concomitant salt withdrawal resulting from differential sediment loading between the basins and the diapirs, as well as due to associated faulting. Of the modern intraslope basins, the black, organic-rich muds accumulating in the Orca basin have especially attracted and are suggested to be modern analogs to late Tertiary source rocks accumulated and buried across the continental slope. Although the organic carbon content of the anoxic sediments in the Orca basin is generally high (2 to 3%), the concentration of preserved oil-generative organic matter in these sediments is low. Rock-Eval P2 yields are usually in the range of 340 to 1620 ppm, and hydrogen indices are generally less than 100. Pyrolysis-GC and 13C-NMR data show that up to 30 + % of the organic carbon is contained in carboxyl and other oxygenated groups, which are lost during diagenesis and early catagenesis of the sediments, and that much of the remainder is aromatized and degraded. The degradation was probably by oxidationmore » during settling through the oxic water column. The geochemical data indicate, therefore, that the bulk of the organic carbon in the Orca basin is not capable of forming oil during catagenesis. Published regional cross sections across the Texas-Louisiana continental margin commonly show a thick (0.5-4 km), continuous salt sequence, sourcing salt diapirs and ridges, to underlie the Oligocene(.)/Miocene to Pleistocene sedimentary section of the outer continental shelf and slope.« less