Oil-source Rock Correlation Studies Research Articles

Stable Isotope Geochemistry of the Organic Elements within Shales and Crude Oils: A Comprehensive Review.

Over time, stable isotopes have proven to be a useful tool in petroleum geochemistry. However, there is currently insufficient literature on stable isotope geochemistry of the organic elements within shales and crude oils in many petroleum systems around the world. As a result, this paper critically reviews the early and recent trends in stable isotope geochemistry of organic elements in shales and crude oils. The bulk and compound-specific stable isotopes of H, C, and S, as well as their uses as source facies, depositional environments, thermal maturity, geological age, and oil–oil and oil–source rock correlation studies, are all taken into account. The applications of the stable isotopes of H and C in gas exploration are also discussed. Then, the experimental and instrumental approaches to the stable isotopes of H, C, and S, are discussed.

Degradation-resistant biomarkers in the Pirambóia Formation tar sands (Triassic) and their correlation with organic facies of the Irati Formation source rocks (Permian), Paraná Basin (Brazil)

The Pirambóia Formation tar sands constitute one remarkable occurrence of heavy oil in the eastern border of the Paraná Basin, São Paulo State, Brazil, being characterized as highly degraded oils related to the Irati-Pirambóia oil system. In this context, the aim of the present work was to investigate biomarkers that are more resistant to degradation and use them to establish a more reliable geochemical correlation between the tar sand oils of the Pirambóia Formation (collected from the Fazenda Betumita and Guareí I outcrops) and the organic extracts of black shales of the Irati Formation (facies Irati A and B, collected in the Amaral Machado Quarry, São Paulo State). For this purpose, analysis of stable carbon isotopes and diagnostic ratios of saturated and aromatic biomarkers were investigated, and the most reliable diagnostic ratios were selected based on the principal component statistical analysis. The results pointed to different degradation extent between the tar sand outcrops, being higher for the Guareí I samples. In this scenario, it was verified that most of the diagnostic ratios commonly used in oil-source rock correlation studies were susceptible to degradation processes. It was also observed that samples from Pirambóia and Irati formations are at the beginning of the oil generation window, with the C29 ββ/(αα + ββ) ratio as the most suitable to assess thermal maturity of extremely degraded oils. The multivariate statistical analysis of the results, based on ten more resistant diagnostic ratios, allowed to select six main variables responsible for the similarity between the samples from the Irati and Pirambóia formations: δ13C (‰), TPP ratio (C30 tetracyclic polyprenoids over diasteranes), %C28 and %C29 monoaromatic steranes, (C20 + C21)/(C23 + C24) tricyclic terpanes, and C23 tricyclic terpane/(C23 tricyclic terpane + C29 hopane). These geochemical parameters showed greater reliability in the correlation between the Pirambóia Formation tar sand oils and the Irati samples of the facies A, deposited in a restricted marine environment under anoxic-euxinic conditions.

Tracing the origin of petroleum using asphaltene carbon isotope ratios: Case study from the Songliao Basin, NE China

Type I and II kerogens, isolated from outcrop shales in the Songliao Basin, were performed a programed sealed-heating kinetic process. Both carbon isotope values of pyrolysis-residual kerogens and those of asphaltene extractions present gradual enrichments dependence on increasing Easy %Ro and biomarker maturity ratios. The carbon isotope (δ13C) values are used for the first time to analyze a close relationship between these kerogens and asphaltenes at the same level of thermal maturation, and identification oil–source rock correlation studies in theory. Such validity of the model was further tested by δ13C of asphaltenes and biomarker ratios in crude oils.

Oil-source rock correlation studies in the unconventional Upper Cretaceous Tuscaloosa marine shale (TMS) petroleum system, Mississippi and Louisiana, USA

The U.S. Geological Survey assessed undiscovered unconventional hydrocarbon resources reservoired in the Upper Cretaceous Tuscaloosa marine shale (TMS) of southern Mississippi and adjacent Louisiana in 2018. As part of the assessment, oil-source rock correlations were examined in the TMS play area where operators produce light (38–45° API), sweet oil from horizontal, hydraulically-fractured wells in an overpressured ‘high-resistivity’ (>5 Ω-m) zone at the base of the TMS. Geochemical data from 39 oil samples and 17 source rock solvent extracts collected from the TMS play area indicate close correspondence for Tuscaloosa Group oils [from lower Tuscaloosa, middle Tuscaloosa (the TMS) and upper Tuscaloosa reservoirs] in thermal maturity (computed from MPI), SARA proportions, n-alkane distributions, isoprenoid and DBT/P ratios, monoaromatic steroids, and δ13C isotopic compositions (from whole oils, saturate and aromatic fractions). Other parameters (normal steranes, extended homohopanes, C31R/C30 hopane, norhopane/hopane and tricyclic terpane ratios, gammacerane/hopane) show most oil samples have similar values, suggesting all Tuscaloosa Group oils are from a common mixed marine-terrigenous source rock. Tighter distributions for triaromatic steroid (TAS) and δ13C isotopic composition for conventional oils in lower and upper Tuscaloosa reservoirs may indicate charge occurred in a single or shorter pulse relative to TMS oils which show broader TAS and δ13C properties, possibly from their generation over an extended period of burial maturation. Dissimilarity in geochemical properties between lower Tuscaloosa source rock solvent extracts and Tuscaloosa Group oils indicates lower Tuscaloosa source rocks did not contribute significantly to conventional and unconventional Tuscaloosa Group hydrocarbon accumulations. Whereas, TMS solvent extracts are similar to Tuscaloosa Group oils, suggesting an oil-source rock correlation. Excluding the possibility for long-distance lateral migration from a similar source downdip (which is unnecessary given thermal maturity considerations), the observations indicate 1. the TMS is a self-sourced reservoir, 2. the TMS is the source of oils accumulated in nearby conventional Tuscaloosa Group reservoirs, and 3. thin organic-rich shales in the lower Tuscaloosa did not contribute substantially to any oil accumulations in the Tuscaloosa Group.

Geochemical characterization of the Upper Mississippian Goddard Formation, Noble Ranch Group, and related oils in the Anadarko Basin of Oklahoma

The Woodford Shale is anecdotally assumed to be the major source of oil for plays in the Anadarko Basin, including the stacked oil and condensate play in the southcentral Oklahoma oil province (SCOOP). However, there is little published geochemical work to confirm this assumption. This study set out to identify a characteristic geochemical fingerprint for the Goddard Formation, another potential source rock in the SCOOP, to determine if the Goddard is contributing to oil accumulations within the SCOOP. The Upper Mississippian Goddard Formation has been a target for unconventional production in SCOOP since 2012. Published geochemical interpretations for the Goddard Formation are still limited, and this study represents the first detailed oil–source rock correlation for the Goddard in the SCOOP area. The most characteristic geochemical signature of the Goddard extracts is a predominance of tricyclic terpanes relative to the hopanes in the mass-to-charge ratio 191 chromatogram, possibly related to enrichment via thermal stress or a unique source signature. Additional distinctive signatures were also identified for the triaromatic steroid hydrocarbons, sesquiterpenoids, and steranes. The biomarker fingerprints of SCOOP oils are nearly identical with those of the Goddard extracts in this study. Oils in the SCOOP, therefore, appear to originate from a Mississippian source, such as the Goddard rather than the Woodford. This observation demonstrates the value of oil–source rock correlation studies and suggests that there may be effective source rocks in the Anadarko Basin that have been overlooked in the past and should be re-evaluated in detail.

Chemometric Differentiation of Oil Families and Their Potential Source Rocks in the Gulf of Suez

An oil–oil and oil–source rock correlation study was carried out using chemometric methods applied to geochemical data for 123 Upper Cretaceous—Lower Miocene putative source rock and 46 crude oil samples from the Gulf of Suez Rift basin. The Gulf of Suez has many organic-rich intervals. The pre-rift source units, such as the Brown Limestone and Thebes formations, contain very good-to-excellent organic content, whereas the Miocene rocks are rated fair to good. HI and Tmax pyrolysis data indicate variable kerogen type and maturation histories where most of the analyzed samples occur along the Type II and Type II/III kerogen pathways from immature to the main stage of oil window with %Ro < 0.9. Carbon isotope ratios’ biomarker data for the bitumen samples indicate predominantly anoxic source rock depositional conditions with substantial algal/bacterial marine and a minor terrigenous organic matter. The Gulf of Suez oils exhibit a wide range of chemical composition from heavy-to-medium gravity and moderate-to-high sulfur content. These oils originated from carbonate/marl source rocks rich in lipids from phytoplankton/benthic algae and bacteria with less contribution of terrigenous organic debris, deposited under anoxic conditions with different thermal maturity histories equivalent to at least the early oil window. Chemometrics using 16 source-related biomarker and isotope ratios identifies six genetic families in the Gulf of Suez. The oil families share common characteristics where the precursor organic matter was deposited in a restricted marine environment with limited land-derived organic matter. The major factor that greatly modifies oil composition in the Gulf of Suez is thermal maturation. However, migration history and spatial and temporal organofacies’ variations of the presumed source rocks are also important. The overall geochemical similarity of the Gulf of Suez oils confirms the mixed nature of these fluids and suggests that no single source rock horizon is likely to have sourced the oil in this promising province. Based on oil–source correlation data and a decision tree chemometric model, the Brown Limestone, Esna, Thebes, and Nukhul formations are the effective source rocks for oil families III, IV, and V, whereas none of the source rock extracts has been assigned for Family I or VI oils.

Origin and geochemical implication of relatively high abundance of 17α (H)-diahopane in Yabulai basin, northwest China

Abstract Relatively high abundance of 17α (H)-diahopane has been detected in source rock extracts in the Yabulai Basin, a lacustrine basin in northwest China. Gas chromatography-mass spectrometry (GC-MS), X-ray diffraction (XRD) and Field emission environment scanning electron microscope imaging (FE-ESEM) were used in combination with conventional geochemical parameters to unravel the enrichment mechanisms. Significant variations of 17α (H)-diahopane concentrations detected in the Xinhe Formation with similar maturity inferred that thermal evolution is not the unique factor inducing the compound generating. The sedimentation of samples rich in 17α (H)-diahopane usually occur under suboxic conditions. Results of mineralogy analysis suggested that samples with high content of 17α (H)-diahopane are rich in carbonate minerals (about 20 wt %), which might deposit in brackish-saline water depositional environment. Relatively high content of gammacerane is also consistent with the experimental results of XRD. Based on the viewpoint of Moldowan et al. (1991), the regular hopanes may be the precursor of the rearranged hopanes, with the Wagner-Meerwein rearrangement as the mechanism. In this reaction, the critical factor of methyl migration is the production of carbocation starting with dehydroxylation. We suggested a general scheme for the generation of 17α (H)-diahopane in this study. In lacustrine sediments, suboxic and brackish environment could catalyze the methyl migration accompanied by carbonate deposit. Its geochemical implication can be used to reconstruct lacustrine paleoenvironment and contribute to a better understanding on oil-oil correlation, oil-source rock correlation and petroleum system study.

Biomarker geochemistry of crude oils and Lower Paleozoic source rocks in the Tarim Basin, western China: An oil-source rock correlation study

Abstract In order to select biomarker parameters that have potential to quantitatively distinguish between the Cambrian–Lower Ordovician and Upper Ordovician source rocks in the Tarim Basin with a total organic carbon content >0.5%, 42 Lower Paleozoic shale samples, were collected from a number of wells and outcrops in the Tarim Basin, northwestern China. The biomarkers in the extracts of the source rocks were analyzed by gas chromatography–mass spectrometry. The results show that C23 and C30 were dominant in the tricyclic terpanes and pentacyclic triterpanes, respectively, and C27 and C29 were both dominant in C27–29 steranes of the source rock samples. The distribution of n-alkanes, isoprenoids and terpanes indicate that the source rock samples have been slightly to moderately biodegraded, and they originated from a reducing depositional environment with considerable marine algal input in. Comparatively, Upper Ordovician source rock samples presented lower values of C28/C29 regular steranes and higher values of C29 ααα20S/(20S + 20R) and C29αββ/(αββ+ααα). Abnormally lower values of C29 ααα20S/(20S + 20R) and C29αββ/(αββ+ααα) were observed in the Cambrian–Lower Ordovician strata. The set of data in this study show that homohopane index including C31homohopane/C30hopane, C31-35homohopanes/C30hopane, and the ratios related to the triaromatic steroids including C26−20S/C28−20S TAS, C27−20R/C28−20R, (C26−20R + C27−20S)/C28−20S and C28/(C26+C27) TAS, could serve as potential biomarker parameters to distinguish between the two groups of source rocks in the Tarim Basin. The values of those parameters (in above order) in Cambrian–Lower Ordovician source rocks were 0.3, >0.5, >0.85, and 0.8, >1.9, 1.2, respectively. The correlation between the source rock samples and 19 oils obtained from the Tadong, Tabei and Tazhong uplifts in the Tarim Basin show that most of the oils in Tabei uplift are probably from Upper Ordovician source rocks, the oils in Tadong uplift are more likely from Cambrian- Lower Ordovician source rocks, and the Tazhong uplift is more like a mixed oil region with oils from both of the two groups of source rocks.

Organic geochemistry of crude oils and Cretaceous source rocks in the Iranian sector of the Persian Gulf: An oil–oil and oil–source rock correlation study

The marls and argillaceous limestones of the Cretaceous Kazhdumi Formation, Ahmadi Member of the Sarvak Formation and Gurpi Formation are considered to be important source rock candidates in the Persian Gulf. To evaluate their source rock characteristics, 265 cutting samples of these rock units from 20 fields in offshore Iran were analyzed using Rock-Eval pyrolysis, organic petrography, stable carbon isotope composition and biomarker analysis. 1D basin modeling was also applied to analyze the burial and thermal history of these source rock candidates. Based on the results, the Kazhdumi and Gurpi formations, which have fair source rock potential, and the Ahmadi Member, which has fair to good source rock characteristics, were deposited in a marine reducing environment with marine organic matter as the main input. Different maturity indicators showed that the Ahmadi Member and Kazhdumi Formation are thermally immature to mature and the Gurpi Formation is immature to early mature in the study area. The results of the modeling suggested that the Kazhdumi Formation and Ahmadi Member in the southeastern parts of the study area are within the main oil window and that the Gurpi Formation has just begun to generate hydrocarbons. All three formations are thermally immature in the eastern parts. In the western parts of the Persian Gulf, the Kazhdumi Formation is early mature and the other formations are immature. The biomarker and stable carbon isotope parameters of these rock units were compared with 20 crude oil samples in the southeastern Persian Gulf. Based on the hierarchical cluster analysis (HCA), principal component analysis (PCA) and carbon isotope composition, the studied crude oils were divided into two groups: Group-I oils from Cretaceous reservoirs were probably derived from Cretaceous source rocks, while Group-II oils from Jurassic and Cretaceous reservoirs with Jurassic rocks as the expected source rocks. The performed oil–source rock correlation shows a positive correlation between the Group-I oils and the Ahmadi Member.

The source of highly overmature solid bitumens in the Permian coral reef paleo-reservoirs of the Nanpanjiang Depression

Solid bitumens occur extensively in Permian coral reefs of the Nanpanjiang Depression. Both potential source rocks and solid bitumens in the study area are highly overmature and have similar bulk carbon isotope values. It is difficult to perform an oil–source rock correlation study in this area based on only regular molecular geochemical methods and bulk carbon isotope values. Thus the covalently bound biomarkers released from solid bitumens and source rock kerogens by catalytic hydropyrolysis (HyPy), together with the geological settings, were taken into account in this oil–source rock correlation study. The distribution characteristics of covalently bound biomarkers suggest that the major source rock of the Longlin paleo-reservoir (in the midwest of the depression) solid bitumen should be the Middle Devonian mudstone, whereas the source rock of the Ziyun paleo-reservoir (in the north of the depression) solid bitumen should be the Lower Permian source rock. However, solid bitumens in the Ceheng and Wangmo paleo-reservoirs (in the middle of the depression) may be mainly sourced from the Middle Devonian source rock, but partly from the Permian source rock. Our bitumen–source rock correlation results are also supported by the petroleum geological settings of the study area, which indicate that the filling of those paleo-reservoirs was controlled by the matching of hydrocarbon generation and trap formation. Basically, the timing of hydrocarbon generation of the Middle Devonian source rocks matches well with the formation of Permian coral reef traps in the middle and midwest portions of the depression, but it is earlier than the formation of the Permian coral reef trap in the north of the depression. We show that our oil–source rock correlation study based on covalently bound biomarkers can provide reliable information for petroleum system analysis when highly overmature strata in South China are involved.

Organic geochemistry of the Lower Cretaceous black shales and oil seep in the Sinop Basin, Northern Turkey: An oil–source rock correlation study

In the Sinop Basin, a thick Liassic to Quaternary sedimentary section is exposed. A Lower Cretaceous-aged Çağlayan Formation crops out in the basin and consists of claystone, siltstone, sandstone, marl, and black-coloured shale that exhibits a fair to good source rock potential. An oil seep from the Çağlayan Formation is located in the Ekinveren region of the Sinop Basin.The average total organic carbon (TOC) values of two shale samples from the Çağlayan Formation in the Ekinveren and the Bürnük sections (Ekin-8, Bür-7) are 1.48 and 1.26 wt.%, respectively, and the hydrogen index (HI) values are 190 and 244 mgHC/g TOC, respectively. The potential yield (PY) value of the samples is >2.0 mgHC/g rock, which indicates fair–good hydrocarbon potential for the Çağlayan Formation.A unimodal n-alkane distribution with dominant light-end components is observed on the gas chromatograms of the shale samples from the Çağlayan Formation. Low TAR (terrigenous/aquatic organic matter ratios), low (C19 + C20)/C23 tricyclic terpane ratios and a higher type II kerogen content indicate that the shale samples predominantly contain marine organic matter. The Pr/Ph ratios of the shale samples are 1.39 and 0.89, respectively. The Pr/Ph values in combination with a high C30∗ diahopane/C29Ts ratio imply a suboxic–anoxic depositional environment for the Çağlayan Formation.The Tmax values of the Ekinveren and Bürnük shale samples are in the range of 425–432 °C and 431–434 °C, respectively, and the average Tmax values are 429 °C and 433 °C, respectively. Based on the Tmax data, the Çağlayan Formation shales are immature–early mature in the Ekinveren location and early mature–mature in the Bürnük location. The CPI values, isoprenoid/n-alkane ratio, 20S/(20S + 20R), ββ/(ββ + αα) C29 sterane and 22S/(22S + 22R) C32 homohopane ratios indicate that the shales from the Bürnük location are more mature than those of the Ekinveren location. The large UCM (unresolved complex mixture) and low amounts of n-alkanes and isoprenoid alkanes observed in the gas chromatogram of the oil seep indicate that the oil has been heavily biodegraded.The m/z 191 and m/z 127 mass chromatograms of the samples from the Çağlayan Formation and the Ekinveren oil seep were similar in their distributions of tricyclic terpane (C23 dominant), C24 tetracyclic terpane, norhopane, hopane, homohopane (with dominant C31 and a decreasing amount of the higher number homologues), diasterane and pregnane. The C27, C28, and C29 sterane distributions for the oil and the shale samples were also similar, demonstrating a C27 > C29 > C28 relationship.Thus, the biomarker data strongly indicate that the black shales and the Ekinveren oil seep are related to each other. In other words, the oil has been derived from the Çağlayan Formation.

Madbi-Biyadh/Qishn (!) petroleum system in the onshore Masila Basin of the Eastern Yemen

The Masila Basin is one several onshore Mesozoic basins in Yemen. However, a full petroleum system, with its essential elements and processes, has not been assigned yet. In this study, one petroleum system in the Masila Basin was identified and named Madbi-Biyadh/Qishn (!) petroleum system. An extensive overview study showed that the main source and reservoir rocks in the Masila Basin are the Upper Jurassic Madbi shales and Lower Cretaceous Biyadh/Qishn sandstones, respectively; hence it appears that the most important effective petroleum system of the Masila Basin becomes the Madbi-Biyadh/Qishn (!) petroleum system. Organic-rich shales of the upper part of the Madbi Formation, deposited during the upper Jurassic, constitute the main source rock of the crude oils in the basin. These shales contain high total organic carbon content (TOC >2.0 wt.%) and predominantly algal Type II with minor Type I kerogen. The Madbi shales are mature and, at the present time, are within the oil window with determined vitrinite reflectance values in the range of 0.53–0.91 Ro%. The Biyadh/Qishn sandstones are the main reservoir and were deposited in braided river channels, shoreface and shallow-marine environments, and consist of fine to coarse-grained, moderate to well sorted grains. Seal rocks are Cretaceous limestone and shales of the Qishn and Harshiyat Formations and Tertiary shales. Overburden rocks include the Cretaceous rocks and the Tertiary sediments deposited simultaneously with development of the traps during Oligocene–Middle Miocene time. Burial/thermal histories models demonstrate that hydrocarbon generation from the Madbi shales commenced in the Late Cretaceous and maximum rates of hydrocarbon expulsion occurred during the Early Tertiary. Geochemical oil-source rock correlation studies showed that regional distribution of the oil fields almost overlap with the previously constructed pod of active Madbi shales indicating that oil migrated from the active Madbi source rock to trapping sites via vertical migration pathways through faults as a result of Tertiary rifting during Oligocene–Middle Miocene time.

Millimeter-scale concentration gradients of hydrocarbons in Archean shales: Live-oil escape or fingerprint of contamination?

Archean shales from the Pilbara in Western Australia contain biomarkers that have been interpreted as evidence for the existence of cyanobacteria and eukaryotes 2.7 billion years (Ga) ago, with far reaching implications for the evolution of Earth’s early biosphere. To re-evaluate the provenance of the biomarkers, this study determined the spatial distribution of hydrocarbons in the original drill core material. Rock samples were cut into millimeter-thick slices, and the molecular content of each slice was analyzed. In core from the Hamersley Group (∼2.5 Ga), C <13 alkanes had gradually increasing concentrations from the surfaces to the center of the rock while the abundance of steranes, hopanes and C 15+ alkanes decreased with distance from the outer surfaces. In samples from the Fortescue Group (∼2.7 Ga), hydrocarbons were overwhelmingly concentrated on rock surfaces. Two mechanisms are proposed that may have caused the inhomogeneous distribution: diffusion of petroleum products into the rock (contamination model), and leaching of indigenous hydrocarbons out of host shales driven by pressure release after drilling (‘live-oil’ effect). To test these models, the hydrocarbon distributions in the Archean shales are compared with artificially contaminated rocks as well as younger mudstones where leaching of live-oil had been observed. The results show that chromatographic phenomena associated with live-oil escape and contaminant diffusion have strong effects on molecular ratios and maturity parameters, potentially with broad implications for oil-source rock correlation studies and paleoenvironmental interpretations. For the Archean shales, the live-oil effect is consistent with some of the observed patterns, but only the contamination model fully explains the complex chromatographic fingerprints. Therefore, the biomarkers in the Pilbara samples have an anthropogenic origin, and previous conclusions about the origin of eukaryotes and oxygenic photosynthesis based on these samples are not valid. However, the study also identified indigenous molecules. The spatial distribution of particular aromatic hydrocarbons suggests they are syngenetic. Although devoid of biological information, these aromatics now represent the oldest known clearly-indigenous terrestrial liquid hydrocarbons.

Carbonaceous substances in mineral deposits: implications for geochemical exploration

Carbonaceous substances (CS) are intimately linked directly and/or indirectly to the genesis of many types of mineral deposits. Examples of the phenomenon include metal accumulations in living organisms, coals, black shales, crude oils and solid bitumens. CS interact with metals by virtue of their inherent reducing, acidic and chelating characteristics. After kerogen, and across the oil-to-solid bitumen continuum, bitumen is the most important CS that promotes metallization. The most familiar Phanerozoic example is the carbonate-hosted Pb–Zn ores of the Mississippi Valley-type, for which diverse reduction models have been proposed. At Elliot Lake, Canada, and in the Witwatersrand, South Africa, CS including kerogen and derivative bitumen (as petrographically defined) are closely related to the genesis of Precambrian uranium and gold mineralization. Occurrences of solid bitumen have long been recognized as important in petroleum exploration, and specific metal ratios (e.g., V/V + Ni and Mo/Mo + Cr) in viscous crudes and solid bitumens have been successfully applied in oil–source rock correlation studies. Typically, there is an increase in concentration of organometallic moities and complexes from crude oil to solid bitumen. Highly anomalous concentrations of elements (U, Pt, Au, V, and Ni) occur in solid bitumen, and numerous minerals (e.g., Zn, Pb, U, Ti, Au and Ag bearing species, illite, pyrite, REE-phosphates, quartz, barite, carbonates) develop authigenically in association with bitumen. Consequently bitumens are potentially important in the search for, and evaluation of, diverse mineral deposits. Where linked to the hydrothermal history of organic matter in sedimentary rocks, bitumen and organic acids generated during diagenesis help to prepare ground for mineral deposition, and like some oil field brines, are genetically associated with mineral deposits. The mineral-forming constituents are carried in an aqueous phase that accompanies bitumen during its emplacement. The mineral-associated constituents and organically bound metals in solid bitumens provide important clues in exploration geochemistry.

Trace metals and organic geochemistry of the Machiques Member (Aptian–Albian) and La Luna Formation (Cenomanian–Campanian), Venezuela

Two proposed source-rock sequences in the Lower (Aptian–Albian) and the Upper (Cenomanian–Campanian) Cretaceous sediments of the Perijá Range, Maracaibo Basin, were geochemically analyzed in order to find environmentally controlled characteristic fingerprints. Trace metals and sulfur concentrations were found to be closely related with the physicochemical conditions during deposition of the rocks. Based on trace metal analyses and sulfur relationships with TOC, the Aptian–Albian sequence (Machiques Member) shows alternate oxic and anoxic episodes close to the bottom-water surface where mixed marine and terrestrial organic matter were deposited. The Cenomanian–Campanian sequence (La Luna Formation) persistently shows anoxic–euxinic conditions that allowed the preservation of marine organic matter. Ratios of trace metals (V, Mo and Zn) characterize both Cretaceous sedimentary columns, however, some limitations are visualized in using trace metals as correlation tools in further geochemical studies. Biomarker ratios are related to the organic matter type and lithology. Some specific ratios and individual compounds allow a clear differentiation between these two sequences and offer, in the context of δ 13 C , an excellent tool for further oil-source rock correlation studies.

98/02780 Petroleum land release—data availability: QGMJ QGMJ, 1998, 99, (1155), 39

A wide range of novel diagenetic and catagenetic products of the diaromatic carotenoid isorenieratene, a pigment of the photosynthetic green sulphur bacteria Chlorobiaceae, has been identified in a number of sedimentary rocks ranging from Ordovician to Miocene. Compound identification is based on NMR, mass spectrometry, the presence of atropisomers, and stable carbon isotopes. Atropisomers contain an axially chiral centre which, in combination with other chiral centres, results in two or more diastereomers that can be separated on a normal GC column. Chlorobiaceae use the reverse TCA cycle to fix carbon, so that their biomass is enriched in 13C. High 13C contents of isorenieratene derivatives therefore support their inferred origins.Isorenieratene derivatives include C 40, C 33, and C 32, diaryl isoprenoids and short-chain aryl isoprenoids with additional aromatic and/or S-containing rings. C 33 and C 32 compounds are diagenetic products of C 33 and C 32 “carotenoids” formed from isorenieratene during early diagenesis through expulsion of toluene and m-xylene, respectively. Cyclisation of the polyene acyclic isoprenoid chain can proceed via an intramolecular Diels-Alder reaction, followed by aromatisation of the newly formed ring. Sulphurisation is also an important process during early diagenesis, competing with expulsion and cyclisation. Sulphur-bound isorenieratane is released during progressive diagenesis, due to cleavage of relatively weak SS and CS bonds. Cleavage of C-C bonds during aromatisation of newly formed rings and during catagenesis yields short-chain compounds. The inherent presence of a conjugated double bond system in carotenoids implies that similar diagenetic and catagenetic reactions can occur with all carotenoids.Chlorobiaceae live at or below the oxic/anoxic boundary layer and require both light and H 2S. The presence of isorenieratene or its diagenetic and catagenetic products in ancient sedimentary rocks and crude oils is therefore an excellent indication for photic zone anoxia in the depositional environment. Diagenetic and catagenetic products of isorenieratene are expected to find applications in reconstruction of palaeoenvironments and in oil-oil and oil-source rock correlation studies. Their presence in several petroleum source rocks suggests that anoxia is an important environmental parameter for the preservation of organic matter.

Diagenetic and catagenetic products of isorenieratene: Molecular indicators for photic zone anoxia

A wide range of novel diagenetic and catagenetic products of the diaromatic carotenoid isorenieratene, a pigment of the photosynthetic green sulphur bacteria Chlorobiaceae, has been identified in a number of sedimentary rocks ranging from Ordovician to Miocene. Compound identification is based on NMR, mass spectrometry, the presence of atropisomers, and stable carbon isotopes. Atropisomers contain an axially chiral centre which, in combination with other chiral centres, results in two or more diastereomers that can be separated on a normal GC column. Chlorobiaceae use the reverse TCA cycle to fix carbon, so that their biomass is enriched in 13C. High 13C contents of isorenieratene derivatives therefore support their inferred origins.Isorenieratene derivatives include C 40, C 33, and C 32, diaryl isoprenoids and short-chain aryl isoprenoids with additional aromatic and/or S-containing rings. C 33 and C 32 compounds are diagenetic products of C 33 and C 32 “carotenoids” formed from isorenieratene during early diagenesis through expulsion of toluene and m-xylene, respectively. Cyclisation of the polyene acyclic isoprenoid chain can proceed via an intramolecular Diels-Alder reaction, followed by aromatisation of the newly formed ring. Sulphurisation is also an important process during early diagenesis, competing with expulsion and cyclisation. Sulphur-bound isorenieratane is released during progressive diagenesis, due to cleavage of relatively weak SS and CS bonds. Cleavage of C-C bonds during aromatisation of newly formed rings and during catagenesis yields short-chain compounds. The inherent presence of a conjugated double bond system in carotenoids implies that similar diagenetic and catagenetic reactions can occur with all carotenoids.Chlorobiaceae live at or below the oxic/anoxic boundary layer and require both light and H 2S. The presence of isorenieratene or its diagenetic and catagenetic products in ancient sedimentary rocks and crude oils is therefore an excellent indication for photic zone anoxia in the depositional environment. Diagenetic and catagenetic products of isorenieratene are expected to find applications in reconstruction of palaeoenvironments and in oil-oil and oil-source rock correlation studies. Their presence in several petroleum source rocks suggests that anoxia is an important environmental parameter for the preservation of organic matter.

Organically bound metals and biomarkers in the Monterey Formation of the Santa Maria Basin, California

Systematic variations in metal concentration ratios and biomarker ratios are observed with depth in cores of the Monterey Formation of the Union Leroy 51-18 well in the Santa Maria Basin, California. Specific metal ratios— V ( V + Ni) and Mo ( Mo + Cr) —correlate between kerogen and extractable organic matter. Further, the organic matter in the two predominant lithofacies (siliceous shales vs. phosphatic shales) can be distinguished based upon metal concentration ratios (e.g., V ( V + Ni) and certain biomarker characteristics (e.g., sterane/terpane, mono/triaromatic steroid hydrocarbon ratios). Maximum 28,30- bisnorhopane hopane ratios occur over a narrow range of V ( V + Ni) ratios in kerogen concentrates and extractable organic matter. This suggests that metal ratios (in kerogen concentrates and EOM) may be useful for oil-source rock correlation studies in the Monterey. Further, while kerogen parameters (metals) are discontinuous at the lithofacies boundary, extract parameters (biomarkers) are gradational at this boundary, suggesting about 30 ft. (9 m) of vertical hydrocarbon migration across the lithofacies contact.

Geochemical characteristics of oils from the Chaidamu, Shanganning and Jianghan Basins, China

Thirty oil samples from the Shanganning, Jianghan and Chaidamu Basins in China have been examined by a number of geochemical techniques. The techniques included gas chromatography (GC), gas chromatography-mass spectrometry (GC-MS) and tandem mass spectrometry using a triple stage quadrupole mass spectrometer (MS/MS), stable isotope mass spectrometry. There were several reasons for undertaking this study. Firstly was the attempted oil-source rock correlation studies within the individual basins. Secondly was the continuing quest for novel, or sets of, biomarkers that could be assigned to saline and hypersaline environments and subsequently used to characterize other similar depositional environments. Thirdly was the desire to compare and contrast results obtained from these three basins with those from a similar study being undertaken on the South Florida Basin and the Anadarko Basin in the U.S.A. Whereas the Chinese basins are lacustrine, those in the U.S.A. are marine. For the purposes of this paper, only the results from the three Chinese basins will be discussed. In addition to examining the results from the biomarker distributions as determined by GC-MS and GC-MS/MS, the results are correlated with those obtained from the δ 13C isotropic determinations. For example, three oils in the Shanganning Basin showed anomalous isotopic data, which immediately suggested that they should be examined in greater detail than the remaining oils, all of which correlated quite closely with each other. A combination of results used in this way is far more valuable than the biomarker data alone. In summary, the results demonstrate that various families of oils in the three basins can be distinguished on the basis of geochemical data and in many cases on the basis of the carbon isotopic composition alone. The oils from the Shanganning Basin had the lightest values, around −32%, whereas the Chaidamu were the heaviest in the −26% region. The Jianghan oils had values intermediate to the other two basins. Variations in the isotopic composition appear to correlate with variations in salinity of the depositional environment as do a number of other biomarker parameters. In particular the relative concentrations of gammacerane, β-carotanes and tricyclic terpanes all increase as the relative salinity increases. Oils from within particular basins that had anomalous isotopic compositions could also be distinguished on the basis of their biomarker composition.

The occurrence and identification of series of organic sulphur compounds in oils and sediment extracts: II. Their presence in samples from hypersaline and non-hypersaline palaeoenvironments and possible application as source, palaeoenvironmental and maturity indicators

The organic sulphur compounds (OSC) present in sixteen immature samples (both crude oils and bitumens) from different geographical locations and of different ages representing different palaeoenvironments have been analysed by GC-MS. In all samples OSC (thiolanes, thianes, thiophenes and benzo[ b]thiophenes) with structures related to well-known geologically occurring hydrocarbons ( n-alkanes, isoprenoid alkanes, steranes, triterpanes) occur, although the relative amounts and distribution patterns of the various OSC classes vary considerably. This variation is interpreted as a result of different sources of organic matter and different degrees of thermal maturation. The palaeoenvironments of the samples were anoxic and H 2S, produced by sulphate-reducing bacteria, probably has exceeded the input of reactive iron minerals. These conditions resulted in a surplus of free H 2S, which reacted with organic matter, leading to the formation of OSC. The distributions of OSC may be useful as molecular indicators for the assessment of sources of organic matter, palaeoenvironment and thermal maturity and for oil-oil and oil-source rock correlation studies. The distributions of the C 20 isoprenoid thiophenes in combination with those of the methylated 2-methyl-2-(4,8,12-trimethyltridecyl) chromans can be used to discriminate non-hypersaline from hypersaline palaeoenvironments.