Stages Of Thermal Maturation Research Articles

Formation of nanoporous pyrobitumen residues during maturation of the Barnett Shale (Fort Worth Basin)

Abstract Hydrocarbon generation reactions occur within organic-rich shales as a response to thermal maturation. Here, we report observations on samples from the organic-rich Mississippian Barnett shale gas system (Fort Worth Basin, Texas, USA) at varying stages of thermal maturation. A multiscale characterization was achieved using a combination of compositional organic geochemistry and spectromicroscopy techniques, including synchrotron-based scanning transmission X-ray microscopy (STXM) and transmission electron microscopy (TEM). We document the chemical evolution of the macromolecular structure of Barnett Shale kerogen with increasing maturity, from an immature kerogen containing a significant aliphatic component and an important concentration of oxygen and sulfur-containing functional groups to an overmature kerogen dominated by poorly condensed aromatic structures. In addition to the presence of bitumen in samples of oil window maturity, very likely genetically derived from thermally degraded kerogen, the formation of nanoporous pyrobitumen has been inferred for samples of gas window maturity, likely resulting from the formation of gaseous hydrocarbons by secondary cracking of bitumen compounds.

The composition, origin and fate of complex mixtures in the maltene fractions of hydrothermal petroleum assessed by comprehensive two-dimensional gas chromatography

Sedimentary organic matter in hydrothermal systems can be altered by high temperature fluids to generate petroleum. The saturated and aromatic fractions of these hydrothermal oils are compositionally similar to conventional oil with the exception that they often contain higher concentrations of polycyclic aromatic hydrocarbons (PAH) as well as substantial mixtures of coeluting organic compounds that produce dramatically rising signal on the baseline of gas chromatograms termed unresolved complex mixtures (UCMs). Little is known about the compounds that compose UCMs and why or how they form. This is in part due to an inability to discriminate between in situ and migrated components that characterize the petroleum generated in hydrothermal systems. However, UCMs are also a product of the limitations imbedded in analytical separation techniques. With the advent of comprehensive two-dimensional gas chromatography (GC×GC), a revision of what should constitute molecular complexity needs to be considered. We address these problems by comparing the molecular compositions of the maltene fractions of three previously published hydrothermal petroleum samples using time of flight-mass spectrometry (GC×GC–ToF-MS) and 12 hydrothermal petroleum samples in cores from three locales using comprehensive two-dimensional gas chromatography with flame ionization detection (GC×GC–FID). The sediment cores were collected from Middle Valley, located off the axis of the Juan de Fuca Ridge, and the Escanaba Trough, along the Gorda Ridge, both in the NE Pacific Ocean, as well as from the Guaymas Basin in the Gulf of California. We define a UCM in GC×GC data to be a condition in which ⩾25% of the detected peaks within a chromatographic area coelute in either the first or second dimension. In turn, complex (CM) and simple mixtures (SM) are defined as having 5–24% and <5% coelution, respectively. All CM and UCMs were dominated by an array of configurational isomers, which becomes increasingly aromatic with higher molecular weight. We relate this to a multi-molecular complexity metric (MCM) by quantitatively comparing the difference in total peak variance and peak density for a GC×GC chromatogram. MCM values correlate with biomarker thermal maturity ratios for the Escanaba Trough and Guaymas Basin samples indicating that molecular complexity in these hydrothermal environments is in part a function of burial temperatures. Partial Least Squares (PLS) linear regression was applied to the total number of peak retention times as a proxy for the bulk molecular differences between each hydrothermal oil sample. Differences in the sample regressions correlate with the thermal maturity and the degree of PAH alkylation, indicating that this technique can be used to assess the degree of oxidative weathering due to dehydrogenation and hydrocarbon cracking. Subtracted chromatograms were then used to quantitatively track all of the individual molecular changes within the pyrolytic regime at Escanaba Trough. These subtracted chromatograms indicate that high molecular weight PAHs are highly mobile in hydrothermal fluids and may represent a phase partitioning that is occurring at greater depths. This phase condenses just below the seafloor to form an UCM in the near surface sediments. Saturated hydrocarbon biomarkers, such as hopanes, steranes and biphytanes are less mobile and more prone to being cracked and/or aromatized prior to migration toward the ocean floor. Together these techniques suggest that the molecular complexity of hydrothermal petroleum maximizes during the early stages of thermal maturation. The diversity of compounds forming these UCMs then decreases with increasing dehydrogenation, dealkylation and condensation reactions associated with elevated thermal stress and exposure to oxidants within the hydrothermal fluids.

Bulk Geochemical Data of Fossil Wood from the Middle Jurassic Clays of Poland

Abstract Macroscopic observations, microscopic studies and literature data revealed that Middle Jurassic wood from Częstochowa area has a different state of preservation, and various types and degrees of mineralization and oxidation. Obtained results of organic matter fractionation illustrate a clear domination of polar fraction in the obtained extracts revealing low thermal maturity stage. Total organic carbon (TOC) values for analysed samples are in a wide range from 1.06% to 68.50%. The highest amount of TOC were measured in not or poorly mineralized wood samples but most of them are mineralized wood fragments, showing the TOC values in the range of 2% - 10%. Percentage content of carbonate in fossil wood constitute in a wide range from less than 1% CaCO3 to above 85% CaCO3. The resulting percentage of the total sulfur content is very varied and do not show convergence with other data such as TOC, carbonate content, etc and is most probable connected with pyritisation range. Unlike the Middle Jurassic clay samples, where long-chain and short-chain n-alkanes occur in similar concentrations, in wood samples always short-chain n-alkanes dominated, in the range from 15 to 23 carbon atoms in molecule. The values of the CPI are generally higher than 1 which indicates the contribution of organic matter derived from higher plant waxes, which are characteristic of e.g. needles from gymnosperm plants. Under the influence of post - diagenetic oxidation in mineralized wood samples distribution of n-alkanes is changing. Diaster-13(17)-enes with 28 and 29 carbon atoms in molecule are present in the wood samples, while those with 29 atoms strongly prevail.

Geochemical evolution of organic-rich shales with increasing maturity: A STXM and TEM study of the Posidonia Shale (Lower Toarcian, northern Germany)

Hydrocarbon generation and retention processes occurring within gas shales as a response to increases in thermal maturation are still poorly constrained. While efforts have been directed at unravelling the resource potential, composition and textures of these economically important unconventional systems, their spatial variability in chemistry and structure is still poorly documented at the sub-micrometer scale. Here, we have characterized samples of the Lower Toarcian Posidonia Shale samples from northern Germany at varying stages of thermal maturation using a combination of compositional organic geochemistry and spectromicroscopy techniques, including synchrotron-based scanning transmission X-ray microscopy (STXM). We document geochemical and mineralogical heterogeneities down to the nanometer scale within the investigated samples as a function of their level of thermal maturity. In particular, authigenic albite crystals containing nanometric halite inclusions have been documented within the investigated mature and overmature samples. The presence of such tracers of palaeobrine–carbonate interactions supports a maturation scenario for the Lower Toarcian Posidonia Shale intimately related to ascending brine fluids rather than a maturation scenario solely resulting from high heat flows. In addition, various types of asphaltene- and NSO-rich bitumen have been detected within the same samples, very likely genetically derived from thermally degraded organic precursors. Furthermore, the formation of nanoporous pyrobitumen has been inferred for samples of gas window maturity, likely resulting from the formation of gaseous hydrocarbons. By providing in-situ insights into the fate of bitumen and pyrobitumen as a response to the thermal evolution of the macromolecular structure of kerogen, the results reported here constitute an important step towards better constraining hydrocarbon generation processes during natural shale gas maturation.

Carbon and hydrogen isotopic compositions and their evolutions of gases generated by herbaceous swamp peat at different thermal maturity stages

Coalbed methane (CBM) accumulation models include continuous gas accumulation and staged gas accumulation. However, studied on the geochemical characteristics and indices to evaluate staged accumulation CBM are lacking. This study for the first time obtained the carbon and hydrogen isotopic compositions of methane and ethane generated at different evolution stages using thermal simulation of samples prepared by treating an herbaceous swamp peat at different temperatures. The results showed that the carbon isotopic compositions of methane and ethane were obviously affected by the thermal evolution level of the starting sample, while the hydrogen isotopic compositions were closely related to the maturity of gases. The carbon and hydrogen isotopic compositions of gases generated by coal-forming organic matter with R o values from 1.2%, 1.7%, 2.4%, 3.2% and 3.7% to 5.2% were determinated. The relationship between R o values and the carbon and hydrogen isotopic compositions of gases generated by coal-forming organic matter at different evolution stages as well as the carbon or hydrogen isotopic relationships between methane and ethane were established. The results provide a scientific basis for studying the genesis of CBM generated at different maturity intervals and understanding the geochemical characteristics of staged accumulation CBM. These results were applied to a case study on CBM from the southern Qinshui basin, and it was found that the CBM accumulated after the Middle Jurassic and was characteristic of staged gas accumulation. This is consistent with the result of geological studies, and further showed that the results of thermal simulation experiments are very important for evaluating the genesis of natural CBM.

SOURCE ROCK POTENTIAL OF THE UPPER JURASSIC – LOWER CRETACEOUS SUCCESSION IN THE SOUTHERN MESOPOTAMIAN BASIN, SOUTHERN IRAQ

This paper reports on the hydrocarbon potential of subsurface samples from the Upper Jurassic Lower Cretaceous succession at the Rumaila (North and South), Zubair, Subba and West Qurna oilfields in southern Iraq. A total of 37 fine‐grained core samples of the Sulaiy, Yamama, Ratawi and Zubair Formations from ten wells were analyzed. Contents of organic carbon and sulphur were measured; other analyses included Rock‐Eval pyrolysis, optical microscopy in incident light, solvent extraction and gas chromatography of non‐aromatic hydrocarbons. The results indicated that the samples from the Cretaceous succession (Yamama, Zubair and Ratawi Formations) are at moderate levels of thermal maturity, whereas samples from the Upper Jurassic – Lower Cretaceous Sulaiy Formation are at a stage of thermal maturity beyond peak oil generation. According to the results of this study, the Sulaiy Formation is an excellent highly‐mature source rock and it is probably responsible for the generation of large quantities of oil in the study area. The samples differ with respect to their organic fades and biomarker distribution, indicating that palaeo depositional conditions varied significantly.

Fácies orgânica da Formação La Luna, Bacia do Valle Superior Del Magdalena, Colômbia: implicações para a geração de petróleo e caracterização paleoambiental

Upper Cretaceous pelitic rocks generate most of the oil reserves in Colombia. In Del Magdalena Upper Valley (MUV), the existence of good quality outcrops and thermal evolution levels that vary from immaturity to the end of the oil generation "window" makes it one of the most appropriate regions for the study of primary migration and generation of oil in Upper Cretaceous. The main objectives of this work were to study the organic facies of La Luna Formation in an outcrop section called Riacho Bambuca (Bambuca Creek), determine the oil generation potential and characterize the paleoenvironment. For this research, 24 samples were used in palynofacies analysis (characterization of the kerogen components assembly) and in organic geochemistry analysis (Total Organic Carbon - TOC analysis and Rock-Eval pyrolysis, provided by Colombia Oil Institute - ECOPETROL). The palynofacies analysis included the use of microscopy techniques (transmitted white light and incident blue light). Furthermore, a Spore Coloration Index (SCI) analysis was made in order to determine the thermal maturation stage. The studied material was composed mainly of an amorphous organic substance, with its fluorescent coloration varying from yellow to bright orange. The palynomorph group is represented by spore morph and dinoflagellate cysts. The ligneous material are present in very low percentages; they are mainly opaque phytoclasts. The results of geochemical analysis showed TOC contents ranging from medium to high, excellent potential for the generation of hydrocarbons (PG &gt;; 4 mg HC/g of rock), hydrogen index ranging from 329 to 589 mg HC/g, and low values of oxygen index, characterizing type II kerogen. The low degree of thermal maturation was determined by Spore Coloration Index values ranging from 2,5 to 3,0, Tmax values below 440ºC and Hydrocarbon Production Index inferior to 0,2. According to the organic facies data, La Luna Formation deposited in a marine environment with facies from disoxic-anoxic distal shelf and suboxic-oxic distal basin; there was kerogen of excellent quality, and its quantity was adequate for the generation of oil.

Occurrence, thermal evolution and primary migration processes derived from studies of organic matter in the Lucaogou source rock at the southern margin of the Junggar Basin, NW China

The Lucaogou Formation carbonate-rich oil shale source rock is exposed at the southern margin of the Junggar Basin, Xinjiang, NW China. We have sampled it in detail and conducted microstructural, mineralogical and geochemical studies, including thin section petrography, UV fluorescence petrography, X-ray diffraction, vitrinite reflectance, bitumen reflectance, fluid inclusion analysis and Raman spectroscopy. Organic matter is disseminated through the carbonate-bearing siltstone source rocks and concentrated in numerous bedding parallel stylolites and in two sets of carbonate veins, one along bedding parallel fractures and the other cross-cutting stylolites and bedding. The research about maturity of organic matter finds vitrinite reflectance values increase from the dispersed kerogen (0.64%) to the stylolites (the one of oriented vitrinite is 0.72% and the one of migrated bitumen is 2.38%); Homogenization temperatures of fluid inclusions in veins containing hydrocarbon fluid inclusions show an increase from 178.5°C in the bedding parallel veins to 222°C in the cross-cutting veins, confirmed by Raman spectroscopy. These results support a model of progressive heating accompanied by fluid loss during later stages of thermal maturation of source rock and the onset of primary migration. Obviously, the occurrence of organic matter is the trace of hydrocarbon primary migration, and the bedding lamination surfaces and cross-cutting fissures are the principal pathways of hydrocarbon-bearing fluids migration. Bedding lamination surfaces evolved into stylolites along the earliest primary migration pathways, followed by bedding parallel and cross-cutting fissures.

Charging of Elk Hills reservoirs as determined by oil geochemistry

Crude oils from Miocene and Pliocene reservoirs from the Elk Hills field in California's San Joaquin basin were analyzed for stable carbon isotopes and biomarkers. Cluster analysis of geochemical variables defines five principal oil families, all derived from different organic-rich facies of the Miocene Monterey Formation. Carbon isotope analysis indicates no contribution from the basin's other major source rock, the Eocene Kreyenhagen Formation. Oil families show a strong correspondence to stratigraphic intervals. Oils from pre-Monterey reservoirs were probably generated from the lowermost organic-rich facies of the Monterey and are the most thermally mature. Upper Miocene Stevens zone turbidite reservoirs contain oils of various thermal-maturity stages, but mature light ends are abundant and are likely generated from the floors of the adjacent subbasins located north and south of Elk Hills. The relatively minor presence of low-thermal-maturity biomarkers that are typically characteristic of Monterey oils may indicate that Stevens traps did not form until after the source intervals were at a higher level of thermal maturity. All oils in Stevens porcelanite reservoirs contain a higher concentration of low-maturity biomarkers, which may indicate derivation from more localized areas on the flanks of the Elk Hills anticlines. The shallow Pliocene oils have suffered biodegradation to different degrees, and the lowest API gravities occur on the flanks of the anticline. The carbon isotopic composition of these oils suggests yet another Monterey source facies that charged the Pliocene reservoirs and is not simply the result of vertical leakage from the older Miocene reservoirs. John E. Zumberge has been vice president and cofounder of GeoMark Research in Houston since 1991. He was manager of geochemical and geological research for Cities Service–Occidental, general manager for Ruska Laboratories, and director of geochemical services for Core Laboratories. He has global experience in petroleum geochemistry, focusing on crude-oil biomarkers. He obtained a B.S. degree in chemistry from the University of Michigan and a Ph.D. in organic geochemistry from the University of Arizona.Judy A. Russell is a senior geological advisor for Occidental and works on worldwide exploration and production, with an emphasis on the integration of geochemistry. She has extensive experience in many of Occidental's projects in Latin America, Far East, the United States, and the Middle East. She has a B.S. degree from Phillips University and an M.S. degree from the New Mexico Institute of Mining and Technology. Stephen Anthony Reid is a senior geological advisor for Occidental and works on international exploration, with an emphasis on deep-water projects. He has extensive experience in California's San Joaquin basin, including the Elk Hills field, where he conducted studies on Stevens turbidite and Monterey porcelanite reservoirs. He has B.S. and M.S. degrees from California State University, Northridge.

Hydrocarbon source rock potential and comments on correlation of the Lower Jurassic Poker Chip Shale, west-central Alberta

Research Article| June 01, 2002 Hydrocarbon source rock potential and comments on correlation of the Lower Jurassic Poker Chip Shale, west-central Alberta Cynthia L. Riediger Cynthia L. Riediger Department of Geology and Geophysics, University of Calgary, 2500 University Drive NW, Calgary, AB T2N 1N4 Search for other works by this author on: GSW Google Scholar Author and Article Information Cynthia L. Riediger Department of Geology and Geophysics, University of Calgary, 2500 University Drive NW, Calgary, AB T2N 1N4 Publisher: Canadian Society of Petroleum Geologists Received: 05 Nov 2001 Accepted: 25 Mar 2002 First Online: 02 Mar 2017 Online ISSN: 2368-0261 Print ISSN: 0007-4802 © The Society of Canadian Petroleum Geologists Bulletin of Canadian Petroleum Geology (2002) 50 (2): 263–276. https://doi.org/10.2113/50.2.263 Article history Received: 05 Nov 2001 Accepted: 25 Mar 2002 First Online: 02 Mar 2017 Cite View This Citation Add to Citation Manager Share Icon Share Facebook Twitter LinkedIn MailTo Tools Icon Tools Get Permissions Search Site Citation Cynthia L. Riediger; Hydrocarbon source rock potential and comments on correlation of the Lower Jurassic Poker Chip Shale, west-central Alberta. Bulletin of Canadian Petroleum Geology 2002;; 50 (2): 263–276. doi: https://doi.org/10.2113/50.2.263 Download citation file: Ris (Zotero) Refmanager EasyBib Bookends Mendeley Papers EndNote RefWorks BibTex toolbar search Search Dropdown Menu toolbar search search input Search input auto suggest filter your search All ContentBy SocietyBulletin of Canadian Petroleum Geology Search Advanced Search Abstract The Lower to Upper Toarcian Poker Chip Shale is present at outcrop in the central and southern Alberta foothills, and comprises marine, black calcareous shale and thin limestone that yield total organic carbon (TOC) values of 1 to 7 wt%. Such high TOC values suggest that these strata may have generated and expelled economic quantities of hydrocarbons. However, the outcrops are presently overmature with respect to hydrocarbon generation, and hence their initial generative potential is difficult to assess. This study of strata previously presumed to be equivalent in the subsurface of the Plains region was undertaken in an attempt to document the generative potential of this unit at the early to mid-mature stages of thermal maturity. The results of this study are integrated with previous stratigraphic and paleontological studies to support revised correlations of Lower to Middle Jurassic strata from the outcrop belt to the subsurface of west-central Alberta.New ammonite identifications from the middle and upper units of the “Nordegg Member” (north of Twp. 60) indicate that these strata are of Early Toarcian age. The middle and upper units of the subsurface “Nordegg Member”, north of Twp. 60 (and perhaps also the radioactive shale at the top of the Nordegg Member proper, south of Twp. 60), are thus considered equivalent to the organic-rich, black calcareous shale and thin limestone of the Poker Chip Shale, which yields Early to Late Toarcian ammonites from outcrops near its type area in the vicinity of Turner Valley, Alberta. This stratigraphic interval is identified in this study as Poker Chip Shale A.Overlying Poker Chip Shale A in the subsurface north of about Twp. 40 is a succession of medium- to dark-grey, or greenish grey, noncalcareous, pyritic, friable and variably bentonitic shales that exhibit moderate gamma ray radioactivity and, based on palynological studies, are Toarcian to Aalenian in age. This interval is commonly identified by various authors and on industry databases as the Poker Chip Shale. In this study, this unit is designated as Poker Chip Shale B, to distinguish it from slightly older, and lithologically and geochemically distinct, strata of the typical Poker Chip Shale as it was originally defined in the Turner Valley region. Poker Chip Shale B is considered equivalent to lithologically similar, imprecisely dated strata in the lower Rock Creek Member of the Fernie Formation at outcrop in the western Alberta Foothills.Poker Chip Shale Ahas excellent hydrocarbon source rock characteristics (TOC values up to 18.5 wt%; Hydrogen Index (HI) values up to 740 mg HC/g TOC) and is thermally mature to overmature over a large region. It thus must have generated significant volumes of hydrocarbons during thermal maturation. Although some of the generated hydrocarbons are present in conventional reservoirs, large volumes were likely retained in the source rock. Therefore, Poker Chip Shale A may represent a viable target for fractured shale production.In contrast, Poker Chip Shale B is not a source rock for hydrocarbons, as it commonly yields TOC values much less than 1 wt%. However, Poker Chip Shale B may have acted as a barrier to upward migration of hydrocarbons generated in underlying strata. You do not have access to this content, please speak to your institutional administrator if you feel you should have access.

Bitumen veins and Eocene transpression, Neuquén Basin, Argentina

In the northwestern part of the petroleum-rich Neuquén Basin, veins of solid hydrocarbon (bitumen) have been reported from over 150 localities. The bitumen veins are mostly steeply-dipping and show intrusive relationships with their wall rocks. The largest are some 8 m wide, 8 km long and probably several kilometres deep. The bitumen probably formed in the earliest stages of thermal maturation of organically-rich source rocks. The most likely source rocks for the bitumen, as well as for most of the oil and gas in the Neuquén Basin, are black marine shales of the Vaca Muerta and Agrio formations. These were deposited in a rift setting during the late Jurassic and Early Cretaceous. According to subsidence models, the source rocks should have reached thermal maturity in the latest Cretaceous or Paleocene and should have remained in the oil window ever since. Although the bitumen has not been dated directly, the veins probably formed soon after maturation of the source rocks, in other words, in the Paleocene or Eocene. The wall rocks of the veins are mostly the source rocks themselves. Other veins have been emplaced into overlying strata of Early Cretaceous to Paleocene ages or into underlying sediments of Jurassic age. The bitumen veins have preferred orientations. The dominant trend is 060° and subsidiary trends are either 000° to 020° or 100°. As in other basins worldwide, the majority of bitumen veins in the Neuquén Basin probably formed by tensile failure, in orientations perpendicular to the least compressive stress, under the combined effects of regional tectonics and fluid overpressures. The orientations of the veins are compatible with the direction of oblique convergence between continental South America and the oceanic Nazca plate in the Eocene. Many major structures in the Neuquén Basin are also of Eocene age and may have formed under right-lateral transpression.

Ostracodes de la limite frasnien-famennien en environnement anoxique (La Serre, Montagne Noire, France)

At La Serre, the trench C exposes, close to the Frasnian-Famennian boundary, dark and bituminous limestones and shales related to a hemipelagic sedimentation in dysoxic or anoxic bottom water conditions (on the whole). The organic matter produced probably by microalgae, have subsisted in an euxinic trough of the outer shelf. From bed to bed, the carbonate content fluctuates between 7 and 96 per cent and the total organic carbon (COT) between 0.1 and 4.1 per cent. The thermal maturation stage appears to be high. Twelve meters of rock have been sampled in the late Frasnian and the early Famennian of the La Serre trench C and 34 ostracod species have been recognized, the majority of which are figured herein. Paraparchitacea and Myodocopina (Entomozoacea and Cypridinacea) characterize this ostracod fauna and the specific diversity is relatively low. The presence of Bairdiacea in one bed is explained by temporary better oxygenated bottom water conditions. The ostracod assemblages confirm a generally low or nil palaeo-oxygenation and show that the % COT of samples is not always related to this palaeo-oxygenation. Entomozoids thrive in dysoxic waters, but they leave when anoxia takes place. The most resisting benthic ostracods belong principally to the Paraparchitacea. The recovery from the Frasnian-Famennian event was delayed by the anoxia in the lowermost part of the Famennian at La Serre. Then another ostracod assemblage, characterized by some platycopids, returns. We compare these results with those of contemporaneous better oxygenated environments of Coumiac, 25 km apart. It allows to emphasize the contrast between these ostracod faunas.

Sulphur-radical control on petroleum formation rates

Most petroleum is formed through the partial decomposition of kerogen (an insoluble sedimentary organic material) in response to thermal stress during subsurface burial in a sedimentary basin1,2. Knowing the mechanisms and kinetics of this process allows the determination of the extent and timing of petroleum formation, which, in turn, are critical for evaluating the potential for petroleum occurrences within a sedimentary basin. Kinetic models of petroleum generation are derived mainly from pyrolysis experiments1,2, in which it is usually assumed that formation rates are controlled by the strength of the bonds within the precursor compounds: this agrees with the observation that petroleum formation rates increase with increasing sulphur content of thermally immature kerogen2,3,4, C–S bonds being weaker than C–C bonds. However, this explanation fails to account for the overall composition of petroleum. Here I argue, on the basis of pyrolysis experiments, that it is the presence of sulphur radicals, rather than the relative weakness of C–S bonds, that controls petroleum formation rates. My findings suggest that the rate of petroleum formation depends critically on the concentration of sulphur radicals generated during the initial stages of thermal maturation. The proposed mechanism appears to provide a realistic explanation for both the overall composition of petroleum and the observed variation in formation rates.

Sulphur and oxygen sequestration of n-C 37 and n-C 38 unsaturated ketones in an immature kerogen and the release of their carbon skeletons during early stages of thermal maturation

Sedimentary rock from the Gessoso-solfifera Formation (Messinian) in the Vena del Gesso Basin (northern Italy) containing immature ( R o = 0.25%) S-rich organic matter was artificially matured by hydrous pyrolysis at temperatures from 160 to 330°C for 72 h to study the diagenetic fate of n-C 37 and n-C 38 di- and tri-unsaturated methyl and ethyl ketones (alkenones) biosynthesised by several prymnesiophyte algae. During early diagenesis, the alkenones are incorporated into the kerogen by both sulphur and oxygen cross-linking as indicated by chemical degradation experiments with the kerogen of the unheated sample. Heating at temperatures between 160 and 260°C, which still represents early stages of thermal maturation, produces large amounts (up to 1 mg/g TOC) of S-bound, O-bound, and both S- and O-bound n-C 37 and n-C 38 skeletons, saturated n-C 37 and n-C38 methyl, ethyl, and mid-chain ketones, C 37 and C 38 mid-chain 2,5-di- n-alkylthiophenes, C 37 and C 38 1,2-di- n-alkylbenzenes, and C 37 and C 38 n-alkanes. With increasing thermal maturation, three forms of the n-C 37 and n-C 38 skeletons are relatively stable (saturated hydrocarbons, 1,2-di- n-alkylbenzenes and saturated ketones), whereas the S- and O-bound skeletons are relatively labile. These results suggest that in natural situations saturated ketones with an n-C 37 and n-C 38 skeleton can be expected as well as the corresponding hydrocarbons.

Are vanadyl porphyrins products of asphaltene/kerogen thermal breakdown?

The idea was examined that during early stages of thermal maturation of source rocks or petroleums, the release of bound vanadyl (VO 2+) porphyrins (P) from the immature asphaltenes or kerogen could contribute to an increase in extractable VO 2+-P. To simulate such a change in the laboratory, the Dead Sea ‘floating’ asphalt and total organic (bitumen + kerogen) fractions of the La Luna and Serpiano carbonaceous sedimentary rocks were heated at controlled temperatures (100, 200, 300 and 400°C) for different periods of time. Residual (and altered) asphaltenes or kerogens were then separated from the heated products and analysed for VO 2+-P content by electron spin resonance. Three conclusions were reached: (1) thermal degradation of immature asphaltenes or kerogen generated no or very little (<1 wt%) extractable VO 2+-P during simulated maturation of petroleums or source rocks and thus by inference during natural maturation; (2) petroleum VO 2+-P by far are those that were saved from incorporation into asphaltenes or kerogen precursors (or young asphaltenes or kerogen) during diagenesis; and (3) a high VO 2+-P content of a petroleum is not an indication of its immaturity.

Reservoir geochemistry of South Pass 61 Field, Gulf of Mexico: compositional heterogeneities reflecting filling history and biodegradation

Cluster analysis of GC data for gasoline and mid-range hydrocarbon ratios from fifty-one South Pass 61 Field oils reveals geochemically similar oil clusters corresponding to geographically coherent groups. Insight into the groupings is obtained from examination of indicators of geochemical processes, e.g., anaerobic biodegradation, aerobic biodegradation and extensive remigration of light ends. Six duplicate samples collected in 1986 and 1992 as well as replicate runs on a single sample showed excellent analytical reproducibility. Subtle but consistent differences in both gasoline and oil-range hydrocarbon maturity indicators are observed between the east, west, and far west flanks of the field, suggesting filling of different segments of the reservoir from different kitchens at slightly different stages of thermal maturity or with slightly different chemical character. The west flank of the salt dome was charged with slightly more thermally mature petroleum than the east flank. The stratigraphically oldest and deepest sand on the far west flank has received the most mature petroleum. Different fluid contacts and GORs are observed in different sands and different fault blocks. The stacked pay geometry of the field and widespread faulting have led to considerable remigration of gas and condensate as observed in other fields in the Gulf of Mexico (Thompson, 1987). Biodegradation varies in severity with depth and reservoir zone, but is frequently overprinted by remigration of light end hydrocarbons. Anaerobic biodegradation by sulfate-reducing bacteria is probably the cause of light to moderate alteration in intermediate depth Pliocene sands which are hydraulically connected to the salt dome (with dissolution of anhydrite from the salt dome providing the sulfate). Widespread late pyrite formation in reservoir sandstones is inferred to represent the ultimate sink for reduced sulfur from sulfate reduction during oil biodegradation. Co-produced water compositions suggest no oxygenated freshwater infusion.

Coal rank and burial history of Cretaceous – Tertiary strata in the Grande Cache and Hinton areas, Alberta, Canada: implications for fossil fuel exploration

The present study discusses coal rank and burial histories for Cretaceous–Tertiary coal measures and thermal maturity of associated source rocks. Coal rank ranges from subbituminous to semianthracite. Coalification maps for selected coal zones indicate a broad coalification maximum east of the deformed belt. In the Pocahontas, Brûlé, and Hinton areas, rank levels appear to be elevated locally due to geothermal anomalies. Thermal modelling indicates that the westward decrease of coal rank in Lower Cretaceous strata is related to a westward decrease in the duration of burial beneath Maastrichtian–Eocene foreland-basin deposits. Upper Cretaceous – Tertiary strata were subjected to relatively low geothermal gradients (&lt; 20 °C/km), whereas Lower Cretaceous strata were exposed to much higher gradients (up to 46 °C/km). Tectonic loading in the foothills had only a minor impact on coalification. At Obed Marsh (Alberta Syncline) thermal modelling suggests that deformation in the thrust belt continued for at least a few million years beyond the 60 Ma age recently suggested by fission-track analysis to indicate the end of Laramide deformation. Petroleum source rock intervals of the study area are currently at various stages of thermal maturity (oil generation window to dry gas zone). Coal seams in the Upper Cretaceous – Tertiary coal measures at and near surface have rank levels suitable for combustion, whereas seams in the Lower Cretaceous coal measures are high-quality metallurgical coals. East of the deformed belt the coal measures occur at depths that at the present time are uneconomic for production.

Alkylated phenanthrene distributions as maturity and origin indicators in crude oils and rock extracts

Methylphenanthrene (MP), dimethylphenanthrene (DMP), and trimethylphenanthrene (TMP) distributions have been determined in crude oils and rock extracts from different origins at various stages of thermal maturity. A methodological approach combining Correspondence Factor Analysis and Nonlinear Mapping (NLM) was used for extracting origin/maturity information from these data. It allowed to benefit from the advantages of both methods. The use of such a multivariate data analysis appeared much more efficient than the use of molecular ratios that can be too restrictive and mask specific distribution patterns. This approach performed on the set of natural samples clearly demonstrated the discrimination between the samples through the presence of specific methyl-, dimethyl-, and trimethylphenanthrene isomers as origin/maturity markers. Based on MP, DMP, and TMP distributions, it is possible to distinguish the variations in organic matter type from the effects of thermal maturation. Some substituted phenanthrenes in each isomer series appear as characteristic of the two studied systems: The Aquitaine basin as representative of a marine carbonate environment and the Mahakam delta as representative of a terrestrial environment (higher plants). These compounds could be tentatively related to natural precursors such as triterpenoids or hopanoids.

A novel type of oil-generating organic matter — Crystal-enclosed organic matter

The comparative study of organic matter in carbonate rocks and argillaceous rocks from the same horizon indicates that the organic thermal maturities of carbonate rocks are much lower than those of argillaceous rocks. And extensive analysis of extracted and inclused organic matter from the same sample shows that inclused organic matter is different from extracted organic matter, and the thermal maturity of the former is usually lower than that of the latter in terms of biomarker structural parameters. It seems that carbonate minerals could preserve organic matter and retard organic maturation. The inclused organic matter, abundant in most carbonate rocks, will be released from minerals and transformed into oil and gas during the high thermal maturity stage.

Characterization of coal-derived hydrocarbons and source-rock potential of coal beds, San Juan Basin, New Mexico and Colorado, U.S.A.

Coal beds are considered to be a major source of nonassociated gas in the Rocky Mountain basins of the United States. In the San Juan basin of northwestern New Mexico and southwestern Colorado, significant quantities of natural gas are being produced from coal beds of the Upper Cretaceous Fruitland Formation and from adjacent sandstone reservoirs. Analysis of gas samples from the various gas-producing intervals provided a means of determining their origin and of evaluating coal beds as source rocks. The rank of coal beds in the Fruitland Formation in the central part of the San Juan basin, where major gas production occurs, increases to the northeast and ranges from high-volatile B bituminous coal to medium-volatile bituminous coal ( R m values range from 0.70 to 1.45%). On the basis of chemical, isotopic and coal-rank data, the gases are interpreted to be thermogenic. Gases from the coal beds show little isotopic variation ( δ 13C 1 values range −43.6 to −40.5 ppt), are chemically dry (C 1/C 1–5 values are > 0.99), and contain significant amounts of CO 2 (as much as 6%). These gases are interpreted to have resulted from devolatilization of the humic-type bituminous coal that is composed mainly of vitrinite. The primary products of this process are CH 4, CO 2 and H 2O. The coal-generated, methane-rich gas is usually contained in the coal beds of the Fruitland Formation, and has not been expelled and has not migrated into the adjacent sandstone reservoirs. In addition, the coal-bed reservoirs produce a distinctive bicarbonate-type connate water and have higher reservoir pressures than adjacent sandstones. The combination of these factors indicates that coal beds are a closed reservoir system created by the gases, waters, and associated pressures in the micropore coal structure. In contrast, gases produced from overlying sandstones in the Fruitland Formation and underlying Pictured Cliffs Sandstone have a wider range of isotopic values ( δ 13C 1 values range from −43.5 to −38.5 ppt), are chemically wetter (C 1/C 1–5 values range from 0.85 to 0.95), and contain less CO 2 (< 2%). These gases are interpreted to have been derived from type III kerogen dispersed in marine shales of the underlying Lewis Shale and nonmarine shales of the Fruitland Formation. In the underlying Upper Cretaceous Dakota Sandstone and Tocito Sandstone Lentil of the Mancos Shale, another gas type is produced. This gas is associated with oil at intermediate stages of thermal maturity and is isotopically lighter and chemically wetter at the intermediate stage of thermal maturity as compared with gases derived from dispersed type III kerogen and coal; this gas type is interpreted to have been generated from type II kerogen. Organic matter contained in coal beds and carbonaceous shales of the Fruitland Formation has hydrogen indexes from Rock-Eval pyrolysis between 100 and 350, and atomic H:C ratios between 0.8 and 1.2. Oxygen indexes and atomic O:C values are less than 24 and 0.3, respectively. Extractable hydrocarbon yields are as high as 7,000 ppm. These values indicate that the coal beds and carbonaceous shales have good potential for the generation of liquid hydrocarbons. Voids in the coal filled with a fluorescent material that is probably bitumen is evidence that liquid hydrocarbon generation has taken place. Preliminary oil-source rock correlations based on gas chromatography and stable carbon isotope ratios of C 15+ hydrocarbons indicate that the coals and (or) carbonaceous shales in the Fruitland Formation may be the source of minor amounts of condensate produced from the coal beds at relatively low levelsof thermal maturity ( R m =0.7).