Bound carboxylic acids in the Alberta oil sands

The Alberta oil sands contain 1–2% organic solvent insoluble organic matter chemisorbed to the inorganic matrix. Analysis of the monocarboxylic fraction (1–14%) of the chemisorbed material has revealed the presence of C₁₂–C₃₂ normal, iso, anteiso alkenoic acids, mono and diunsaturated acids, cyclopropylalkanoic and cyclic terpenoid carboxylic acids. Some of the main components of the acyclic acids were similar to those which have been identified in various petroleums and Alberta oil sand bitumens (in small concentrations) by Mackenzie et al. (Advances in Organic Geochemistry 1981, pp 637–649, Wiley/Heyden, 1983), and attributed to bacterial degradation of the oils via the aerobic pathway of biosynthesis.The presence of these acids in the chemisorbed fraction and virtual absence in the bitumen lends additional support to earlier proposals that the Alberta oil sand bitumens have undergone severe microbial degradation.     

Evidence for in situ methanogenic oil degradation in the Dagang oil field

In situ biotransformation of oil to methane was investigated in a reservoir in Dagang, China using chemical fingerprinting, isotopic analyzes and molecular and biological methods. The reservoir is highly methanogenic despite chemical indications of advanced oil degradation, such as depletion of n-alkanes, alkylbenzenes and light polycyclic aromatic hydrocarbon (PAH) fractions or changes in the distribution of several alkylated polycyclic aromatic hydrocarbons. The degree of degradation strongly varied between different parts of the reservoir, ranging from severely degraded to nearly undegraded oil compositions. Geochemical data from oil, water and gas samples taken from the reservoir are consistent with in situ biogenic methane production linked to aliphatic and aromatic hydrocarbon degradation. Microcosms were inoculated with production and injection waters in order to characterize these processes in vitro. Subsequent degradation experiments revealed that autochthonous microbiota are capable of producing methane from ¹³C labelled n-hexadecane or 2-methylnaphthalene and suggest that further methanogenesis may occur from the aromatic and polyaromatic fractions of Dagang reservoir fluids. The microbial communities from produced oil–water samples were composed of high numbers of microorganisms (on the order to 10⁷), including methane producing Archaea within the same order of magnitude. In summary, the investigated sections of the Dagang reservoir may have significant potential for testing the viability of in situ conversion of oil to methane as an enhanced recovery method and biodegradation of the aromatic fractions of the oil may be an important methane source.     

Origin and alteration of oils and oil seeps from the Sinú-San Jacinto Basin, Colombia

Liquid hydrocarbons have been detected in the subsurface as well as in the surface in the Sinú-San Jacinto Basin (northwestern Colombia). The origin of the oils has not been conclusively established especially in the southern part of the basin. The most likely source rocks in the basin are the Ciénaga de Oro Fm. of the Oligocene-Early Miocene and the Cansona Fm. of the Upper Cretaceous. In this study, oil samples, seeps and source rock extracts were analyzed by GC and GC/MS, and δ¹³C was determined to identify the source facies. The sulphur content and gravity data were also considered.Two organic facies were identified: one constituted by terrestrial organic matter deposited in siliciclastic sediments in marginal marine to deltaic environments and the other made up of marine organic matter deposited in marine costal shelf to pelagic environments. The oils from the former organic facies have low sulphur contents, whereas the oils from the latter facies have high sulphur levels. Correlation of the oil seeps from the former facies with the Ciénaga de Oro Fm. has not been clearly established. The oil seeps from the latter facies correlate well with the extracts from the source rocks of the Cansona Fm., deposited along the fold belt of San Jacinto (east side). The oil seeps are affected by moderate to severe biodegradation, whereas the oil from the only oil producing well in the Sinú Basin (Floresanto-6 well) has not undergone biodegradation.     

Generation of aliphatic acid anions and carbon dioxide by hydrous pyrolysis of crude oils

Two crude oils with relatively high (0.60 wt%) and low (0.18 wt%) oxygen contents were heated in the presence of water in gold-plated reactors at 300°C for 2348 h. The high-oxygen oil was also heated at 200°C for 5711 h. The compositions of aqueous organic acid anions of the oils and of the headspace gases were monitored inn order to investigate the distribution of organic acids that can be generated from liquid petroleum.The oil with higher oxygen content generated about five times as much organic anions as the other oil. The dominant organic anions produced were acetate, propionate and butyrate. Small amounts of formate, succinate, methyl succinate and oxalate were also produced. The dominant oxygen-containing product was CO₂, as has been observed in similar studies on the hydrous pyrolysis of kerogen. These results indicate that a significant portion (10–30%) of organic acid anions reported i be generated by thermal alteration of oils in reservoir rocks. The bulk of organic acid anions present in formation waters, however, is most likely generated by thermal alteration of kerogen in source rocks. Kerogen is more abundant than oil in sedimentary basins and the relative yields of organic acid anions reported from the hydrous pyrolysis of kerogen are much higher than the yields obtained for the two oils.     

Application of sulfur and carbon isotopes to oil–source rock correlation: A case study from the Tazhong area,Tarim Basin,China

Up until now, it has been assumed that oil in the Palaeozoic reservoirs of the Tazhong Uplift was derived from Upper Ordovician source rocks. Oils recently produced from the Middle and Lower Cambrian in wells ZS1 and ZS5 provide clues concerning the source rocks of the oils in the Tazhong Uplift, Tarim Basin, China. For this study, molecular composition, bulk and individual n-alkane δ¹³C and individual alkyl-dibenzothiophene δ³⁴S values were determined for the potential source rocks and for oils from Cambrian and Ordovician reservoirs to determine the sources of the oils and to address whether δ¹³C and δ³⁴S values can be used effectively for oil–source rock correlation purposes. The ZS1 and ZS5 Cambrian oils, and six other oils from Ordovician reservoirs, were not significantly altered by TSR. The ZS1 oils and most of the other oils, have a “V” shape in the distribution of C₂₇–C₂₉ steranes, bulk and individual n-alkane δ¹³C values predominantly between −31‰ to −35‰ VPDB, and bulk and individual alkyldibenzothiophene δ³⁴S values between 15‰ to 23‰ VCDT. These characteristics are similar to those for some Cambrian source rocks with kerogen δ¹³C values between −34.1‰ and −35.3‰ and δ³⁴S values between 10.4‰ and 21.6‰. The oil produced from the Lower Ordovician in well YM2 has similar features to the ZS1 Cambrian oils. These new lines of evidence indicate that most of the oils in the Tazhong Uplift, contrary to previous interpretations, were probably derived from the Cambrian source rocks, and not from the Upper Ordovician. Conversely, the δ¹³C and δ³⁴S values of ZS1C Cambrian oils have been shown to shift to more positive values due to thermochemical sulfate reduction (TSR). Thus, δ¹³C and δ³⁴S values can be used as effective tools to demonstrate oil–source rock correlation, but only because there has been little or no TSR in this part of the section.     

Artificial bacterial degradation and hydrous pyrolysis of suberin: Implications for hydrocarbon generation of suberinite

The organic maceral suberinite is widely believed to be a contributor to immature or low mature oils with R_o < 0.5% in some coal and terrigenous sequences. However, its evolution of hydrocarbon generation, especially in the relatively high maturation stage of R_o > 0.5%, has not been sufficiently characterized. This issue was addressed herein using periderm cork tissues of the modern angiosperm Quercus suber (suberin), which is a possible bio-precursor of suberinite, in artificial bacterial degradation and hydrous pyrolysis experiments. Integrated studies were conducted, including analyses on the compositions of hydrocarbon yields and the content variations that were generated during the experiments, gas chromatography (GC) analyses of generated oils and spectral fluorescence observations, and Rock-Eval and Fourier Transform Infrared (FTIR) microspectroscopic studies on solid residues. Analytical results indicate that suberin and suberinite have long and complex hydrocarbon generation histories. In general, the hydrocarbon that is generated during bacterial degradation is predominantly gas and present in relatively limited amounts, while the oils mainly are generated during hydrous pyrolysis. Furthermore, the oil generation has two peaks that correspond to R_o of approximately 0.35–0.50% and 0.80–1.10%. In composition, the early generated oil mainly consists of long chain waxy and oxygen containing compounds, while the late generated oil is relatively enriched in aromatic compounds. These features can be ascribed to the chemical nature (e.g., composition and structure) of suberin. It is a type of insoluble and high molecular weight polyester compound that contains large quantities of long chain structure dicarboxylic acids and alcohols. Consequently, the deoxygenization of these compounds can take place under relatively low thermodynamic conditions, generating liquid oil that is dominated by a long chain structure and oxygen-containing waxy compounds. In contrast, the degradation of the phenolic compounds results in the second oil generation peak. Therefore, suberinite has a two stage and relatively long oil generation history and is a good bio-precursor for coal-derived oil generation.     

Demethylated hopanes in crude oils and their applications in petroleum geochemistry

Analyses of some Australian crude oils show that many contain varying concentrations of A/ B-ring demethylated hopanes. These range from C₂₆ to C₃₄ and have been identified from their retention times and mass spectral data as 17α(H)-25-norhopanes. Comparison of hopane and demethylated hopane concentrations and distributions in source-related, biodegraded oils suggests that demethylated hopanes are biotransformation products of the hopanes. Further, it appears that the process occurs at a late stage of biodegradation, after partial degradation of steranes has occurred. Demethylated hopanes are proposed as biomarkers for this stage of severe biodegradation. The presence of these compounds in apparently undegraded crude oils is thought to be due to the presence of biodegraded crude oil residues which have been dissolved by the undegraded crude oil during accumulation in the reservoir sands. The timing of hopane demethylation, relative to the degradation of other compounds, has been assessed and the progressive changes in crude oil composition with increasing extent of biodegradation have been identified. The use of demethylated hopanes as maturity parameters for severely biodegraded crude oils, and the applicability of established biomarker maturity parameters to such oils, are also discussed.     

Induced degradation of crude oil mediated by microbial augmentation and bulking agents

Different bacterial and fungal strains, isolated from petroleum hydrocarbon-contaminated soil, were tested, in isolation as well as in combination, for their ability to degrade total petroleum hydrocarbon (TPH) in soil samples spiked with crude oil (2, 5 or 10 %, w/w) for 30 days. The selected combination of bacterial and fungal isolates, i.e., Pseudomonas stutzeri BP10 and Aspergillus niger PS9, exhibited the highest efficiency of TPH degradation (46.7 %) in soil spiked with 2 % crude oil under control condition. Further, when this combination was applied under natural condition in soil spiked with 2 % (w/w) crude oil along with inorganic fertilizers (NPK) and different bulking agents such as rice husk, sugarcane, vermicompost or coconut coir, the percent degradation of TPH was found to be maximum (82.3 %) due to the presence of inorganic fertilizers and rice husk as bulking agent. Further, results showed that the presence of NPK and bulking agents induced the activity of degradative enzymes, such as catalase (0.718 m mol H₂O₂ g^?1), laccase (0.77 µmol g^?1), dehydrogenase (37.5 µg g^?1 h^?1), catechol 1, 2 dioxygenase (276.11 µ mol g^?1) and catechol 2, 3 dioxygenase (15.15 µ mol g^?1) as compared to control (without bioaugmentation). It was inferred that the selected combination microbes along with biostimulants could accentuate the crude oil degradation as evident from the biostimulant-induced enhanced activity of degradative enzymes.     

The origin of nitriles in shale oil

Because nitriles are unlikely to occur naturally in a geological environment but have been reported as being present in some shale oils their origin was investigated. A careful infrared study could find no trace of the nitriles in the shale but it was shown, by infrared and gas chromatography with a nitrogen sensitive detector, that they do occur in some but not all oils. They are formed in the pyrolysis process by the reaction of car?ylic acids and ammonia liberated from minerals such as ammonium feldspars present in the shale. If both species are not present nitriles are not formed in the product oil. Pyrolysis of a brown coal, Loy Yang, in the presence of ammonia produced nitriles but none were generated when a more mature coal (Metropolitan) was similarly treated.     

Characterization of hydrothermally generated oil from the Uzon caldera,Kamchatka

This paper reports the analyses of unusual oils that accumulate in the Uzon Caldera, situated in the central volcanic region of Kamchatka, Russia. Gas chromatography–mass spectrometry (GC–MS) was used to determine the primary constituents, and the ¹³C and ¹⁴C compositions provided information about the potential source and age of the oils. The ¹⁴C ages determined are 1030 ± 40 a BP (measured) or 940 ± 40 a BP (conventional). The δ¹³C value is −30.6‰ versus the PDB standard, a value consistent with a biological origin. The nearly contemporary age of the C content indicates a geologically recent origin from biogenic detritus and not by synthesis from mantle C. The biogenic origin is supported by the presence of sterane and hopane biomarkers and the δ¹³C value of the bulk oil. The overall compositions of the oils indicate that they are derived from rapid hydrothermal alteration of algal/bacterial mat detritus buried by volcanic ashfall deposits of the Uzon Caldera. The oils represent the youngest hydrothermal petroleum reported to date.     

Molecular correlation of free oil,adsorbed oil and inclusion oil of reservoir rocks in the Tazhong Uplift of the Tarim Basin,China

The free, adsorbed and inclusion oils were recovered by sequential extraction from eleven oil and tar containing reservoir rocks in the Tazhong Uplift of Tarim Basin. The results of gas chromatography (GC) and GC–mass spectrometry analyses of these oil components and seven crude oils collected from this region reveal multiple oil charges derived from different source rocks for these oil reservoirs. The initially charged oils show strong predominance of even over odd n-alkanes in the range n-C₁₂ to n-C₂₀ and have ordinary maturities, while the later charged oils do not exhibit any predominance of n-alkanes and have high maturities. The adsorbed and inclusion oils of the reservoir rocks generally have high relative concentrations of gammacerane and C₂₈ steranes, similar to the Cambrian-Lower Ordovician source rocks. In contrast, the free oils of these reservoir rocks generally have low relative concentrations of gammacerane and C₂₈ steranes, similar to the Middle-Upper Ordovician source rocks. There are two interpretations of this result: (1) the initially charged oils are derived from the Cambrian-Lower Ordovician source rocks while the later charged oils are derived from the Middle-Upper Ordovician source rocks; and (2) both the initially and later charged oils are mainly derived from the Cambrian-Lower Ordovician source rocks but the later charged oils are contaminated by the oil components from the Silurian tar sandstones and the Middle-Upper Ordovician source rocks.     

Origin of sulfur rich oils and H2S in Tertiary lacustrine sections of the Jinxian Sag,Bohai Bay Basin,China

Very high S oils (up to 14.7%) with H₂S contents of up to 92% in the associated gas have been found in the Tertiary in the Jinxian Sag, Bohai Bay Basin, PR China. Several oil samples were analyzed for C and S stable isotopes and biomarkers to try to understand the origin of these unusual oil samples.The high S oils occur in relatively shallow reservoirs in the northern part of the Jinxian Sag in anhydrite-rich reservoirs, and are characteristic of oils derived from S-rich source rocks deposited in an enclosed and productive stratified hypersaline water body. In contrast, low S oils (as low as 0.03%) in the southern part of the Jinxian Sag occur in Tertiary lacustrine reservoirs with minimal anhydrite. These southern oils were probably derived from less S-rich source rocks deposited under a relatively open and freshwater to brackish lake environment that had larger amounts of higher plant inputs.The extremely high S oil samples (>10%) underwent biodegradation of normal alkanes resulting in a degree of concentration of S in the residual petroleum, although isoprenoid alkanes remain showing that biodegradation was not extreme. Interestingly, the high S oils occur in H₂S-rich reservoirs (H₂S up to 92% by volume) where the H₂S was derived from bacterial SO₄ reduction, most likely in the source rock prior to migration. Three oils in the Jinxian Sag have δ³⁴S values from +0.3‰ to +16.2‰ and the oil with the highest S content shows the lightest δ³⁴S value. This δ³⁴S value for that oil is close to the δ³⁴S value for H₂S (∼0‰). It is possible that H₂S was incorporated into functionalized compounds within the residual petroleum during biodegradation at depth in the reservoir thus accounting for the very high concentrations of S in petroleum.     

The scope for generating bio-oils with relatively low oxygen contents via hydropyrolysis

The primary oils obtained in high yields from fast (fluidised-bed) pyrolysis of biomass generally have high oxygen contents (ca. 40% w/w). The scope for using pyrolysis under hydrogen pressure (hydropyrolysis), to give oils with much lower oxygen contents compared to normal pyrolysis has been investigated. Fixed-bed hydropyrolysis tests have been conducted on cellulose, sugar cane bagasse and eucalyptus wood using hydrogen pressures up to 10 MPa, with heating rates of 5 and 300°C min⁻¹. A colloidal FeS catalyst was used in some tests (Fe loading of 5%, w/w) to increase overall conversions. Further, the attractive option of using a two-stage reactor in which the primary oil vapors are passed though a bed of hydrotreating catalyst is also described. Raising the hydrogen pressure from atmospheric to 10 MPa reduced the oxygen content of the primary oil by over 10% to below 20% w/w. The addition of a dispersed iron sulphide catalyst gave conversions close to 100% for all three biomass samples investigated at 10 MPa under conditions in the fixed-bed reactor where significant diffusional resistances existed and reduced the oxygen content of the bio-oil by a further 10%. Although NMR indicated that the oils became increasingly aromatic as more oxygen was removed, the increase in hydrogen pressure decreased the extent of overall aromatisation that occurs primarily due to the lower char yields obtained. In two-stage tests for cellulose, using a commercial sulphided Ni/Mo γ-Al₂O₃ catalyst at 400°C, increasing the hydrogen pressure from 2.5 to 10 MPa decreased the oxygen content of the oil by over 20% to 10% w/w. The H/C ratios were higher and O/C ratios smaller for the two-stage bio-oils compared to their single stage counterparts. However, the differences in the O/C ratios between the single and two-stage bio-oils increase with pressure.     

On the usefulness of sulfur isotope ratios in crude oil correlations

Sulfur isotope analyses have been completed for twelve samples of marine Jurassic oils from a single basin, and are presented along with previous chemical analyses of the same oils (Seifert and Moldowan, 1978). Two isotopic anomalies are discussed in light of correlational analyses, and show that sulfur isotope ratios, when used with other chemical variables, are sensitive indicators of subtle changes in initial source input. Measurements of δ³⁴S in correlational studies of crude oil characterization and identification are recommended.     

The nature of scattered and concretion pyrite in the Upper Abalak Formation of the Salym oil field (Western Siberia)

Dispersed and concretionary pyrite in chert–clay–carbonate and carbonate rocks of the Abalak Formation (Salym oil field) have been studied. The study was conducted using Scanning Electron Microscopy (SEM), Electron Probe Microanalysis (EPMA), and high spatial resolution Secondary Ion Mass Spectrometry (Nano-SIMS). As a result, three morphological groups of pyrite have been distinguished: large cubic crystals, framboidal pyrite, and fine-crystal aggregates that replace organic remnants. The sulphur isotope ratio allows one to distinguish two genetic types of pyrite. The source of the sulphur for the first genetic group was H₂S produced by bacterial sulphate reduction, while the second group pyrite was formed with sulphur as a product of thermochemical sulphate reduction.     

Biomarker signatures from Neoproterozoic–Early Cambrian oil,western India

The Neoproterozoic–Early Cambrian time is the cradle of multicellular, eukaryotic life and thereafter metazoan life started populating the planet. Biomarkers, which record the chronicles of biotic events on Earth, have been investigated using gas chromatography–mass spectrometry from a suite of nine oil samples extracted from oil stained sediments and a crude oil of Neoproterozoic–Early Cambrian age from Bikaner-Nagaur Basin, western India. The biomarker distribution is characterized by high concentration of both tricyclic terpanes and pentacyclic hopanes. The predominance of C₂₉ regular sterane over C₂₇ and C₂₈ steranes indicates green algal contribution and may imply the prominence and diversification of the same algal group. The low pristane/phytane ratio and occurrence of substantial quantity of gammacerane, monomethyl 2-methyl-2-(2,4,8-trimethyltridecyl) chroman and 1,1,7,8-tetramethyl-1,2,3,4 tetrahydrophenanthrene are indicative of stratified water column as well as anoxic and enhanced salinity condition of the environment of deposition. This paper reports for the first time the presence of methyltrimethyltridecyl chromans (MTTCs) from Neoproterozoic–Early Cambrian time. Putative C₁₉ norsteranes, probably indicative of sponge input, are recorded in the studied samples and also reported from other infracambrian oils and sediments. Normal alkanes (n-C₁₇ and n-C₁₈) and isoprenoids (pristane and phytane) are highly depleted in δ¹³C. The overall biomarker distribution and carbon isotope data of oils from Bikaner-Nagaur Basin show similarities with those of other infracambrian oils like Huqf oils from Oman and Baykit High oils from eastern Siberia.     

Geochemical analysis of mixed oil in the Ordovician reservoir of the Halahatang Depression, Tarim Basin, China

In this study,12 crude oil samples were collected and analyzed from the Ordovician reservoir in the Halahatang Depression,Tarim Basin,China.Although the density of oil samples varies considerably,based on saturated hydrocarbon gas chromatographic(GC),saturated and aromatic hydrocarbon gas chromatographic-mass spectrometric(GC/MS) and stable carbon isotopic composition analyses,all the samples are interpreted to represent a single oil population with similar characteristics in a source bed or a source kitchen,organic facies and even in oil charge history.The co-existence of a full suite of n-alkanes and acyclic isoprenoids with UCM and 25-norhopanes in the crude oil samples indicates mixing of biodegraded oil with fresher non-biodegraded oil in the Ordovician reservoir.Moreover,according to the conversion diagram of double filling ratios for subsurface mixed crude oils,biodegraded/non-biodegraded oil ratios were determined as in the range from 58/42 to 4/96.Based on oil density and oil mix ratio,the oils can be divided into two groups:Group 1,with specific density>0.88(g/cm3) and oil mix ratio>1,occurring in the north of the Upper Ordovician Lianglitage and Sangtamu Formation pinchout lines,and Group 2,with specific density<0.88(g/cm3) and oil mix ratio<1,occurring in the south of the pinchout lines.Obviously,Group 2 oils with low densities and being dominated by non-biodegraded oils are better than Group 1 oils with respect to quality.It is suggested that more attention should be paid to the area in the south of the Upper Ordovician Lianglitage and Sangtamu Formation pinchout lines for further exploration.     

Coal as a source rock for oil: a review

The geological debate about whether, and to what extent, humic coals have sourced oil is likely to continue for some time, despite some important advances in our knowledge of the processes involved. It is clear that not only liptinites, but also perhydrous vitrinites have the potential to generate hydrocarbon liquids in the course of natural coalification. Some liptinites, especially alginite, cutinite, and suberinite, contain a higher proportion of aliphatic moieties in their structure than other liptinites such as sporinite and resinite and are, therefore, more oil-prone. It is of potential value to be able to predict the several environments of deposition in which coals with high liptinite contents or containing perhydrous vitrinites may have been formed. Review of the distribution of oil-prone coals in time and space reveals that most are Jurassic–Tertiary with key examples from Australia, New Zealand, and Indonesia. Methods based both on experimental simulations and the examination of naturally matured samples have been used to determine the order of generation of hydrocarbons from different macerals. Results are not entirely consistent among the different approaches, and there is much overlap in the ranges of degradation, but it seems probable that in the natural environment vitrinites begin to generate early, followed by labile liptinites such as suberinite, then cutinite, sporinite, and, finally, alginite.Petroleum potential may be determined by experimental simulation of natural coalification or inferred through various micro-techniques, especially fluorescence and infrared (IR) spectroscopy, or bulk techniques such as elemental analysis and ¹³C NMR spectroscopy. The latter three techniques enable a measure of the polymethylene component of the coal, which now appears to be one of the best available approaches for determining petroleum potential. No method of experimental simulation of petroleum generation from coals is without criticism, and comparative results are highly variable. However, hydrous pyrolysis, confined pyrolysis, and forms of open-system hydrous pyrolysis approach acceptable simulations.Whether, and to what degree generated liquid hydrocarbons are expelled, has long been the central problem in ‘oil from coal’ studies. The structure of vitrinite was believed until recently to contain an interconnected microporous network in which generated oil would be contained until an expulsion threshold was attained. Recent studies show the pores are not interconnected. Combined with a dynamic model of pore generation, it now seems that expulsion of hydrocarbons is best explained by activated diffusion of molecules to maceral boundaries and ultimately by cleats and fractures to coal seam boundaries. The main reason for poor expulsion is the adsorption of oil on the organic macromolecule, which may be overcome (1) if coals are thin and interbedded with clastic sediments, or (2) if the coals are very hydrogen-rich and generate large quantities of oil.The existence of oil in vitrinite is attested to by solvent extractions, fluorescence properties, and by microscopic observations of oil and bitumen. Experimental simulation of expulsion of oil from coals has only recently been attempted. The relative timing of release of generated CO₂ and CH₄ could have considerable importance in promoting the expulsion of liquid hydrocarbons but the mechanism is unclear. As it is universally agreed that dispersed organic matter (DOM) in some shales readily generates and expels petroleum, it is curious that few consistent geochemical differences have been found between coal macerals and DOM in interbedded shales.Unambiguous evidence of expulsion from coals is limited, and in particular only a few commercial oil discoveries can be confidently correlated to coals. These include Upper Cretaceous Fruitland Formation coals in the USA, from which oil is produced; New Zealand Tertiary coals; and Middle Jurassic coals from the Danish North Sea. It is likely that coals have at least contributed to significant oil discoveries in the Gippsland Basin, Australia; in the Turpan Basin, China; and in the Kutei and Ardjuna basins in Indonesia, but this remains unproven. Early reports that early Jurassic coals in mid-Norway were a major source of the reservoired oils have been shown to be inaccurate.None of the proposed ‘rules of thumb’ for generation or expulsion of petroleum from coals seem particularly robust. Decisions on whether a particular coal is likely to have been an active source for oil should consider all available geological and geochemical information. The assumptions made in computational models should be well understood as it is likely with new understandings of processes involved that some of these assumptions will be difficult to sustain.     

Correlation and migration studies of North Central Sumatra oils

The Central Sumatra Basin (CSB) is a prolific petroleum-producing basin and its petroleum systems have been extensively studied. The widely occurring Tertiary lacustrine shale, Brown Shale, has long been recognized as the main source rock for tens of billions of barrels of oil in place. The oils produced from different fields display significant variation in source characteristics that have been attributed to variation in source facies. Despite this generalized recognition of the oil source, the links between major oil accumulations and many possible source kitchens throughout the basin have not been established as detailed oil-source correlation, and oil migration routes are not well defined. For continued exploration in the region, detailed genetic grouping and migration routes of the oils were evaluated through geochemical characterization of numerous oils from various fields in the northern part of Central Sumatra. Biomarker and carbon isotopic data indicate that the oils are quite similar geochemically but form several genetic groups on the basis of subtle but persistent differences in source facies. The groupings appear geographically meaningful and show association of the different oil groups with various troughs. Carbazole distributions show consistency in suggesting differences in relative migration distance among the oils within each genetic group. By combining the oil grouping and carbazole distributions with geological data, models of migration directions and pathways for oils in North Central Sumatra have been constructed.