Abstract: Compound-specific isotope analysis (CSIA) of individual organic compounds is a powerful but underutilized tool in petroleum exploration. When integrated with other organic geochemical methodologies it can provide evidence of fluid histories including source, maturity, charge history and reservoir processes that can support field development planning and exploration efforts. The purpose of this chapter is to provide a review of the methodologies used for generating carbon and hydrogen isotope data for mid- and high-molecular-weight n -alkanes. We discuss the factors that control stable carbon and hydrogen isotope compositions of n -alkanes and related compounds in sedimentary and petroleum systems and review current and future applications of this methodology for petroleum exploration. We discuss basin-specific case studies that demonstrate the usefulness of CSIA either when addressing particular aspects of petroleum exploration (e.g. charge evaluation, source rock–oil correlation, and investigation of maturity and in-reservoir processes) or when this technique is used to corroborate interpretations from integrated petroleum systems analysis, providing unique insights which may not be revealed when using other methods. CSIA of n -alkanes and related n -alkyl structures can provide independent data to strengthen petroleum systems concepts from generation and expulsion of fluids from source rock, to charge history, connectivity, and in-reservoir processes.

Abstract Because the chemical composition of organic matter (OM) varies among different organisms, the biological source of OM can exert an important control on its preservation and influence the formation of petroleum source rocks. Molecular compounds derived from specific organisms, biomarkers, are a useful tool in the evaluation of the biological sources of organic matter to ancient sediments. Previous work has shown that organic matter in the Kimmeridge Clay Formation derives from a range of organisms, represented in the biomarker record by isotopically distinct n -alkanes, branched alkanes, and isoprenoids. Here we report the abundances of these compounds and other select biomarkers in the extractable-organic-matter fraction and the distribution of n -alkanes and isoprenoids in the kerogen; these data are used to determine the stratigraphic variation in the occurrence of different organic-matter assemblages through the lower hudlestoni biozone in a sediment core from Dorset, southern England. The TOC-normalized abundances of n -alkanes and specific methyl and isopropyl branched alkanes in the extract are relatively constant through the studied interval, suggesting that their contribution to sedimentary organic matter did not vary. In contrast, the occurrence of isoprenoid-rich kerogen and bitumen is largely restricted to discrete horizons, three of which were clearly identified in this study. Because changes in the abundance of extractable isoprenoids correlate with changes in the relative abundances of kerogen-bound isoprenoids, the former does reflect a change in the predominant source of organic matter during these intervals. However, the proportional abundances of isoprenoids in both the bitumen and kerogen correlate poorly with both TOC contents and TOC contents calculated on a carbonate-free basis, indicating that such variation in organic-matter source did not influence organic-matter preservation. Instead, a strong correlation between TOC contents and the relative abundance of unresolved complex mixtures released during pyrolysis and inferred to consist of S-bound organic matter suggests that the availability of sulfide was the main control on OM accumulation regardless of the predominant sources of organic matter.

ABSTRACT Advanced geochemical technologies (AGT) were applied to 12 oils from pre-salt formations (pre-salt oils) from the Santos Basin and compared to four post-salt reservoired oils. Three primary methods were used to categorize the oils: (1) diamondoid methods, that is, quantitative diamondoid analysis (QDA) and quantitative extended diamondoid analysis (QEDA); (2) biomarker analyses using gas chromatography–mass spectrometry–mass spectrometry (GCMSMS); and (3) compound specific isotope analysis of alkanes and hopanes plus tricyclic terpanes (CSIA-A and CSIA-Bh/CSIA-TT, respectively). Each method either provided new information or reinforced interpretations derived from other methods diminishing uncertainties in the overall interpretations. GCMSMS data suggested the preliminary source relationships for charges of early-to-middle oil-window maturity based on biomarker correlations. Those suggestions from GCMSMS data were either bolstered or more finely discriminated by the CSIA data. Data from diamondoid analyses gave insight into components that could not be described by biomarkers and the CSIA methods related to post-mature oil, oil cracking, and oil mixtures. QDA showed post-mature components for some oil samples, indicative of oil-window plus post-oil-window mixtures. QEDA showed that, in addition to one predominant lacustrine source, other lacustrine sources contributed to some of the pre-salt oil accumulations. Oils taken from pre-salt reservoirs in the study include samples from the following fields: Bem-Te-Vi, Sapinhoá, Jupiter, Mero, Buzios, Tingua, Tupi, Sururu, and Carcará. Biomarker and CSIA data confirm correlative relationships among nine pre-salt oils with source rocks deposited in brackish-to-saline water lacustrine depositional environments, putatively from the upper Barremian (Itapema Formation). Among those, QDA shows the samples from Tupi (three samples), Mero (two samples), and Jupiter to be of mixed maturity, including some normal oil-window plus post-mature cracked oil. Oils from Sapinhoá, Buzios, and Sururu fields show only the normal oil-window maturity. Oils from Bem-Te-Vi and Carcará correlate to a different source proposed to be the mid-to-late Aptian-sag lacustrine hypersaline system (Barra Velha Formation), of which the Carcará oil shows a major cracked component, whereas the Bem-Te-Vi oil does not. The oil from Tingua Field appears to be the lone representative of a fresh-to-brackish water system, putatively, the lower Barremian rift system (Piçarras Formation). Four oils from post-salt reservoirs recovered from Albian carbonates from the Guaruja Formation in the southern Santos Basin show contrasting biomarker, CSIA, and diamondoid (QEDA) patterns distinguishing them from any of the pre-salt oils. Taxon-specific biomarker parameters based on GCMSMS analysis are definitive for making those distinctions, including, for example, 24- n -propylcholestanes (marine algal steranes), dinosteranes concentrations (dinoflagellate steranes), and other A-ring methyl steranes and 24-norcholestanes (putatively diatom related). One of the highly cracked post-salt oils is an example of oil co-sourcing, showing features of both lacustrine and marine components in the biomarker and diamondoid parameters.

Abstract Stable isotope composition of gas is widely used in hydrocarbon exploration to determine the composition and thermal maturity of source rocks. Many isotope classification systems used for gas to source rock correlation and thermal maturity determination are primarily based on empirical observations made in conventional reservoirs and the kinetic isotope effects observed during pyrolysis experiments performed on source rocks. However, such relationships may not be readily applicable to onshore unconventional reservoirs due to the strong molecular and isotope fractionation that occur during extensive gas expulsion associated with basin uplift and depressurization. Degassing studies of freshly recovered core samples can provide useful insight into the behaviour of gas molecules in unconventional reservoirs during basin uplift. The analyses of Australian coal and marine shale samples demonstrate that during desorption both molecular and isotopic compositions of gas change at variable rates. Gas initially desorbed from the samples is mostly CH 4 , whereas later desorbed gas becomes increasingly enriched in C 2 H 6 and higher hydrocarbons. Hydrocarbon molecules also fractionate according to their isotopic composition, where the early released gas is enriched in 12 C causing the remaining gas in the reservoir to be enriched in the heavier 13 C isotope. During the release of gas from the Bowen Basin coals the C isotope ratio of CH 4 ( δ 13 C 1 ) changes by up to 21‰ (VPDB), whereas that for C 2 H 6 ( δ 13 C 2 ) and C 3 H 8 ( δ 13 C 3 ) changes by <6‰. Similar changes in the isotope composition can be seen during the release of gas from marine source rocks of the Beetaloo Sub-basin. In a fully gas-mature middle Velkerri shale sample, δ 13 C 1 changes by up to 28‰ and δ 13 C 2 by up to 3‰ with no appreciable change occurring in δ 13 C 3 . The extent of molecular fractionation during gas flow through carbonaceous rocks is primarily related to the adsorption–desorption properties of organic matter and diffusivity through the overall rock matrix. Using the current dataset, the magnitude of the contributions exerted by the desorption and diffusion processes cannot be readily distinguished. However, both Bowen Basin coals and Beetaloo Sub-basin shale show similar fractionation effects during gas flow, where the heavier alkane molecules, including those containing more 13 C, desorb and move slowly compared with the lighter components, in particular CH 4 . Different rates of isotope fractionation between hydrocarbon molecules during gas flow cause the shape of compound-specific-isotope (CSI) curve to change with time. Early released gas is characterized by a normal CSI trend where the short-chain hydrocarbons are isotopically lighter compared with the longer-chain hydrocarbons. Because CH 4 and C 2 H 6 molecules enriched in 12 C desorb and diffuse more readily than the heavier hydrocarbons (including those enriched 13 C), the gas remaining in the coal and shale samples after extensive desorption shows a reversed CSI trend where CH 4 and C 2 H 6 are isotopically heavier compared with the longer chain hydrocarbons. Reversed isotope trends may also develop over geological time, particularly where the source rock is fully gas-mature and has expelled hydrocarbons due to prolonged degassing. As seen in the Beetaloo Sub-basin, the CSI trend in the dry-gas-mature Velkerri shale is reversed, possibly due to the loss of a large proportion of originally generated CH 4 during post-Cambrian basin uplift.