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Foundational to source rock assessment in exploration is an understanding of organic enrichment and hydrocarbon generation potential. With an increased use of oil-based drilling mud, particularly in deep water drilling, problems associated with contamination have complicated source rock assessment. Drilling fluid contamination is assumed to increase the apparent values of the basic screening source rock parameters such as total organic carbon (TOC) and total hydrocarbon generation (S1 + S2). It has been commonly assumed that the effect of contamination can be reduced or eliminated by pre-treating samples with organic solvents (i.e., extraction of the sample) prior to analysis. In this study, an attempt is made to characterize this extraction process on a suite of simulated cuttings samples that were contaminated and extracted prior to analysis to validate the assumptions presented in the literature. Results from these experiments show significant differences between values measured on the original and oil-based drilling fluid contaminated samples before and after extraction. After contamination and before extraction, measured TOC and Rock-Eval parameters indicate that the oil-based drilling fluids appear to be acting as an aggressive solvent, altering the apparent source rock potential. Contamination by oil-based drilling fluid appears to reduce the total organic carbon content and the residual generation (S2) potential, while increasing the free hydrocarbon content. This may be a result of the presence of solid bitumen or bituminite in the original sample, which are acted on by the oil-based drilling fluid. Following extraction of the contaminated samples, the TOC and residual generation potential undergo further reduction and the free hydrocarbons were nearly eliminated. It was also observed that uncontaminated samples, when extracted, experienced an increase in TOC and the S3 (CO2) peak. These increases may have resulted from the retention of small amounts of solvent. Unlike the common assumption in the existing literature, these data indicate that once oil-based drilling fluids contaminate a sample, pre-treatment extraction does not provide an accurate measure of either the original organic carbon or residual generation potential. The data indicate that the use of Rock-Eval pyrolysis results from extracted samples that have been contaminated by oil-based drilling fluid can result in a significant underestimation of the system's hydrocarbon source rock potential.

The molecular and compound-specific isotopic composition of the n-alkanes in 30 oil samples from the Central Sumatra Basin were analyzed with the purpose of determining facies variations of the source rock in this basin. The oil samples were generated by the Eocene-Oligocene lacustrine Brown Shale Formation. Biomarkers in the oil samples indicate varying contributions from algal and terrigenous organic matter, primarily under oxic, or suboxic depositional conditions. Five source rock facies were identified based on the relative concentrations of n-alkanes, isoprenoids, tricyclic terpanes, and steranes. The individual facies were also distinguished by the compound-specific isotopic composition of the n-alkanes. Source rock depositional environments vary from deep lacustrine, shallow lacustrine, and lacustrine saline to coal and mixed coal and lacustrine shale. Deep lacustrine facies predominate in the Aman and Bengkalis troughs whereas saline and shallow lacustrine facies predominate in the South Aman and Kiri troughs, respectively. Oils derived from coal and mixed coal and lacustrine shale facies predominate in the northern part of the Central Sumatra Basin, in the Tanjung Medan and north of the Balam grabens.

Comparison of some Paleozoic and Mesozoic gas shales has revealed a generally common sequence stratigraphy, consisting of, from the base upward: combined sequence boundary/transgressive surface of erosion (SB/TSE) upon which sits a transgressive systems tract (TST) enriched in organic matter, then a somewhat ‘cleaner gamma-ray’ highstand or regressive systems tract (HST/RST). When resolvable, this stratigraphy occurs at 2nd, 3rd, and 4th order relative sea level cyclicity, forming couplets of relatively organic-rich (TST and condensed section-CS) and organic-poor (HST/RST) strata at these time scales. A higher order sequence stratigraphy can be developed for Mesozoic shales than for Paleozoic shales owing to greater biostratigraphic age resolution of the former. The higher frequency cycles are superimposed upon lower frequency cycles, giving rise to a complex stratigraphy of several couplets of differing thickness and distribution. These documented common characteristics provide the basis for a unifying, general sequence stratigraphic model for shales which can be utilized to identify, predict and map the most productive facies within a shale stratigraphic interval. There also are several commonalities in geochemistry of gas shales. Prolific gas shales are usually >200 ft (65 m) thick, contain >3% TOC, have Hydrogen Index values >350 mg HC/g, contain Type II kerogen and have organic maturity values >1.1% Ro. Organic-rich shales typically contain minerals such as pyrite and phosphates (apatite) and show biomarker ratios (pristane/phytane, steranes distribution, C13–C20 regular isoprenoids and C18 aryl isoprenoids) indicative of anoxic conditions during source rock deposition. In high maturity areas, there is a reversal in ethane isotope abundance owing to secondary cracking of hydrocarbons; such a reversal is normally associated with best gas production. Relative hydrocarbon potential (S1 + S2/TOC) is a geochemical parameter which reflects oxygenation conditions in the depositional environment. It can be related to relative sea level fluctuations within a sequence stratigraphic context. Understanding the sequence stratigraphy of shale provides a powerful tool not only for regional-to-local stratigraphic correlations from well logs and seismic reflection records, but also for high-grading stratigraphic intervals most favorable for preservation of organic matter and gas generation and storage.

The Central Sumatra Basin (CSB) is a prolific oil producing basin in Indonesia where a single source rock has been identified, the Brown Shale Formation of the Paleogene Pematang Group. Despite the presence of a single source rock, the oils in the Central Sumatra Basin and particularly in the Aman Trough, exhibit variable molecular and isotopic compositions, previously described as reflective of lateral facies variations within the source rock. Analyses by gas chromatography (GC), gas chromatography–mass spectrometry (GC–MS) and gas chromatography–isotope ratio mass spectrometry (GC–IRMS) of 15 oil samples from the Aman Trough allowed identification of vertical and lateral facies changes within the Brown Shale Formation as well as paleoproductivity and paleoclimatic changes that took place during deposition of this prolific source rock. The molecular and isotopic data indicate the source rock for these oils was deposited in a fresh to brackish water stratified lake in which CO 2 limiting conditions prevailed. Compound specific isotopic data also indicate that changes in paleoclimatic conditions, possibly associated with the Eocene–Oligocene paleoclimatic transition, had an effect on the geochemical composition of the source rock in the Aman Trough.

Molecular and isotopic compositions of 51 gas and 7 condensate samples produced from the Barnett Shale were determined by gas chromatography–isotope ratio mass spectrometry to investigate their origin and maturity at the time of generation. Additionally, two hydrous pyrolysis experiments were performed to calibrate maturity values predicted for gas generation. Molecular and carbon and hydrogen isotopic compositions of the gases indicate that gas produced from the Barnett is thermogenic. To estimate generation maturity, additional analyses were performed on the condensates and available core samples. Diamondoid indices combined with vitrinite reflectance (Ro) measurements, isotopic and molecular composition, and hydrous pyrolysis experiments suggest that gas produced from the Barnett Shale was generated within the condensate–wet gas window (1.3–2.0% Ro) at a later stage than hydrocarbons accumulated in shallower reservoirs. The origin of the gas is thermogenic, probably derived from both kerogen cracking and secondary cracking of previously generated nonmigrated hydrocarbons. Additionally, the occurrence of a methane isotope reversal in group 1 gases corroborates that in-situ oil or gas cracking is occurring in the easternmost part of the study area.