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An advanced method for pyritic and organic sulphur quantification in organic rich sediments was developed using a Rock-Eval which was designed for sulphur quantification in addition to carbon quantification (Rock-Eval S). This new method involves data processing of parameters obtained via Rock-Eval S analysis of rock samples. It was applied to sedimentary mixtures with known organic and pyritic sulphur contents. The results show that this method allows an accurate quantification of both pyritic and organic sulphur in organic rich sediments that do not contain sulphates. This new method provides important analytical advantages, including (i) rapid analysis time (2 hours per sample); (ii) no chemical preparation steps, which are laborious and hazardous due to the use of strong acids; (iii) automatic analysis; and (iv) simultaneous quantification of organic/inorganic carbon and organic/inorganic sulphur in a single run.

An advanced method for pyritic and organic sulphur quantification was developed using a Rock-Eval 6 adapted for sulphur quantification in addition to carbon (Rock-Eval 6S). It consists in data processing of sulphur parameters obtained via Rock-Eval 6S analysis of a rock sample. This Rock-Eval 6S method for pyritic and organic sulphur quantification was applied on sets of organic rich sedimentary rock samples from the Grey Shale Member in North Yorkshire and from the Kimmeridge Clay Formation in Dorset. Results from the Rock-Eval 6S method were compared to results from another independent method based on elemental analysis. A good correlation between both methods is observed except for samples with low pyritic and organic sulphur contents. This new Rock-Eval 6S method for pyritic and organic sulphur quantification provides important advantages compared to the elemental analysis method, including: rapid analysis time (2 hours per sample); no chemical preparation steps, which are heavy and dangerous procedures due to the use of strong acids; automatic analysis; combined quantification of organic/inorganic carbon and organic/inorganic sulphur in a single run.

The hypothesis of a low temperature natural “vulcanization” process as a potential mechanism for the formation of insoluble bitumen and H2S in reservoirs which have not undergone biodegradation, high thermal stress, or thermochemical sulfate reduction (TSR) has been investigated using laboratory simulation experiments. The experiments, involving elemental sulfur (32S and 34S), a low maturity oil and water at 200 °C in sealed gold tubes, clearly showed that elemental sulfur is able to induce the formation of H2S, polar compounds (resins and asphaltenes) and insoluble bitumen most likely by way of sulfur cross-linking processes. Specific organic sulfur compounds (thiophenes, dithiophenes and thienothiophenes) formed by the reaction of sulfur and hydrocarbons may be potential markers of such a process, but remain to be detected in natural samples.

The sulfur isotopic composition (δ34S) of petroleum is believed to be affected mainly by sulfur incorporation reactions into the sedimentary organic matter during the early diagenesis. However, secondary processes could affect the original δ34S of oil under the effect of thermal maturity or of the microbial activity of biodegraded reservoirs. In this study, the different processes that may affect the δ34S of in-reservoir oils were assessed based on the sulfur content and isotopes of a series of oil and core samples coming from various reservoirs of the Lower Cretaceous Mannville Group, Western Canada Sedimentary Basin (WCSB). Based on the molecular study, these samples appear to have reached various levels of maturity and biodegradation, ranging from 0 to 6.5 on the biodegradation scale of Peters and Moldowan. In addition, mixing of organic matter coming from different source rocks was identified based on the comparison with extensive correlation studies performed in the WCSB. Investigation of the δ34S shows a trend that seems a priori correlated to the level of biodegradation. However, a careful interpretation of molecular and sulfur isotope data leads to the conclusion that the observed δ34S variations have rather to be ascribed to contributions of oils generated by various source rocks. Alternatively, variations of δ34S could neither be related to maturity differences nor to kinetic effects during organic sulfur compounds biodegradation. In the case of some specific core samples showing a common origin based on biomarker study, δ34S variations might not be related to different sources but to secondary sulfur incorporation/exchange processes occurring within the reservoir. These processes would involve reduced sulfur species from bacterial sulfate reduction formed in situ or migrated into Mannville reservoirs. This hypothesis is supported by laboratory experiments showing sulfur exchange/incorporation under plausible conditions for shallow reservoirs.

Thermochemical sulfate reduction (TSR) is usually associated with significant sour gas (H 2 S) generation and calcite precipitation in deep and hot carbonate reservoirs as a result of reaction between sulfate minerals (primarily anhydrite) and petroleum fluids at elevated temperature (beginning at ∼110-140°C). Thermal enhanced oil recovery (TEOR) techniques are widely applied during production to increase heavy oil recovery in mature fields by lowering oil viscosity. The reservoir rock may reach high temperature (150 °C < T< 300 °C) during steam and hot water flooding for secondary oil recovery that induces TSR. Experimental (pyrolysis in gold tubes) and numerical (0D fluid-rock interaction numerical model: ArXim) simulations were undertaken with a simple petroleum system assimilated to n-alkane model compounds in the presence of sulfate to assess the feasibility of "induced TSR" and to tentatively estimate the sulfur risk in terms of H 2 S and organosulfur compound (OSC) formation during steam and hot water stimulated enhanced recovery operations. The oxidation of organic matter (by reaction with both S° and sulfate) can be easily reproduced under laboratory conditions, as confirmed by the presence of organic sulfur in the soluble and insoluble residue. For the experiments performed in the presence of sulfate, higher amounts of H 2 S, polar compounds and organic residue are produced, and aromatic fractions are enriched in condensed aromatics (sulfur-containing and non-sulfur-containing). Although sulfate reduction from 3% to 5% is deduced from a sulfur balance calculation, no secondary carbonate is detected using X-ray diffraction (XRD). Numerical simulations suggest no limiting thermodynamic factor for the precipitation of carbonate under our experimental conditions and indicate the replacement of sulfate by carbonate. According to numerical data, the lack of carbonate can be explained by its slow growth and/or high energy barrier of nucleation and/or insufficient residence time in laboratory experiments.

Two bridgehead-alkylated 2-thiaadamantanes (1,5-dimethyl and 1-methyl) have been identified in petroleum; these compounds give clues to sulfurisation processes affecting petroleum which has undergone high thermal stress.