First EAGE/IFPEN Conference on Sulfur Risk Management in Exploration and Production

This work presents results of natural sour gas analysis and laboratory experiments that produce such gases and reveal sulfur isotope variability between individual OSCs that may represent key processes during formation and degradation of OSCs

We here demonstrate that abiotic and biotic sulfurization processes can concomitantly occur during the degradation of alkyl substrates by microbial sulfate-reduction (MSR), and that sulfurization of OM can lead to the formation of OSC that, in return, can potentially fuels MSR. It can thus be envisaged that, in some circumstances, MSR can 1) counterbalance the apparent recalcitrance of OSC formed abiotically by metabolizing them further into cell biomass and/or other less recalcitrant OSC and, 2) decrease the content in OSC (and thus increase the quality) of the preserved OM/oil. The biogeochemical importance of such processes still needs to be evaluated. In addition to the enlargement of the panel of interactions that can occur during OM diagenesis in hydrocarbon-containing anoxic sediments and oil reservoirs, our study opens up new perspectives on mechanistic aspects involved in the sulfurization under natural conditions of organic compounds that are supposed not reactive with inorganic sulfur species.

Sulfur is a key element of biogeochemical cycles, being both an essential component of living cells and involved in major geological processes. Its four stable isotopes (32S, 34S, 33S, 36S, in order of abundance) are subject to equilibrium and kinetic fractionations, which can be used as tracers to understand sulfur cycling processes. Multi-isotope studies noticeably revealed mass-independent fractionation processes of 33S and 36S, enlightening previously unknown specific organic or inorganic (bio)(geo)chemical mechanisms. Though the analytical procedures for the determination of S-multi-isotope compositions, which requires a quantitative extraction and purification of sulfur, are well-known for mineral sulfur species, the existing procedures for the extraction of organic sulfur are either restricted to specific species or technically restrictive. Here we propose a new chemical procedure for the quantitative recovery of organic sulfur in the form of Ag2S, for multi-isotope analysis, which is also compatible with the multi-isotope analysis of inorganic sulfur species from the same samples. This procedure is based on a standard sequence of reductive attacks specific of mineral sulfur species and was validated on various samples including fresh sediments, source rocks and oils.

For years reservoir souring has caused serious economic and environmental damages. High concentration of sulphate in seawater besides the presence of sulphate reducing microorganisms in both seawater and reservoir fluids are a major source of this issue. Even though most of the academic research studies and industrial report propose nitrate treatment as a favourable mitigation strategy, some reports introduce it as an inefficient method. As the available literature data have studied nitrate treatment in the lab scale, to assess nitrate treatment fairly, they cannot be used directly. Therefore, in this study, we use simulation to extend our understanding from the lab scale to the reservoir scale. Results show that if NRM are dominant nitrate reducer community in the reservoir, nitrate treatment strategy might not be promising. In the case that NRSOM are the dominant nitrate reducer community, there can be a concentration of nitrate that can inhibit reservoir souring. In fact, this concentration is the concentration for which carbon source is exhausted through sulphur cycling. Therefore, the success of nitrate treatment, in this case, might depend on the feasibility of injecting this nitrate concentration. Additionally, we suggest that nitrite inhibition mechanism is not of significance in the reservoir scale.

We present sulfur isotopic data for H2S from three different unconventional resource plays, the Haynesville, Eagle Ford, and Permian Basin, which produce dry gas, gas condensate and light oil respectively. Each play produces low levels of H2S, with sulfur derived from clearly defined but different sources. H2S in each of these cases was generated by different mechanisms, including both Bacterial (BSR) and Thermochemical Sulfate Reduction (TSR). A consistent theme observed in all three resource plays is that H2S generated by both BSR and TSR processes coexist at present day reservoir conditions. These conditions in some cases are too hot for BSR and/or too low for TSR. In one example, we show that TSR-generated H2S was likely formed on a production time scale due to elevated sulfate levels in water used for hydraulic fracturing. In the other two examples H2S was generated over geologic time and appears to persist as a mixture of H2S derived from two different reservoirs of sulfur, generated at different times relative to their burial and uplift histories.

Improved exploration strategies for the oil and gas fields involve high temperatures and pressures. This may induce Thermochemical Sulfate Reduction (TSR) risks. TSR is a complex succession of redox reactions that occur in deeply buried anhydrite-rich carbonate reservoirs under high temperatures. Such reactions lead to the formation of a high amount of H2S (toxic and corrosive gas) and a decrease in the quality of the hydrocarbons due to their oxidation. A new basin-scale approach was developed to compute a TSR risk index and, to assess the spatial distribution of H2S. The produced H2S can then be either dissolved in the formation water or released as a free gas phase. These two possibilities have been integrated into the TemisFlow™ software and were successfully applied to the Western Canadian Sedimentary Basin (WCSB). The Devonian carbonate reservoirs of WSCB are known to have experienced TSR reactions, some of them containing up to 30% of H2S. The obtained numerical results show high TSRI values for the Devonian petroleum system. These values increase with the burial associated to the Laramide orogeny. Our results are in agreement with the petrography analyses. Given our simulation criteria, the order of magnitude of average simulated H2S masses is the same as the one reported by Machel (2005).

Analyses of the multiple sulfur isotopes (δ33S, δ34S, δ36S) on the sulfur-rich minerals from the “Nappe des Gypses” formation (western French Alps), allow a better constrain on the TSR process. Small variations on ∆33S values highlight the conditions evolution of the isotopic signatures of the different sulfur pools during the TSR process. The fate of sulfur in petroleum reservoirs could be better understand with systematic analysis of all the sulfur isotopes.

Steam Assisted Gravity Drainage is a popular EOR method to recover heavy oil and bitumen. It consists of injecting steam to decrease the oil viscosity in the reservoir. During this process, the steam reacts with the oil due to the high temperature leading to the emission of the corrosive and highly toxic H2S if the oil contains sulfur. These reactions are called aquathermolysis. Understanding the mechanisms leading to H2S generation in the reservoir and to its resulting production at surface is of paramout importance for field operators in order to properly design their surface facilities and respect the environmental regulations. This study aims at providing more insights into these mechanisms. In particular the H2S generation and its distribution among the gas, oil and water phases in the reservoir have been investigated as well as its production process at well. Sensitivity analyses of H2S emissions on the injection temperature and the reservoir permeability have also been investigated. Overall this work illustrates the complex interactions between chemical reactions, thermodynamics equilibria and multiphase flows occuring in the reservoir and gives further insights on the mechanisms leading to the H2S production and its variation at the wellhead during the lifetime of a SAGD project.

H2S emissions from thermal recovery operations of bitumen and heavy oil are becoming an increasing concern. Many Steam Assisted Gravity Drainage (SAGD) programs are finding H2S level rising as wells are aging. Steam injection causes aquathermolysis reactions between bitumen, reservoir rock and high temperature steam, converting some organosulfur compounds into H2S. To precise its origin, a pre-SAGD oil sand sample from Foster Creek-Athabasca was submitted to aquathermolysis laboratory tests at 250°C, 45 bar and various durations up to one year. After each run, H2S yield was quantified, the extracted SARA fractions and the mineral fraction were weighed. Their total and labile sulfur contents were measured using Rock-Eval Sulfur pyrolysis, enabling the calculation of total sulfur and labile sulfur distributions over the fractions. The results show that aquathermolysis reactions led to sulfur depletion of the asphaltene fraction and to sulfur enrichment of the resin and aromatic fractions, simultaneously to H2S generation. This suggests that labile sulfur containing asphaltenic compounds generate H2S, resins and aromatics upon aquathermolysis conditions. These data can be used to entirely calibrate an integrated aquathermolysis kinetic model in reservoir simulator, for simulating H2S production in a SAGD project at Foster Creek existing producing asset.

The Tayarat Formation (Maastrichtian in age) was deposited in shallow-water carbonate platform complex across the interior of the Arabian Shield (Alsharhan and Nairn 1990, Dunnington 1958, Owen and Nasr 1958). Production from the Tayarat and Radhuma Formation heavy-oil reservoirs has presented many challenges in south Kuwait. Factors affecting these challenges are: 1) reservoir lithological heterogeneity, 2) poor reservoir quality, and 3) heavy-oil fluid properties heterogeneity. However, the main interest of this study is to understand the effect of mixing TSR-fluids on the physical and chemical fluid properties of the Radhuma and Tayarat Formation reservoirs in the Burgan Field

Significant concentrations of hydrogen sulphide (H2S) are observed in the Marrat reservoir in the Raudhatain and Sabriya fields (northern Kuwait). In this study, we have attempted to determine the origin of H2S and what factors may control its relative concentration. Our data show that it is most likely a product of thermochemical sulphate reduction (TSR). However, this process has not gone to completion, as the levels of H2S in the samples studied are still below 5%. Additionally, the hydrocarbon constituents of the gas phase do not appear to have been severely affected by TSR. So far, this process has primarily impacted the oil phase: increasing oil gravity and decreasing oil sulphur content. Some of the Marrat fluids from the Sabriyah field have lower H2S concentrations, though with equivalent H2S sulphur isotopic compositions to the other Marrat fluids from Raudhatain. We hypothesize that these differences are related to original compositional grading and/or reservoir charge histories, which influence the degree of TSR alteration by virtue of differences in original fluid polar and associated labile sulphur contents. This study demonstrates that pre-TSR reservoir charge histories and fluid phase distributions should be taken in to account for effective evaluation of H2S occurrences.