Petroleum exploration in presalt reservoirs is reaching increasingly deeper carbonate reservoirs, more and more distant from coastline. Therefore, optimization of investments for a safe and profitable production is critical. Each possible concern on geological conditions that would govern fluid composition and that can bring impact in development cost of an accumulation must be taken into account. In some petroleum accumulations, within presalt reservoirs, along southeastern offshore Brazilian basins, H2S was found. Although H2S concentrations were significantly lower than most of carbonates worldwide, they are enough to be considered in economical evaluations. Therefore, it is important to identify the process that generated H2S and to constraint the main variables that govern its occurrence for a more precise evaluation of the " H2S risk", take into consideration possible pit falls during well intervention. In this way, H2S is precipitated on site as a salt (Ag2S) from the gas produced during the long lasting producing tests, shipped to laboratory and the 34S/32S ratio is measured. The corresponding d34S value is the main tool for identifying H2S origin: if it was formed due to organic (BSR, d34S < -10 ‰) or inorganic (TSR, d34S > +10 ‰) sulfate reduction. Results of d34SCDT obtained in H2S from presalt reservoirs of the Santos Basin spread between +10 ‰ and +20 ‰ typical of TSR. However, temperatures of the reservoirs are lower than that inferred for development of TSR (T > ~120 °C) suggesting that H2S was generated in deeper intervals with significantly higher temperatures. More accuracy in the interpretation about the origin, and clues on migration pathways and accumulation are obtained integrating geochemical, geological and well data production. This integrated approach gives to the explorationist the best understanding about the " H2S risk" in a specific exploratory target. In this work it will be presented a discussion on the methodology for sampling and measuring d34S for identification of H2S origin.
Hydrogen sulfide is a non desirable gas component in petroleum accumulations. Because H2S is a powerful poison and has great capacity for increasing corrosion, its presence can bring significant health and economic impacts for petroleum exploration and production. The " H2S risk" must be evaluated carefully before drilling and its presence must be detected immediately during exploration and production.
Thermochemical sulfate reduction (TSR) is considered as the most important process of H2S formation in sedimentary basins and is controlled by the availability of sulfate (usually anhydrite from evaporites) and hydrocarbons (mainly gas), and temperatures higher than ~100 to 140 °C1,2,3. Although less important than TSR, other processes can also generate H2S that occur in petroleum reservoirs complicating the interpretation of its origin. As, for example, biochemical sulfate reduction (BSR) needs sulfate and sulfate-reducing bacteria in environments with temperatures lower than ~ 60 to 80 °C3, thermal cracking of kerogen (especially type II-S), magmatic sources and possibly thermal alteration of oils4,5,6. Therefore, it is important to identify the origin of this gas to propose prediction models for its occurrence. The most reliable tools for identification of H2S are an efficient sample collection and the sulfur isotopic analysis (d34S) of this gas. Integration with geological and geophysical data can strengthen significantly these interpretations.