Assessing the Magnitude and Consequences of Reservoir Souring

Abstract

Reservoir souring Reservoir souring, defined as the unplanned increase in hydrogen sulfide (H2S) in produced fluids during field life, is a growing concern for the petroleum production industry. H2S is a poisonous, dense gas with serious safety implications; it can lead to sudden catastrophic failure of nonresistant metallic materials from sulfide stress corrosion cracking or hydrogen-induced cracking, and it can enhance pitting corrosion rates. But how does reservoir souring develop, and how can its consequences for materials be anticipated? Consideration also needs to be given to the currently available options for souring control and their shortcomings. Despite the significant advances that have been made over the past 30 years or so in the understanding of H2S- related materials degradation mechanisms, H2S still causes many failures every year. While it may be understandable that such failures continue to occur in operating environments where reservoir souring is a new phenomenon, failures are also occurring where the industry is mature. For example, recently in the UK, a carbon steel pipeline transporting sour hydrocarbons onshore failed by sulfide stress cracking (SSC) after 6 weeks of operation, necessitating replacement at a cost of GBP 100 million. Over 2000–01, sour gas pipelines failures, including those affected by both microbial and chemically induced corrosion, accounted for 35 (4%) of the 952 pipeline failures in Alberta, Canada. The challenge of dealing with H2S is likely to rise in importance as an increasing number of high-temperature, high-pressure (HTHP) reservoirs are exploited in the future. This will require more widespread use of corrosion resistant alloys (CRAs), increasing the costs of wells and downstream equipment. Therefore, we need more corrosion data on a range of alloys when there are fewer materials engineers (particularly metallurgists) coming into the industry and fewer corrosion testing facilities in steel companies, meaning that operating companies and even fabrication contractors are having to take on the task of generating materials susceptibility data. H2S Generation and Mobility Reservoir souring is the production of increased concentrations of H2S in well-stream fluids from production wells subject to water injection for secondary recovery. It is generally acknowledged to be caused by the activity of a specialized group of microorganisms, the sulfate-reducing bacteria (SRB). Low populations of SRB cells are ubiquitous in seawater and many other natural waters that are used for secondary recovery. Biogenic H2S originates solely from SRB activity in the water phase and subsequently partitions between water, liquid hydrocarbon, and gas, dependent on temperature, pressure, the pH of the aqueous phase, fluid phase ratios, and a number of other factors. However, the progress of reservoir souring is routinely measured and expressed in terms of H2S concentrations in the gas phase at separator conditions and the corresponding partial pressures of gaseous H2S.

Reservoir souring: sulfur chemistry in offshore oil and gas reservoir fluids

“…In low-temperature diagenetic settings (T < 100 °C), where oxygen is available and pH conditions are favorable, sulfide can be oxidized to elemental sulfur. Several models have been developed to predict the partitioning behaviour of H 2 S in reservoir fluids and to investigate the effects of temperature, pressure, fluids composition, ionic strength, and water pH on the H 2 S mass production rate Burger et al 2005;Schofield and Stott 2012;Ligthelm et al 2000;King and Al-Najjar 1977;Sunde et al 1993;Tyrie and Ljosland 1993). The dissolution of H 2 S in water involves a series of chemical reactions: the dissociation of the molecular H 2 S to bisulfide and sulfide ions and the selfionization of water (Burger et al 2013):…”