Determination of H2S Partial Pressures and Fugacities in Flowing Streams

Abstract

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 179921, “Determination of H2S Partial Pressures and Fugacities in Flowing Streams for a More-Accurate Assessment of Integrity Threat in Sour Systems,” by Christopher Harper, Kanan Taghiyev, and Peter Wilkie, Baker Hughes, and Douglas Hall, Chevron, prepared for the 2016 SPE International Oilfield Corrosion Conference and Exhibition, Aberdeen, 9–10 May. The paper has not been peer reviewed. An Excel-based tool was developed that uses cubic-equation-of-state (EOS) and thermodynamic electrolyte-chemistry modeling to assess sour-production streams from a reservoir, through production tubing, pipelines, and facilities to an export pipeline within a range of temperature and pressure conditions. The approach is need to assess the integrity risk posed to system components in the Alba field in the North Sea. Theory and Methodology To accurately determine multiphase sulfide concentrations, and therefore hydrogen sulfide (H2S) partial pressures and the resulting integrity threat in sour-production streams, it is first important to understand the pH-dependent distribution of the three species of sulfide that may be present in an aqueous solution. Many commercially available EOS software packages do not take into account aqueous pH- and speciation-driven aqueous sulfide solubility. They merely assume that the gas-phase and oil-phase H2S remains as H2S in all three phases and, as such, that the aqueous solubility is limited by the solubility of the H2S species in water. The three species of sulfide that may be present in an aqueous solution are H2S, HS−, and S2−. How much of each species is present (as a fraction) is dependent largely upon the aqueous pH. H2S is the only species of sulfide that exists in all three phases; some aqueous sulfide must speciate to H2S before H2S is found in the oil and gas phases. Therefore, in an oil-production system in thermodynamic equilibrium, with an aqueous pH of 9.5 or higher, all sulfide must be in the water phase and oil and gas phases must be completely free of H2S. However, this would be very unusual in an oil- production system or reservoir where typical aqueous pH values are much lower. At very low pH values, three-phase H2S distribution is driven by temperature and pressure alone: Increasing pressure reduces gas-phase H2S and increases oil- and water-phase H2S, whereas increasing temperature increases gas-phase H2S and reduces oil- and water-phase H2S (Fig. 1).