Reservoir Souring in a Field With Sulphate Removal: A Case Study

Abstract

Abstract This paper presents the results of a reservoir souring study in Hess' South Arne field (North Sea, Denmark). The field produces from a 115°C chalk reservoir and utilizes sulphate rejection membrane (SRM) technology to generate low-sulphate seawater (LSSW) for water injection. In addition to achieving the primary objective of barium sulfate scaling control, eight years of historical data show that the injection of LSSW also significantly reduced the severity of reservoir souring to levels acceptable for continued use of the existing wells and facilities from a corrosion and gas handling point of view. This case study is especially important information for deep sea oilfields where high-strength steel risers, which are susceptible to sulphide stress corrosion cracking, are utilized and where installation of SRM units can be a significant part of a viable souring mitigation strategy. In November 2008, an innovative and successful water shut-off operation was performed for oil producer Well-L and production was commenced after a 2 year shut-in. Three weeks later, an unexpected H2S alert was experienced during oil export to a tanker. A follow up H2S survey indicated up to 15 ppm in the bulk gas and in excess of 35 ppm in gas from Well-L. A comprehensive study was therefore initiated to fully understand the causes of souring and to develop a new H2S management strategy to deal with the issue. Analysis of produced water and H2S concentrations in oil, water and gas was used to generate mass balances of sulphate and sulphide for the reservoir and production system. Analysis of the sulphur isotopes in H2S was made together with a review of the historical H2S scavenger usage and pre-water injection well-test H2S measurements. This showed that reservoir souring was the dominant H2S source and that a significant proportion of the sulphate introduced to the reservoir by the injection water was converted to H2S. Molecular microbiological methods (MMM) showed high concentrations of sulphate-reducing archaea (a group of thermophilic microbes producing H2S, but genetically very different to sulphate-reducing bacteria) in produced fluids, while traditional most probable number (MPN) techniques gave zero readings. Microbiological sulphate reduction may minimize the field's barium sulphate scaling risk by reducing sulphate concentrations in the injection water below those achievable by South Arne's SRM equipment alone.