Material Assessment for Souring Subsea Systems

Abstract

Abstract Material selection for subsea pipelines and equipments for the cases where the well fluid analysis shows elevated levels of H2S (sour service) has been extensively studied and documented during the past years. However, several cases have been reported where the fluid analysis at the start up stage does not show evidence of H2S but the risk of sour production is still present. There are two main causes for this to occur:typically, the resolution of the gas composition measurement is only valid down to 0.01 mole% (100 ppm) leaving the possibility of H2S being present in amounts between 0-99 ppm presenting potential sour conditions for high pressure systems.The H2S contents can increase during production when water injection systems are used to pressure-support the production reservoir. Seawater injection increases the H2S levels on the fluid due to microbial activity. This paper addresses the risk associated with sour systems which were not designed for such service. The paper presents a project specific study where the presence of H2S was determined after the system was built. A material risk assessment was performed to determine the suitability of the system. The purpose is to share the lessons learned and to provide guidelines for the material assessment of souring production systems. Introduction Corrosion produced by hydrogen sulfide (H2S) in oil and gas production, referred to as sour corrosion, has been recognized and extensively studied for several years. The presence of H2S in the produced fluids not only generates general corrosion but also can lead to hydrogen embrittlement and cracking making the material prone to catastrophic failure. When the produced fluid is regarded as sour, the risk of hydrogen embrittlement failures due to sulfide stress cracking (SSC) or hydrogen induced cracking (HIC) may support the selection of highly priced materials reflected in abundant cost penalty on the initial capital expenditure (CAPEX) [1,2]. Several systems on the North Sea and Gulf of Mexico have been designed for sweet service (i.e. H2S is not present) since the fluid analysis at the start up stage did not show evidence of H2S. However, it has been reported that several of these systems have experienced the presence of H2S afterwards [2-5]. There are two main reasons for this to occur:Usually, the gas composition measurement resolution is only valid down to 0.01 mole% (100 ppm) and, therefore, there is the possibility of H2S being present in amounts between 0-99 ppm presenting potential sour conditions for high pressure systems.