This paper will present corrosion management of a wet sour gas carbon steel export pipeline using continuous and batch corrosion inhibitors with mono-ethlene-glycol (MEG) as hydrate mitigation strategy in NACE MR 0175/ ISO 15156 region 3 (severe sour). The wet sour gas carbon steel export pipeline corrosion management via continuous CI and batch inhibitors with closed loop MEG regeneration system is rare worldwide. This is especially challenging when the case study may potentially be the longest wet sour gas, large diameter carbon steel pipeline (approximately 207km × 32 inch) in the world thus far. Pipeline corrosion management and hydrate management aspects when being reviewed holistically, it could provide significant cost savings yet safeguarding the overall technical integrity of the pipeline. The overall corrosion management leverages on Shell's many years of JIP and operating experience in sour service including the pipeline material specification, corrosion management, inspection, and maintenance philosophy. Reliable correlation between reservoir properties and uncertainties severe sour service, flow assurance, chemical behavirous, operating experiences etc were considered to best represent the operating envelope for this wet sour gas carbon steel pipeline. This includes the testing and selection of continuous CI and batch inhibitor, corrosion monitoring, operational pigging, maintenance, and inspection requirements throughout the field life.
The use of duplex stainless steel has been increasingly common in the oil and gas industry since the material offers a unique combination of high strength and superior corrosion resistance. However, the material is not immune to failure. A process safety incident at Sarawak Shell Bhd. highlighted this fact, whereby a duplex stainless steel gas flowline flange had fractured and parted after around 11 hours upon being installed and put in service. Independent failure investigations revealed that the failure was due to the formation of harmful sigma intermetallic phase in the base material of the flowline flange, a phenomenon known as sigma phase embrittlement. This can occur due to incorrect heat treatment processes during the manufacturing stage of duplex stainless steel components or due to incorrect welding processes. For the specific example reported in this paper, it was concluded that the flange was subject to incorrect heat treatment during manufacturing which exposed it to slow cooling through the sigma phase formation temperature range. This resulted in a significant loss of toughness and ductility of the flange material, which caused it to fracture and part shortly after being placed in service. Actions were subsequently taken to identify the risks of other duplex stainless steel piping components in Sarawak Shell Bhd. having the similar in correct heat treatment and thus could likely be subject to the same failure mechanism. This paper presents how a systematic risk-based approach was implemented to verify existing installed piping components in terms of their risks to intermetallic phase embrittlement. Actions taken to prevent similar occurrences in the future are also detailed. Ferrite count verifications using portable ferrite scope instruments were found to provide a useful screening method for verifying the likelihood of the presence of sigma phase in duplex stainless steel material. During procurement of duplex stainless steel components in new projects, inspection Hold Points for ferrite scope inspections were specified and implemented in the Inspection and Test Plans. Additionally, 100% ferrite scope inspections were imposed on all duplex stainless steel piping components received at Sarawak Shell Bhd.'s supply base warehouse. The procurement process for small quantities of duplex stainless steel components was revised to ensure that proper review of the technical specifications is carried out prior to placing purchase orders especially with stockists.
Top of Line corrosion (TLC) has becoming a growing concern for the oil and gas industry over the past recent decades especially on the offshore subsea high temperature and high pressure (HTHP) pipelines. This paper will present the challenges in managing TLC in multiphase wet gas pipelines. It will also cover the design, execution, appropriate inspection and corrosion monitoring to ensure pipeline integrity meeting the intended design life. There are many corrosions prediction modelling softwares available in the open market. However, once TLC is predicted in a pipeline, there are only few mitigation options which are by material selection, chemical injection, routine operation pigging, batch inhibition, etc. New projects are often considering material selection to mitigate TLC. This approach is rather straight-forward, however, high CAPEX is required. As for existing pipelines in operation with TLC, it must depend on effective chemical control (corrosion inhibitor) that could protect both TLC and BLC (bottom of line corrosion) coupled with continuous corrosion monitoring tools. Routine pigging during operation and more frequent inspection could be required too. To date, there is no common standard in testing the effectiveness of volatile corrosion inhibitor (VCI) in mitigating TLC.
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