Monday, November 24, 2014

HYDROGEN SULFIDE (H2S) GAS RELEASE FROM PIPING CORROSION FAILURE NEAR A WELD AT AN OIL PLATFORM




Hydrogen Sulfide (H2S) Gas Release from Piping Corrosion Failure Near a Weld at an oil platform




Hydrogen sulfide corrosion has been plaguing the oil and gas industry for many decades.  Unless this issue is addressed in areas where high concentrations of hydrogen sulfide are expected or have been measured, catastrophic failures have and will continue to occur.


The Incident

The location of the H2S release was on Platform Hidalgo on Lease OCS-P 0450.  This is offshore the California coats.  It occurred on February 23, 2012.

A hydrogen sulfide (H2S) gas release occurred from a piping corrosion failure near a weld, on the 8-inch side of an 8-inch by 4-inch reducer on the blowdown line for a third-stage section compression scrubber.  Multiple H2S sensors detected the release and initiated a platform shutdown.  Platform personnel were directed to muster to the safe briefing areas.  Response personnel using breathing apparatus isolated the leak.  No injuries to any personnel occurred from the incident.  Prior to the platform being restarted, the failed spool was removed and saved for testing, and a new spool was installed.  The H2S concentration at the release point was estimated to be 40,000 ppm.



Investigation

An incident investigation revealed the following:

The cause of the H2S release was a weld failure on the side of the reducer. This failure was caused by accelerated corrosion resulting from elemental sulfur in contact with steel in an area where deposits could build up.  Elemental sulfur acts as an oxidizer and is known to accelerate steel corrosion and cause localized reduction in wall thickness. The elemental sulfur in the scale was the result of oxygen contamination in the wet, sour gas stream.  Oxygen reacts with hydrogen sulfide in liquid water to form elemental sulfur.

Contributing factors to the accelerated corrosion include: high H2S concentrations sufficient to introduce elemental sulfur which exacerbates the corrosion process and low flow rate in the area of the failure due to the reducer configuration.  The areas in the reducer with higher flow rates did not have heavy buildup of corrosion products.


The reducer spool that failed is included in a piping circuit in the operator’s Mechanical Integrity Program.  The circuit was last examined in May 2011 utilizing a non-destructive test (NDT) ultrasonic “A” scan that was run at specific points on the circuit.  The results of the 2011 inspection did not indicate any issues that required corrective action.

NDT results for the piping circuit covering the last 10 years showed no appreciable loss in wall material thickness.


The ultrasonic inspection procedures used to examine the piping circuit may not have been effective in identifying the potential for a weld failure because the procedures were designed to assess the pipe’s thickness and were taken on a smooth surface at some distance away from the weld’s location.  In addition, the voluminous scale deposits on the steel surface may have affected the accuracy of the inspection results.




Prior H2S Gas Release on Another Platform in the Point Arguello Unit



On August 3, 1999, at about 2:00 p.m., an 8-inch high pressure gas flowline on Platform Hermosa ruptured, resulting in a sour gas release.  The break occurred on the mezzanine deck, about 64 feet above the ocean, downstream of a third-stage discharge scrubber, V-14, and just prior to the glycol contactor inlet, V-16.  The drop in pressure activated the automatic safety system on the platform, which shut in oil and gas production. Platform Hidalgo, with pipelines transporting oil and gas to Platform Hermosa, was also shut in.

The released gas had an H2S concentration of about 18,000 ppm. The H2S alarms on Platform Hermosa activated. No one on Platform Hermosa was harmed.  No harm to seabirds or other wildlife was observed.

The flowline failed due to internal corrosion, which reduced the wall thickness until it could no longer contain the normal operating pressure.  Corrosion was caused by condensed liquid water reacting with H2S gas to form a corrosive acid gas.




Recommendations

Therefore, we recommend that operators:



·         Inspect all piping with similar internal exposure, i.e., wet, sour gas where water and deposits can accumulate, and replace if extensive corrosion is identified.

·         Review inspection and maintenance programs for piping exposed to sour gas and

·         include procedures for identifying localized corrosion problems using radiography or other non-destructive inspection methods where normal ultrasonic inspection may not be effective, such as the areas near welds, reducers, and flanges.

Verify that your Safety and Environmental Management System program adequately addresses the design, inspection, testing and quality assurance of piping exposed to sour gas in order to prevent the buildup of elemental sulfur and to identify and remediate areas of excessive corrosion so that similar releases of H2S gas can be prevented.





Safety Alerts can be found on the following BSEE webpage:  http://www.bsee.gov/Regulations-and-Guidance/Safety-Alerts/Safety-Alerts/



Panel Investigation Reports can be found on the following BSEE webpage:  http://www.bsee.gov/Inspection-and-Enforcement/Accidents-and-Incidents/Panel-Investigation-Reports/Panel-Investigation-Reports/



Metropolitan Engineering, Consulting & Forensics (MECF)

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