A March 16, 2017, Pipeline and Hazardous Materials Safety Administration (PHMSA) advisory bulletin (Docket No. PHMSA-2016-0131 – “Pipeline Safety: Deactivation of Threats”) gave guidance on the deactivation of pipeline threats, including the threat of internal corrosion. On April 8, 2016, PHMSA issued a Notice of Proposed Rulemaking (NPRM) entitled “Safety of Gas Transmission and Gathering Pipelines”. Section §192.478 “Internal Corrosion Control: Onshore transmission monitoring and mitigation” of the NPRM would increase the scrutiny and requirements for monitoring and mitigating the threat of internal corrosion for the gas industry.
This bulletin and NPRM reinforce the requirements of CFR part 192-subpart O, Section 192.937, requiring gas pipeline operators to continuously assess their pipelines for the threat of internal corrosion as part of their overall integrity management program. One of the requirements is to determine if the gas entering the system is corrosive or not corrosive. The optimal way to prove that the gas is not corrosive is to build a thorough continuous monitoring program that considers guidance from the NPRM and the advisory bulletin.
Following regulatory guidance and general corrosion principles, SI has partnered with EnhanceCo to develop a program to properly evaluate the possibility of deactivating the threat of internal corrosion on gas pipelines. Upon the successful completion of the Internal Corrosion Direct Assessment (ICDA) process or an in-line inspection (ILI) with no instances or indications of internal corrosion, the implementation of a comprehensive internal corrosion monitoring program for affected pipeline systems is recommended.
A monitoring program would still be recommended if an ICDA or ILI discovered indications of internal corrosion, however, the monitoring program would have additional requirements. After completing a baseline assessment, there are multiple elements considered best practices for conducting subsequent internal corrosion assessments and monitoring:
Gas Composition Analysis (moisture, CO2, O2, total sulfur, and H2S)
This analysis can be conducted using portable analyzers, stain tubes, or on-line monitoring equipment (gas chromatographs). Criteria must be established, and data should be periodically reviewed to ensure the criteria is achieved to exclude the threat of internal corrosion.
Corrosion Rate Analysis (Electrical Resistance (ER) probes, Coupled Multiple Array Sensor (CMAS) probes, coupons, etc.)
This analysis is conducted by using weight loss coupons, electrical resistance (ER) probes, coupled multi-array sensor (CMAS) probes, or other corrosion rate monitoring equipment. Coupons should be removed and analyzed at a minimum of twice per year. ER, and CMAS probes will provide significantly more resolution and can be monitored connected to an existing supervisory control and data acquisition (SCADA) system for continuous monitoring.
Liquids and Solids Analysis Liquids and solids, when detected, should be collected for analysis whenever piping and/or equipment is opened for inspections such as ILI operations, drip blowing or internal inspections. Sampling and analysis of this material provide invaluable information regarding the presence of corrosion by-products.
Internal Examination Records Internal surface examination records provide direct evidence to the existence or absence of internal corrosion. The internal surface of a pipeline or vessel should be examined anytime it is opened or removed from service.
Excavations and NDT Analysis Excavations done during routine maintenance, leak inspection, or integrity assessments provide an opportunity to perform NDT inspections to ascertain the possibility of internal corrosion.
Leak or Rupture Repair Records Available leak or rupture records shall be evaluated for internal corrosion listed as the root cause. Multiple assessment elements are recommended for proper implementation of an Internal Corrosion (IC) monitoring program to ensure that all factors that could influence the threat of internal corrosion are accounted for in the program.
The deposits were primarily composed of Fe, S, O, C, Al, Mg, Si, S, K, Ca and Mn. Presence of iron and sulfur is consistent with iron sulfide corrosion products. The source of these deposits is from the gas supplier’s line as the probe is mounted just downstream of the station inlet.
The presence of aluminum, magnesium, silica, potassium, and calcium (Al, Mg, Si, K and Ca) are common elements found in water or dirt and can react or otherwise precipitate out of solutions as a myriad of fine solids like calcium carbonate, and silicates as the moisture content drop.