Strategic Internal Corrosion Monitoring for Gas Pipelines

Regulatory Overview

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.

 

Internal Corrosion Monitoring Guidance

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:

Element 1

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.

Element 2

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.

 

Element 3

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.

Element 4

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.

Element 5

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.

Element 6

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.

 

Internal Corrosion Case Study
Pipeline System Background
The particular pipeline system being used in this case study is a typically dry natural gas pipeline which operates continuously with some periods of increased gas consumption in the winter. A baseline ICDA was conducted on this line segment, and no internal corrosion was observed. No known history of internal corrosion in the system has been documented. Evaluation of the one gas inlet on this system demonstrates the value of IC monitoring.
A gas chromatograph has been installed at this inlet, allowing for review of the gas quality data for continuous monitoring of liquid upsets. Additionally, an ER probe and transmitter were installed and tied in to the SCADA system as an additional monitoring methodology to supplement the IC monitoring strategy.
Gas Composition Analysis
The IC monitoring program considers the presence of excess amounts of moisture (H2O), hydrogen sulfide (H2S), total sulfur, oxygen (O2) and carbon dioxide (CO2) as conditions with the potential to increase the threat of internal corrosion. As shown in the charts above, none of these constituents were above allowable limits during this analysis period.
ER Probe Analysis
The short-term corrosion rate (STCR) (blue line in Figure 3), is based on one-minute data collection measurements that are averaged and stored in the SCADA system. For the period analyzed, May 2016 to April 2017, the minute-by-minute STCR data was averaged and stored every 3 hours and 25 minutes, providing 2,599 records for analysis. The average STCR was 0.0 mils per year (mpy). The fluctuations in the STCR are likely from solid build up on the probe. The long-term corrosion rate (LTCR) (red line in Figure 3) data is an average of one-minute probe readings, averaged each 10 minutes, then each 10-minute average is cumulatively averaged over the entire duration and stored in SCADA. The LTCR calculated rates are 0.0 mpy. These LTCRs indicate no significant internal corrosion issues. The ER probe condition is shown by the green line in Figure 3. Once a probe reaches 50% of its useful life, it should be replaced. At the current time, the probe is at 4% of its life with 4.78 years until likely replacement at the current exposure conditions.
Solids Analysis
Based on the fluctuations seen in the STCR as noted above, the ER probe was removed and inspected. Once the probe was removed for inspection, a sample of the surface deposit was collected for elemental analysis using scanning electron microscopy/electron dispersive microscopy (SEM/EDS) to provide information on the elemental characteristics. A light layer of a black deposit covered all exposed surfaces, some of which was easily removed manually with a cloth. Solvent cleaning had little effect, suggesting the deposit was not predominantly hydrocarbon-based (i.e., grease, lubricant, oil). The probes were successfully cleaned with a light abrasive pad prior to returning to service.

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.

Monitoring Conclusions
  • A thin layer of a black, organic-based material was lightly covering the probe at the inlet location. Based on the findings obtained from the SEM/EDS analysis, the material is most likely a combination of corrosion products and solids that precipitate as moisture in the system is consumed upstream.
  • The probe readings did not indicate any significant long-term corrosion rates at the location being monitored (<1 mpy). These readings were evaluated and averaged from hourly, weekly, and monthly perspectives.
  • The ER probe metal loss measurements suggest a corrosion rate less than 1 mpy at this gas inlet. Within the corrosion control industry, managing degradation below 1 mpy is considered non-corrosive.
  • Evaluation of the daily gas analysis information (e.g., H2O, H2S, Total S and O2) revealed no excursions above the established criteria.
  • The current threat of internal corrosion is low based on the data assessment gathered from the monitoring methods used, however, there is a potential threat from solids that is prudent to monitor.

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