What can go wrong

Pipelines fail through a handful of threats: external corrosion where coatings and cathodic protection fall short, internal corrosion from water and contaminants in the product, cracking such as stress corrosion cracking and seam weld defects, mechanical damage from excavation equipment, and defects from construction and manufacturing that grow over time. Storage tanks, compressor and pump stations add their own corrosion and fatigue problems.

The case that reshaped US pipeline integrity rules is San Bruno. On September 9, 2010, a 30-inch natural gas transmission pipeline owned and operated by Pacific Gas and Electric Company ruptured in a residential area of San Bruno, California. The gas ignited; eight people were killed, many were injured, 38 homes were destroyed and 70 damaged. The NTSB determined that the probable cause was inadequate quality assurance and quality control during a 1956 relocation project, which let a substandard, poorly welded pipe section with a visible seam weld flaw into service, where the flaw grew until the pipe ruptured; and an integrity management program that failed to detect and repair or remove the defective section. The Board also found that exemptions of older pipelines from pressure testing had contributed, because a test would likely have found the defects. Construction inspection and in-service integrity management, in other words, failed together.

Inspection during construction

New pipelines are welded in the field, joint by joint, and the girth welds are the first thing inspection protects. Welding procedures and welders are qualified, typically to API 1104, and the completed welds are examined by radiography (RT) or, increasingly, by automated ultrasonic testing (AUT), which records encoded phased array and other ultrasonic data around the full circumference in minutes.

Federal rules set a floor. For gas pipelines, 49 CFR 192.243 requires that, where nondestructive testing is required, a random sample of each day's field butt welds be tested over their whole circumference: at least 10 percent in Class 1 locations, at least 15 percent in Class 2, and 100 percent (unless impracticable, then at least 90 percent) in Class 3 and 4 locations, at major river crossings, offshore and in road and rail rights-of-way, with every tie-in weld tested. For hazardous liquid lines, 49 CFR 195.234 requires at least 10 percent of each welder's girth welds each day and all girth welds in sensitive locations such as water crossings and populated areas. Both rules require written procedures, trained personnel and records. Many operators test far more than the minimum.

Coating inspection, including holiday testing for gaps in the coating, and a hydrostatic pressure test complete the picture before the line is put into service. On the owner's side, construction inspectors certified to API 1169 oversee the work.

Inspection in service: integrity management

Once a pipeline is running, federal rules require operators to manage its integrity where a failure would do the most harm. Gas transmission operators must have integrity management programs for segments in high consequence areas under 49 CFR Part 192, Subpart O, and hazardous liquid operators for pipelines that could affect such areas under 49 CFR 195.452. The rules require baseline assessments, periodic reassessment, and repair of what is found on set timelines.

The assessment methods named in the gas rule (49 CFR 192.921) include:

  • In-line inspection (ILI) with tools, or "smart pigs", carried through the line by the product. Magnetic flux leakage tools find metal loss, ultrasonic and EMAT tools find cracks and measure wall, and caliper tools find dents. The rule requires operators to account for tool uncertainties such as detection thresholds, probability of detection and sizing accuracy.
  • Pressure testing, including spike hydrostatic tests for crack-like threats.
  • Direct assessment and direct examination, where surveys and records pick dig sites and the pipe is examined in the ditch with methods such as UT, phased array, radiography and magnetic particle testing.
  • Guided wave ultrasonic testing for internal and external wall loss, applied as the rule's Appendix F describes.

Reassessment intervals are set by the rules and the operator's risk analysis: for gas segments operating at or above 30 percent of specified minimum yield strength, the maximum reassessment interval is seven calendar years (49 CFR 192.939), and hazardous liquid operators must reassess at intervals of five years, not exceeding 68 months (49 CFR 195.452). Every ILI call that is dug up is an NDT job: the dig verification crew measures the actual anomaly so it can be compared with what the tool reported, which in turn tells the operator how far to trust the rest of the run.

Stations, tanks and LNG

Compressor and pump stations are small process plants with piping, vessels and rotating equipment, inspected much like a refinery. Breakout tanks on hazardous liquid systems must be inspected in accordance with API 653 (49 CFR 195.432), which brings tank floor scanning, shell thickness measurement and weld inspection into pipeline programs. LNG facilities come under their own federal standards in 49 CFR Part 193.

Regulations and standards

  • PHMSA regulations: 49 CFR Part 192 (gas) and Part 195 (hazardous liquids), including construction, testing, integrity management and operator qualification of personnel who perform covered tasks.
  • API documents such as API 1104 for pipeline welding, API 1163 for qualifying in-line inspection systems and API 1169 for construction inspection.
  • ASME pipeline codes, B31.4 for liquids and B31.8 for gas, and ASME B31.8S for managing the integrity of gas pipelines.

What this means for operators

Do your NDT procedures and technicians meet the requirements of your construction specification and the regulations, with records kept for the life of the pipeline where the rules require it? Is dig verification data fed back to validate ILI performance? Are anomaly measurements in the ditch made with calibrated equipment, by technicians certified in the technique? And is there a clear owner for the handoff between ILI vendor, integrity engineer and dig crew?

Frequently asked questions

What is pipeline integrity management?

It is the program a pipeline operator runs to find and fix threats to its pipelines before they fail: identifying where a failure would matter most, assessing the pipe by in-line inspection, pressure testing or direct examination, repairing what is found, and reassessing at set intervals. In the US it is required by PHMSA rules in 49 CFR Parts 192 and 195.

How much of a pipeline's girth welds must be inspected?

Federal rules set minimums that depend on the product and location. For gas pipelines, 49 CFR 192.243 ranges from at least 10 percent of each day's welds in rural Class 1 locations to 100 percent in populated areas and at crossings; for liquids, 49 CFR 195.234 requires at least 10 percent of each welder's daily welds and all welds in sensitive locations. Many operators specify 100 percent.

What does a smart pig find?

Depends on the tool. Magnetic flux leakage tools find metal loss from corrosion, ultrasonic and EMAT tools find cracks and measure wall thickness, and caliper tools find dents and ovality. Operators often run more than one tool type to cover all their threats.

How NDT LLC can help

NDT LLC helps pipeline operators and their contractors with NDT procedures and written practices, technician qualification, audits of NDT and ILI verification vendors, and independent review of inspection data. Contact us to discuss your program. See also our overview of NDT in oil and gas.

This article is general information for a business audience, not engineering, legal or regulatory advice. Always work to the current edition of the codes, standards, regulations and manufacturer data that apply to your equipment and contracts.

NDT LLC is an independent consulting firm. It is not affiliated with, endorsed by or sponsored by PHMSA, the National Transportation Safety Board (NTSB), the American Petroleum Institute (API), ASME, or any other organization named in this article; names are used only to identify the organizations and documents referred to.