Pipeline Safety Stakeholder Communications

Overview:

“Integrity Assessment” refers to measurements made by pipeline operators to determine whether their hazardous liquid or natural gas pipelines have adequate strength – integrity – to prevent leaks or ruptures under normal operation and upset conditions. These measurements help determine if pipe has been exposed to internal or external corrosion; if there are cracks, dents or other deformations in the pipe, or its welds, that weaken the pipe; or if there are manufacturing defects that would lead to pipe failure during extended periods of operation.

Regulations specify that pipeline operators must perform assessments and prioritize necessary repairs. Some repairs must be performed immediately. Others, depending on severity, can be addressed across different time frames.

Measurements are conducted on line pipe, or pipe that connects facilities such as pumping stations, refineries, chemical plants, storage tanks or wells. The determination that a facility can maintain integrity against leaks or spills is usually conducted as a part of OSHA Process Safety Management (PSM) requirements.

Assessment Methods:

Depending on characteristics of the pipe being examined, operators select among several measurement methods for determining integrity. These include:

• Magnetic Flux Leakage (MFL) tools;
• Transverse Flux Inspection (TFI) tools;
• Compression Wave Ultrasonic Inspection tools;
• Shear Wave Ultrasonic Inspection tools;
• Geometry (Caliper) tools;
• Hydrostatic testing;
• Direct Assessment;
• Close Interval Surveys.

Additional Considerations:

Hazardous liquid or natural gas pipeline operators are required to have an Integrity Management (IM) program in place. IM programs require operators to map those segments of their pipeline(s) that lie in high consequence areas (HCAs). These are areas where a leak or rupture could result in:

• adverse impact to the public;
• adverse effect upon the environment; or
• contamination of drinking water.

After HCAs are identified, operators are required to use one or more assessment method to measure for corrosion, deformations, cracking, or other hazards that could reduce integrity to a point where protection against leakage or rupture cannot be assured.

Operators typically use a magnetic flux or ultrasonic inspection tool that runs inside the pipe to detect corrosion, cracks or other anomalies, in combination with a geometry tool to measure deformations. Some operators use hydrostatic testing, either in lieu of these tool runs, or to supplement them, because of particular risk factors associated with their pipeline or where the pipe is too small to run internal tools (six inch diameter pipeis usually the smallest for many in-line tools, although some may be able to run in straight pipe runs of four-inch diameter).

Natural gas operators have difficulty using the same tools as hazardous liquid operators, because gas product does not provide for good coupling between the tool and the pipe wall, and pipe diameters often vary over a length of pipeline. Hydrostatic testing using water is not a good solution either, because of dewatering concerns and interruptions of service to customers.

These operators are considering direct assessment techniques to conduct their integrity assessments.

IM programs must identify risk factors that could lead to pipeline failure in each HCA; combine those factors to arrive at the overall risk for the HCA; and then rank the pipe segments according to risk. An operator’s assessment schedule usually ensures the assessment of higher-risk sections first, with assessment of successively lower-risk sections later in the schedule. Assessments are repeated periodically to ensure that pipelines remain safe and strong.

Date of Revision: 12012011