[Skip to Content]
U.S. Department
of Transportation

Pipeline Safety Stakeholder Communications

Pipeline Safety Connects Us All

Fact Sheet: Direct Assessment (DA) - Gas Pipelines

Quick Facts:

  • Direct Assessment is identified in the Gas Pipeline Integrity Management Rule as one of the three acceptable methods for evaluating the integrity of a pipeline segment.
  • Direct Assessment may be used either as a primary or a supplementary method, implemented in conjunction with one of the other primary assessment methods, i.e. inline inspection (ILI) or hydrostatic pressure testing.
  • Direct Assessment — also known as DA — is limited to evaluating the risks of three time-dependent threats to the integrity of a pipeline segment: external corrosion, internal corrosion, and stress corrosion cracking.
  • The Gas Pipeline Integrity Management Rule — also known as the “gas IM rule” — contained in Subpart O of 49 CFR Part 192 provides for specific and separate requirements for applying DA for external corrosion (ECDA) (§192.925), internal corrosion (ICDA) (§192.927), and stress corrosion cracking (SCCDA) (§192.929).
  • When a pipeline segment is scheduled for a full integrity reassessment at an interval longer than 7 years, confirmatory direct assessment (CDA) (§192.931) may be used during the seventh year following a baseline assessment to verify or “confirm” the integrity of a pipeline from external and internal corrosion threats only.
  • The Gas Pipeline Integrity Management Rule contains more restrictive requirements for operators applying DA for the first time on a pipeline segment.
  • If external corrosion direct assessment (ECDA) finds pipeline coating damage, the operator must integrate the data from ECDA with one-call notification information and right-of-way information to evaluate the segment for the threat of third-party damage.

Why do pipeline operators use direct assessment to evaluate the integrity of a pipeline?

DA is needed as an integrity assessment method for pipeline segments:

  • Where ILI or hydrostatic pressure testing cannot be used,
  • To avoid impractical, costly retrofitting of a pipeline,
  • To avoid interrupting gas supply to a community fed by a single pipeline, and,
  • To provide an alternative where sources of water for hydrostatic pressure testing are scarce, and where water disposal may create problems.
  • DA may provide a more effective, equivalent alternative to ILI and hydrostatic pressure testing for evaluating a pipeline’s integrity.

How is direct assessment carried out?

The gas IM rule specifies a four-step approach for evaluating corrosion threats using DA. For external corrosion direct assessment (ECDA), the gas IM rule requires:

Step One: Pre-assessment - to gather and integrate data to determine the feasibility of using ECDA for a segment, the identification of ECDA regions, and the identification of two indirect examination tools to be used on the ECDA region.

Step Two: Indirect Examination - to evaluate the pipe segment and identify indications of potential external corrosion, to classify the severity of those indications, and determine urgency for their excavation and direct examination.

Step Three: Direct Examination - to examine the condition of the pipe and its environment, to determine actions to be taken should corrosion defects be found, and to identify and address root causes.

Step Four: Post Assessment - to determine a segment’s remaining life, its re-assessment interval, and the effectiveness of using ECDA as an assessment method.

For internal corrosion direct assessment (ICDA), the gas IM rule also specifies a four-step process, based on the principle that liquids collect on the bottom of a pipe when a “critical angle of inclination” is exceeded for a specific gas flow velocity. (§192.927):

Step One: Pre-assessment - to gather and integrate data and information to determine whether ICDA is feasible for the segment, to support use of a model to identify locations where liquids may accumulate, and to identify where liquids may enter the pipeline.

Step Two: CDA region identification - to apply a specific model to identify elevation conditions and other pipeline fittings where liquids may accumulate.

Step Three: Direct Examination - to excavate and examine pipe locations identified by the process as most likely for internal corrosion, and to evaluate the severity of defects and remediate as code requires.

Step Four: Post assessment evaluation and monitoring - to evaluate the effectiveness of the ICDA process, to monitor segments where internal corrosion was identified, and to determine re-assessment intervals.

Stress corrosion cracking direct assessment (SCCDA) requires a plan that provides for:

  1. Data gathering and integration — to determine whether the conditions for stress corrosion cracking are present, requiring an assessment for SCC; to prioritize pipeline segments for assessment; and to gather and evaluate data related to stress corrosion cracking at all operator excavation sites. When all of the following conditions for high pH SCC are present — operating stress greater than 60% of SMYS; operating temperature greater than 100°F; within 20 miles downstream of a compressor station; age greater than 10 years; and pipe coating other than fusion bonded epoxy — an assessment method must be applied.
  2. Assessment method — to evaluate segments for the presence of stress corrosion cracking; determine its severity and prevalence; repair, remove or hydrostatically test the valve section; and determine any further mitigation requirements.

Should conditions for SCC be present in a segment, the segment must be assessed and remediated, as specified in Appendix A3 of ASME B31.8S, applying:

  • The bell hole examination and evaluation method, or
  • The hydrostatic pressure testing method for SCC.

Applying CDA requires a plan specifying that CDA can only be used on internal and external corrosion threats (§192.931).

  1. For external corrosion (EC), the plan must comply with §192.925, however:
    • Only one indirect examination tool may be used, and one high risk indication examined in each ECDA region; and
    • All immediate indications must be excavated in each ECDA region.
  2. For internal corrosion (IC), an operator’s plan must comply with §192.927, however: only one high risk location must be excavated in each ICDA region.
  3. When applying either ICDA or ECDA, if defects are found requiring remediation before the next scheduled assessment, the operator is required to apply the formula in § 6.2 and 6.3 of the National Association of Corrosion Engineers (NACE) Recommended Practice 0502 to schedule the next assessment.

Are standards being developed for ICDA and SCCDA?

In December, 2004, NACE adopted Recommended Practice 0204 for Stress Corrosion Cracking Direct Assessment (SCCDA), and is now in the process of adopting a proposed recommended practice for Internal Corrosion Direct Assessment. These will provide operators additional guidance for addressing threats.

Are there referenced standards which must be met when applying DA?

  • For ECDA: NACE RP 0502-2002, and ASME B31.8S §6.4.
  • For ICDA and for SCCDA: ASME B31.8S § 6.4, Appendices A2, B2 & A3.
  • For ICDA: Gas Technology Institute, GRI-02-0057, “Internal Corrosion Direct Assessment of Gas Transmission Lines - Methodology”.

Date of Revision: 02262018