PIPELINE INTEGRITY
Pipeline integrity is the ability of a pipeline system to remain fit for its intended service and perform safely, reliably, and effectively under the operating and environmental conditions it is expected to encounter.
00 · FOUNDATION
Integrity is maintained over time by understanding what can threaten the pipeline, evaluating what is known about its condition, choosing assessment methods that fit the threat, acting on the evidence, and reassessing as conditions and information change.
01 · ASSESSMENT SELECTION
ILI, pressure testing, direct assessment, direct examination, NDE, and other methods answer different questions. The first discipline is matching the assessment method to the threat, the pipeline configuration, the information required, and the limitations of the method.
Tool technology, sizing capability, detection limits, inspection conditions, prior run history, validation results, and data quality determine what confidence can reasonably be placed in an ILI result.
Hydrostatic and other pressure-test approaches can demonstrate pressure resistance and expose certain defects, but they do not provide the same location-specific condition information as inspection or direct examination.
ECDA, ICDA, and SCCDA are structured processes that integrate pre-assessment, indirect evidence, targeted examination, and post-assessment learning for specific threats.
02 · DIRECT ASSESSMENT
ECDA, ICDA, and SCCDA share a framework, but they are built around different damage mechanisms. The right method depends on the threat, the evidence available, and what the operator needs to confirm.
Combines corrosion-control history, coating and environmental context, above-ground surveys, and excavation findings to prioritize external-corrosion indications.
Under 49 CFR 192.925, ECDA is a four-step process: pre-assessment, indirect inspection, direct examination, and post-assessment.
CP context: cathodic-protection performance, coating condition, interference, electrical continuity, and field measurement quality can materially affect the evidence used in an ECDA program.
Uses operating, elevation, flow, geometry, and other pipeline-specific data to identify locations where liquid or electrolyte is most likely to accumulate.
For dry-gas ICDA under 49 CFR 192.927, the process includes pre-assessment, indirect inspection, detailed examination, and post-assessment monitoring.
Boundary: the federal dry-gas ICDA process is limited to normally dry natural-gas segments; additional requirements apply when electrolytes are normally present.
Brings together pipe, coating, CP, environment, operating stress, temperature, cyclic loading, and other susceptibility factors to target direct examination.
SCCDA uses indirect surveys and direct examination to test whether SCC is present and where the mechanism is most likely to be active.
Boundary: SCCDA is complementary to other SCC assessment methods such as ILI or hydrostatic testing with a spike test; it is not automatically a substitute for them.
ECDA follows evidence of external corrosion. ICDA follows conditions that can create internal corrosion. SCCDA follows susceptibility and evidence associated with stress-corrosion cracking.
PHMSA Direct Assessment overview03 · FIELD VALIDATION
Integrity excavations and direct examination are where an assessment prediction meets the physical asset. NDE, coating observations, measurements, photographs, samples, metallurgical or laboratory work, and repair records can confirm, refine, or contradict what the assessment suggested.
The crew and technical team need to know what indication is being investigated, where it is expected, what measurements are required, and what evidence must be preserved.
Observed coating condition, corrosion morphology, crack characteristics, dimensions, NDE results, environmental observations, and photographs become part of the decision record.
The value of direct examination is not only the repair. The finding should feed back into tool performance, prioritization logic, threat models, future assessment, and the asset record.
04 · INTEGRITY EVIDENCE & DECISION CONTINUITY
Assessment results, field findings, repairs, operating history, and prior decisions become more useful when they remain connected over time. Software can support that continuity, but it does not replace reliable source data, context, validation, or qualified judgment.
Asset · Location · Date · Method · Conditions · Assumptions · Uncertainty · Disposition
History · Inspection · Field evidence · Remediation · Risk · Follow-up
Software can preserve and connect the evidence. It cannot replace the quality of the data, the context, or the judgment applied to it.
REFERENCE FRAMEWORK
This page uses broad pipeline-integrity principles. Regulatory and technical requirements vary by pipeline service, material, jurisdiction, and operator.
PHMSA integrity-management requirements and guidance for regulated gas and hazardous-liquid pipelines, including 49 CFR Parts 192 and 195.
EPA resources on drinking-water distribution system condition, integrity, asset management, maintenance, rehabilitation, and replacement.
