PHMSA's Pipeline Safety Integrity Management Program, codified in 49 CFR Part 195 for hazardous liquid pipelines (and 49 CFR Part 192 for gas transmission), is primarily a pipeline integrity standard — it addresses the pipe itself, its welds, its corrosion protection, and its pressure containment. It does not, as a regulatory matter, specifically mandate condition monitoring of rotating equipment. What it does require — and where rotating equipment monitoring becomes materially relevant — is in the broader Integrity Management Program (IMP) framework's requirements for data integration, anomaly identification, and root-cause analysis documentation.
What 49 CFR Part 195 Actually Requires of Operators
Part 195 Subpart F (Integrity Management) requires hazardous liquid pipeline operators to: identify High Consequence Areas (HCAs) in their system; perform baseline assessments and re-assessments at defined intervals; identify and evaluate threats (including "equipment failures" as a threat category in the PHMSA threat taxonomy); develop preventive and mitigative measures; and maintain records documenting all of the above.
The equipment failure threat category in the PHMSA threat taxonomy specifically includes pump station failures as pipeline integrity threats. A pump cavitation event that leads to impeller damage and loss of containment, a compressor seal failure in a gas gathering line, or a pump station fire initiated by a mechanical seal failure in a Class I Division 1 hazardous area are all pipeline integrity events that could require PHMSA incident reporting if they meet the reporting thresholds in 49 CFR 195.50.
Condition monitoring data — vibration trends, bearing temperatures, process variable history — becomes part of the documentary record that supports root-cause analysis after an equipment failure event, and that supports the preventive measure documentation required by the IMP. A well-structured condition monitoring program, with historian-backed time-series records, makes the PHMSA RCA documentation process substantially more supportable than reconstructing equipment behavior from maintenance logs alone.
Process Safety Management (OSHA 1910.119) and the Overlap with PHMSA
Many midstream facilities — particularly gas processing plants, NGL fractionation units, and large compressor stations — are subject to both PHMSA and OSHA Process Safety Management (PSM) requirements under 29 CFR 1910.119. PSM applies when a facility processes or stores hazardous chemicals above threshold quantities; for natural gas liquids and H2S-bearing gas streams, this threshold is frequently met at gas processing plants.
OSHA PSM requires, among other elements, a Mechanical Integrity (MI) program covering all process equipment including rotating machinery. The MI program must include written procedures for maintenance activities, training for personnel, inspection and testing of process equipment, and documentation of any deficiencies found and corrective actions taken. PSM does not require continuous vibration monitoring, but it does require that inspection and testing intervals be established based on "applicable manufacturer's recommendations and good engineering practices" — a phrase that leaves room for condition-based maintenance intervals supported by monitoring data.
Where continuous condition monitoring becomes particularly relevant to PSM Mechanical Integrity is in demonstrating due diligence on high-consequence equipment. A centrifugal compressor at an amine treating unit handling a 35% H2S-containing gas stream, if it fails due to a bearing failure that was preceded by 6 days of detectable vibration trend increase, is a potential PSM incident regardless of PHMSA jurisdiction. The existence of a condition monitoring program — and the question of whether its alerts were acted upon — will be part of any PSM incident investigation.
RAGAGEP and the Role of Industry Standards
OSHA PSM uses the term "Recognized and Generally Accepted Good Engineering Practices" (RAGAGEP) as the standard of care for mechanical integrity. RAGAGEP standards relevant to rotating equipment monitoring include: API 670 (machinery protection systems), API RP 686 (recommended practice for machinery installation and installation design), API 612/617/618 (steam turbines, centrifugal compressors, and reciprocating compressors respectively), and ISO 20816 (vibration severity evaluation). A condition monitoring program that is designed to support these RAGAGEP standards — using API 670-specified sensor types, ISO 20816 severity zone references, and alarm setpoints grounded in API recommendations — provides a stronger defensible position in the event of a PSM incident investigation than an ad-hoc approach.
We are not saying that implementing condition monitoring makes a facility PSM-compliant or creates any regulatory safe harbor. We are saying that a structured monitoring program, documented against RAGAGEP references, supports the PSM Mechanical Integrity element's intent and provides substantially better incident investigation documentation than unstructured maintenance records.
API RP 754 Process Safety Indicators: Where Condition Monitoring Feeds the Lagging/Leading Indicator Framework
API Recommended Practice 754 (Process Safety Performance Indicators for the Refining and Petrochemical Industries) is widely used in gas processing and NGL operations to categorize safety events by severity — Tier 1 (the most severe: unplanned releases meeting defined criteria), Tier 2 (significant process safety events), Tier 3 (challenges to safeguards), and Tier 4 (leading indicators such as near-misses and unsafe conditions).
Condition monitoring data feeds the leading indicator tier. A compressor bearing that was showing accelerating vibration trend for 10 days before an operator-initiated shutdown for inspection, which upon teardown revealed a bearing outer race spall of 40% of the rolling element contact area — that is a Tier 4 near-miss that belongs in the API RP 754 leading indicator tracking. The condition monitoring alert that preceded the shutdown is the detection mechanism for that Tier 4 event. Without the monitoring data, the event may never surface as a leading indicator at all.
Practical Alignment: What "Designed to Support PHMSA IMP" Means
Midstreamly's platform is designed to support PHMSA Integrity Management Program documentation requirements — specifically the equipment failure threat data collection, the anomaly identification and evaluation documentation, and the corrective action tracking. This is distinct from claiming PHMSA compliance, which is a regulatory status earned by the pipeline operator through their IMP program, not a software certification.
In practice, "designed to support IMP documentation" means: all anomaly alerts include a timestamped record of the alert threshold, the measured value at alert time, and the equipment's condition history leading up to the alert; alert dispositions (acknowledged, investigated, work order created, cleared) are logged with timestamps; and the export format for incident investigation packages is structured to support root-cause analysis documentation in line with PHMSA guidance on equipment failure threat investigations.
For a mid-size midstream company operating a gas gathering and processing system in the Midcontinent or Permian Basin, the practical benefit of this structure is that when a PHMSA compliance inspection asks for documentation of how equipment failure threats are identified, evaluated, and mitigated, the condition monitoring system records provide a substantial portion of that documentation trail automatically — rather than requiring manual reconstruction from maintenance ticketing systems.
If your IMP program includes equipment failure threats and you want to see how condition monitoring data supports the documentation requirements, book a technical session with our team.
