Pipeline integrity management software that knows which segment is due, on what interval and what the last tool run left open
Pipeline integrity management is the program an operator runs over pipe that could affect a high consequence area: identifying those segments, assessing them on a schedule, analyzing the results against everything else known about the line, and remediating what is found inside stated deadlines. The intervals are written down. 49 CFR 195.452 sets hazardous liquid reassessment at five year intervals not to exceed 68 months, and 49 CFR 192.939 caps gas transmission reassessment at 7 calendar years. Neurobird holds the segment, the assessment and the repair clock on one record.
Neurobird Pipeline Integrity Management in short
- Hold the covered segment list and the annual verification that keeps it current
- Run the discovery clock from the assessment date, not from the day the report was opened
- Grade each anomaly into its immediate, 60 day or 180 day class and watch the date
- 68 months Outside limit on the five year intervals an operator must establish for continually assessing line pipe that could affect a high consequence area, with priority set by the risk the pipe poses to that area. PHMSA 49 CFR 195.452
- 180 days Time after an assessment within which an operator must obtain enough information about a condition to determine that it exists. If that is impracticable, the operator must notify PHMSA and give an expected date. PHMSA 49 CFR 195.452
- Pricing runs 450 to 2900 US dollars per month across 3 tiers. Early access is free.
What hazardous liquid and gas transmission operators actually deal with
Why it stays broken
Integrity work is produced by vendors and consumed by regulators, and the operator sits in the middle holding the deadlines. A tool run comes back as a file from an inspection company, the engineering call is made by a specialist, the repair is done by a construction crew, and the date that matters is the day the operator had enough information to know a condition existed. Nothing in that chain owns the calendar, so the calendar ends up in a workbook.
Under 49 CFR 195.452 an operator must obtain enough information about a condition to determine that it exists no later than 180 days after an assessment, unless it notifies PHMSA that 180 days is impracticable.
An operator must take prompt action to address all anomalous conditions in the pipeline that the operator discovers through the integrity assessment or information analysis.
How does Neurobird Pipeline Integrity Management work?
Define the segment
Why the segment is covered, which high consequence area it could affect, and the risk factors behind its place in the assessment schedule, kept where an auditor can follow the reasoning.
Run the assessment
Method, date and vendor recorded against the segment, with the anomaly list loaded, so the discovery clock starts on the assessment date rather than on the day of a review meeting.
Close the condition
Each anomaly carries its repair class, its deadline, the pressure reduction if one was taken, and the evidence that closed it, so an audit becomes a query rather than an excavation.
Neurobird Pipeline Integrity Management Compliance Platform
One record per covered segment: why it is covered, when it was last assessed and by which method, every anomaly the assessment returned, the discovery date, the repair class each condition falls into, and the reassessment interval that follows from all of it.
- 1Hold the covered segment list and the annual verification that keeps it current
- 2Run the discovery clock from the assessment date, not from the day the report was opened
- 3Grade each anomaly into its immediate, 60 day or 180 day class and watch the date
- 4Track reassessment against the 68 month and 7 calendar year outside limits
What changes with Neurobird Pipeline Integrity Management?
The same work, read left to right: how it runs today, and how it runs once the record is in one place.
| Today | With Neurobird Pipeline Integrity Management |
|---|---|
| An inspection report lands and the 180 day discovery clock starts running before anyone has opened the file | Hold the covered segment list and the annual verification that keeps it current |
| A dent is graded as a 60 day condition in one spreadsheet and a 180 day condition in another | Run the discovery clock from the assessment date, not from the day the report was opened |
| The covered segment list has not been verified since the census data moved and nobody is sure what is still covered | Grade each anomaly into its immediate, 60 day or 180 day class and watch the date |
Who is this for?
The same segment, three different programs.
You run to 195.452
Five year intervals not to exceed 68 months, discovery inside 180 days, and repair classes that start the day you knew. You need those dates derived rather than typed in by hand.
You run to subpart O
Covered segments, threat identification and a 7 calendar year reassessment cap. You need the threat analysis and the interval sitting on the same record as the segment.
You have a few hundred miles
No integrity department, one engineer and a consultant. You need the program to hold its own deadlines so an audit does not depend on one person's memory of last year.
What the rules say about integrity intervals
The hazardous liquid rule that puts discovery and repair on a clock, the gas transmission subpart that caps reassessment, and the sections that decide which segments are covered at all.
Outside limit on the five year intervals an operator must establish for continually assessing line pipe that could affect a high consequence area, with priority set by the risk the pipe poses to that area.
PHMSA 49 CFR 195.452Time after an assessment within which an operator must obtain enough information about a condition to determine that it exists. If that is impracticable, the operator must notify PHMSA and give an expected date.
PHMSA 49 CFR 195.452Deadline from discovery for evaluating and remediating a dent on the top of the pipeline deeper than 3 percent of the diameter, or any bottom side dent showing metal loss, cracking or a stress riser.
PHMSA 49 CFR 195.452Metal loss of nominal wall that is an immediate repair condition regardless of dimensions. Where no suitable remaining strength method can be identified, the operator must cut operating pressure by at least 20 percent until the anomaly is repaired.
PHMSA 49 CFR 195.452Outside limit on the annual verification of the risk factors used to identify which segments could affect a high consequence area, after which the endpoints have to be established again.
PHMSA 49 CFR 195.452Maximum reassessment interval for a covered gas transmission segment by any allowable method, with a 6 month extension available only on written justification submitted to the Office of Pipeline Safety.
PHMSA 49 CFR 192.939The segment board, as your integrity desk would work it
Load an assessment and watch the discovery date, the repair classes and the next interval move together.
| Requirement | Status | Next due | |
|---|---|---|---|
| SEG-22C, refined products, 60 day condition open | current | in 42d | |
| SEG-40D, newly identified area, baseline due within 5 years | due soon | in 9d | |
| SEG-14A, crude, inspection run 96 days ago, discovery due | current | in 120d | |
| SEG-31B, gas transmission, reassessment now at 82 months | overdue | 3d late | |
| SEG-40D, newly identified area, baseline due within 5 years | current | in 64d |
Tick a requirement to file evidence against it.
Pipeline integrity management software questions, answered
Key terms
- What is pipeline integrity management?
- It is the program an operator runs over pipe that could affect a high consequence area: identifying covered segments, assessing them on a schedule, analyzing the results against everything else known about the line, and remediating what is found. 49 CFR 195.452 covers hazardous liquid and subpart O of part 192 covers gas transmission.
- What are the reassessment intervals?
- For hazardous liquid, five year intervals not to exceed 68 months under 49 CFR 195.452. For gas transmission, a maximum of 7 calendar years under 49 CFR 192.939, with a 6 month extension only on written justification to the Office of Pipeline Safety.
When does the repair clock start?
At discovery, not at assessment. Discovery is the point where the operator has enough information to determine that a condition exists, and 49 CFR 195.452 requires that no later than 180 days after the assessment unless PHMSA is notified otherwise.
Does this replace our inspection vendor's analysis?
No. The vendor keeps the tool run and the sizing. This holds the segment, the dates, the repair class each anomaly falls into and the evidence that closed it, which is the part an audit actually asks to see.
How is a high consequence area defined for liquid lines?
49 CFR 195.450 defines it to include a commercially navigable waterway, a high population area, and an other populated area as defined and delineated by the Census Bureau, along with unusually sensitive areas.
Why we are building this
We went looking for work where the deadline is measured from a fact rather than from a date, and pipeline integrity kept coming up. Discovery is the day you had enough information to know a condition existed, which means the clock can already be running while the report sits unopened in a shared folder. That is a record problem, and record problems are what we build. The rules we read while scoping this are linked above, so you can check our reading of them instead of taking our word for it. If we have an interval wrong, tell us and we will fix it.
Where the requirement comes from
Primary sources, straight from the regulators.
- 49 CFR 195.452, hazardous liquid integrity management Baseline assessment, discovery, the immediate, 60 day and 180 day repair classes, and the five year interval.
- 49 CFR 195.450, definitions What counts as a high consequence area: navigable waterway, high population area, other populated area, unusually sensitive area.
- 49 CFR 192.939, required reassessment intervals The 7 calendar year cap, the split at 30 percent SMYS, and confirmatory direct assessment as the fallback.
- 49 CFR 192.911, elements of an integrity management program The written program a gas transmission operator has to have, element by element.
- 49 CFR 192.917, identifying and evaluating potential threats The threat categories, the data an operator must gather, and how risk assessment feeds the assessment schedule.
- 49 CFR 192.921, baseline assessment methods Which assessment methods are allowed for a covered segment and what each one has to be capable of detecting.
How much does Neurobird Pipeline Integrity Management cost?
Priced per operation because the deadlines attach to the covered segment rather than to the number of engineers looking at it. Segments, assessments and anomalies are unlimited on the upper tiers.
- Up to 300 miles
- Covered segment register
- Assessment scheduling
- Repair class tracking
- Unlimited mileage
- Liquid and gas rule sets
- Discovery clock automation
- Audit exports
- Several systems
- Threat analysis library
- Vendor data ingestion
- Priority support
Get free early access
Early access means we load your covered segments, your last assessments and your open conditions before you type anything, and the account stays free while we do it.
Straight answer on where this is: The software is in development. Nothing is purchasable today. Early access means you shape it and pay nothing while we build.
Prefer email? Write to office@neurobird.com and a person will reply. No autoresponder.