Approximately 40% of global pipeline infrastructure cannot be assessed using conventional in-line inspection tools (source: PHMSA). These pipelines lack pig traps, have tight bends, diameter restrictions, heavy wax buildup, or insufficient flow velocity to drive inspection tools through. For these assets, integrity management is built on periodic, incomplete data — and every assessment carries uncertainty that cannot be quantified because the baseline does not exist.
What Makes a Pipeline Unpiggable
"Unpiggable" is not a single condition. It describes a range of physical and operational constraints that prevent conventional ILI tools from passing through the line:
- No pigging facilities — pipelines designed before ILI existed, without launchers or receivers
- Multi-diameter sections — diameter changes that no single tool can navigate
- Tight radius bends — bends too sharp for standard ILI geometry
- Subsea configurations — access points that require marine mobilisation
- Low flow velocity — production rates insufficient to push tools through the line
- Wax or debris accumulation — internal conditions that would trap any tool sent through
"Unpiggable" is not the same as "uninspectable." A pipeline may be technically inspectable through alternative means — but those alternatives come with their own limitations.
What Integrity Management Looks Like Without ILI
When conventional ILI is not an option, operators rely on a combination of indirect methods:
- ECDA (External Corrosion Direct Assessment) — surface surveys to identify coating defects
- DCVG (Direct Current Voltage Gradient) — detection of cathodic protection anomalies
- Corrosion coupons — periodic samples of corrosion environment
- UT spot checks — localised wall thickness measurements at accessible points
- Risk-based prioritisation — focusing limited resources on highest-consequence segments
All of these are point-in-time. All provide limited coverage. None deliver continuous visibility of wall condition between assessment windows.
Risk-based prioritisation still leaves pipelines uninspected for years. Predictive models built without real operational data are "garbage in, garbage out." The operator manages risk. The risk does not go away.
Two Operational Examples
A gas lift system built in 1968 — no pigging facilities, operating beyond design life, no business case for retrofit inspection, approaching decommissioning. The uncomfortable question: close your eyes and hope, or invest in understanding what you have?
A 32-inch export pipeline at end of field life — aging infrastructure, elevated terrain, insufficient pressure to push ILI tools through high points. The asset carries significant consequence. The inspection options are limited.
These are not edge cases. They are common. And the engineers responsible for them are making integrity decisions without the data they need.
The Regulatory Tailwind
The regulatory environment is changing. PHMSA's Mega Rule (49 CFR Part 192/195) is progressively extending integrity management requirements to previously exempted assets. UK HSE Pipeline Safety Regulations continue to evolve. The regulatory expectation is clear: operators must demonstrate they understand the condition of their assets.
The technology to address the gap is maturing simultaneously. The question is no longer whether continuous monitoring is possible — it is whether the industry is ready to deploy it.
Closing the Gap — Continuous Monitoring for Unpiggable Assets
Continuous external monitoring does not replace ILI — it addresses the assets where ILI is not an option. The approach:
- Non-intrusive clamp sensors installed without shutdown or pipeline access
- Continuous wall condition data streamed to analytics platform
- Operational data integration for context (flow, pressure, temperature)
- Prediction analytics anchored to governing code equations (ASME B31G, API 579)
The result: visibility where there was none. Confidence-rated assessments where there were only assumptions. A baseline that updates continuously instead of every five years.