By the PICA Corp Engineering Team | Updated September 2026 | Est. reading time: 9 min
In 2007 a Shell Canada sour gas pipeline failed from internal corrosion. The line had been lined with a polyamide liner in 2001 and re-lined with high density polyethylene in 2003. Neither liner had breached in service. The steel had corroded anyway, in the narrow annulus behind a liner that was doing exactly what it was designed to do.
Shell’s response was to build an inspection capability for pipelines the industry had written off as uninspectable. The technology was remote field testing (RFT) in-line inspection.
Key facts about HDPE lined pipeline inspection:
- Corrosion behind the liner (CBL) attacks the carrier pipe while the liner stays intact, so leak and pressure monitoring show nothing
- RFT reads steel wall thickness through polymer liners, scale, cement, epoxy, and plastic coatings up to 25-30 mm (about 1 inch) thick
- Shell Canada adopted RFT ILI after a 2007 sour gas failure and confirmed by repeat runs and verification digs that the corrosion had been brought under control
- PICA and Russell NDE Systems have inspected over 100 kilometres of HDPE-lined steel pipeline across more than 20 years of field trials and projects
The 2007 failure: a corrosion mechanism nobody was measuring
Shell Canada has moved sour gas through steel pipelines for decades. Sour service is hostile to carbon steel, so the standard mitigation is an internal polymer liner that keeps the product off the pipe wall. On paper that solves the problem. The 2007 failure showed it had moved somewhere no one was looking.
Methanol is injected into wet sour gas lines to control hydrates and prevent icing. Polymer liners are not impermeable to small molecules. Over years of service, methanol and water permeate the liner and collect in the annulus between the liner and the steel. Dissolved CO2, H2S, and oxygen come through with them. What accumulates behind the liner is a stagnant acidic film in direct contact with bare steel, with no flow to sweep it away and no inhibitor reaching it.
The liner then does something worse than fail. It holds. Product stays inside it, pressure holds, leak detection reads normal, and internal corrosion coupons in the product stream report a clean line, because the corrosion is not happening in the product stream. PICA’s technical library covers the incident investigation in detail in Corrosion Failure in a Lined Sour Gas Pipeline.
Why conventional in-line inspection had limited reach
Magnetic flux leakage has dominated oil and gas pipeline in-line inspection for more than fifty years, and for unlined steel pipelines it remains the standard. The physics that make it work are also what limit it here.
Sensor standoff is the constraint
MFL and handheld ultrasonic tools both depend on close proximity between the sensor and the pipe inside surface. A three-quarter-inch HDPE liner puts the sensor three-quarters of an inch away from the steel it is supposed to measure, and on many of these lines the pipe also carries external insulation or a rock jacket. MFL tools have limited inspection capabilities under those conditions. Handheld ultrasonic tools need a couplant path to the metal, which a polymer liner does not provide.
This is a narrower claim than it sounds. Unlined oil and gas flowlines are perfectly good MFL candidates. It is specifically some lined production pipelines and lined gathering systems that defeat standard MFL tools, and those are exactly the lines carrying the most aggressive product.
Remote field testing does not need proximity
RFT works through the pipe wall rather than off its surface. An exciter coil energizes the wall with a low frequency AC field. Part of that field exits the pipe, travels along the outside where attenuation is far lower, and diffuses back inside two to three pipe diameters downstream, where a receiver coil picks it up. The phase and amplitude of that returned signal are governed by the wall it passed through, twice.
Because the measurement is a through-transmission measurement, tool liftoff barely matters. A thick liner is a minor effect, not a blocker. That single property is why RFT could be adapted to water and wastewater pipeline inspection, from lined hydrocarbon service where it had been in use for years. The tradeoff worth stating plainly: the through-transmission signal sees wall loss on the inside surface and the outside surface without differentiating between them. It tells you how much steel is left, not which face lost it.
What Shell built, and how the runs went
After the 2007 failure Shell worked with Russell NDE Systems to develop a customized RFT ILI tool for their lined pipelines. PICA holds the exclusive commercial inspection rights to those tools.
Getting a tool down a lined line
Lined pipe is not friendly to in-line tools. The liner reduces the effective bore, liner ends at flange pairs create step changes, and the tolerances that matter are the ones nobody recorded during lining. Shell’s program treated liner restrictions and flange pair damage as engineering problems in their own right, separate from the inspection. Preparatory pigging came first, then gauge runs to confirm the tool would pass.
Speed control and calibration
Two operational lessons came out of the early runs. The first was speed. RFT sampling is distance-based, and a tool that surges through a section leaves gaps in the record, so travel speed has to be managed rather than assumed. The second was calibration. Where sample pipe with known defect dimensions is available, tools can be calibrated against it, which tightens sizing confidence considerably. That is a conditional step, not a routine one, and Shell’s experience made the case for arranging it when the pipe is available.
The third lesson was for design engineers rather than inspection crews: new lined pipelines should be built to accept ILI tools from the start. Retrofitting launch and receive capability is expensive, and it is why many lined systems still go uninspected.
What the inspections found
The RFT tool detected and sized corrosion behind the liner with accuracy confirmed by multiple runs and verification digs. That verification matters more than the detection. Detection alone tells an operator something is wrong somewhere; sized, located, repeatable data tells them which segments to dig and which to leave alone.
Shell’s corrective action was operational. Continuous methanol injection was identified as a significant contributor to the annulus environment and the practice was stopped. Subsequent RFT runs showed CBL had been effectively controlled after the change. The inspection program did two jobs at once: it found the damage, and it then proved the fix was working. Without repeat measurement, the second half is guesswork.
The same tooling was applied to a cement mortar lined produced water pipeline. Those lines accumulate solids, so the program needed extensive preparatory pigging before the tool could run cleanly. The inspection then identified areas of significant external corrosion and repairs were scheduled before failure rather than after it. Note the direction of that finding: on the sour gas line the threat was internal, on the produced water line it was external. One tool, two mechanisms, which is the practical argument for measuring wall thickness rather than hunting a specific defect type.
Why a single measurement is rarely enough
RFT gives continuous wall thickness along the full length of the run. It does not tell you everything.
Verification digs still need direct measurement at the excavation, which is where handheld electromagnetic and ultrasonic thickness testing earns its place, along with the Bracelet Probe for screening corrosion under insulation without stripping the jacket. Liner condition itself, disbondment, wrinkling, damage at joints, is a visual question best answered by CCTV and Lidar where the line can be accessed and taken out of service. On concrete pressure pipe assets in the same facility, NFT and RFT serve different conditions and are selected accordingly.
The Shell program worked because it combined in-line measurement with verification digs and an operational change, then re-measured. Any one of those steps alone would have produced a weaker result. PICA builds pipeline condition assessment programs the same way across water, wastewater, power, industrial, mining, and oil and gas assets.
What lined pipeline inspection costs
For small and medium diameter metallic lines in the 4 to 24 inch range, which covers most lined production and gathering systems, in-line inspection programs run from several thousand dollars to roughly $40,000 per mile. Cost drivers are access, how much cleaning the line needs before a tool will pass, and total length. Large diameter out-of-service programs are a different tier, running $100,000 to $200,000 or more per mile.
The comparison that matters is not inspection cost against zero. It is inspection cost against a sour gas release: emergency response, regulatory involvement, remediation, lost production, and potential H2S exposure. Shell ran those numbers after 2007 rather than before, which is the expensive order.
How PICA inspects lined pipelines today
The tooling has moved on considerably since 2010. PICA’s Advanced NDT service covers 2 to 96 inches using RFT.
In-service free-swimming tools, including the SeeSnake and Chimera tools, handle 2 to 36 inch lines at operating pressures of 300 to 500 psi. Flow reduction is required to keep tool speed in the 5 to 20 ft/min window, so there is an operational impact, but no shutdown or dewatering. Out-of-service EMIT and RAFT tools cover 36 to 96 inches, and both are rated for lined metallic pipe as well as concrete pressure pipe. Minimum reported defect volume is 1 inch by 1 inch at 20% wall loss.
Across more than 20 years, PICA and Russell NDE have inspected over 100 kilometres of HDPE-lined steel pipeline in field trials and projects. The technique itself is covered in more depth in Delicate Detection: the RFT technique for lined pipeline condition assessment, and the range of HDPE, PVC, and FRP applications is set out on the applications page. The Canadian Association of Petroleum Producers also publishes guidance on the use of HDPE lined pipelines.
Frequently asked questions
What is corrosion behind the liner (CBL)?
Corrosion behind the liner is metal loss on the inside surface of a steel pipe that occurs in the narrow annulus between the carrier pipe wall and an internal polymer liner. It happens when water, methanol, and dissolved gases such as CO2, H2S, and oxygen collect in that gap. Because the liner itself stays intact, the pipeline shows no leak, no pressure loss, and no visual warning while the steel behind it thins. Shell Canada’s 2007 sour gas failure occurred on a line where neither the original polyamide liner nor its HDPE replacement had breached in service.
How do you inspect an HDPE lined pipeline without removing the liner?
Remote field testing measures steel wall thickness straight through a polymer liner because it does not need sensor contact with the metal. The exciter coil energizes the pipe wall, the field passes out through the steel and returns to a receiver coil two to three pipe diameters away, and the phase and amplitude of that returned signal reflect the remaining wall. PICA’s RFT tools read through internal linings, scale, cement, epoxy, and plastic coatings up to about 25-30 mm (1 inch) thick, so a typical three-quarter-inch HDPE liner stays in place during the run.
Can a pipeline liner fail without leaking?
Yes, and this is the central risk in lined pipeline integrity management. A liner can disbond from the carrier pipe, allow permeated gases and liquids to collect behind it, and support aggressive localized corrosion of the steel while remaining watertight and pressure tight. Leak detection, pressure monitoring, and internal coupons all read normal in this condition. The first indication is often the failure itself. Detecting it requires a measurement of the steel wall, not a measurement of the product stream.
What causes methanol to accumulate behind a pipeline liner?
Methanol is injected into wet sour gas lines for hydrate control and de-icing. Polymer liners are permeable to small molecules, so methanol and water vapor migrate through the liner wall over time and condense in the annulus, where they cannot drain or be swept out by product flow. Combined with permeated CO2 and H2S, the result is a stagnant, acidic, oxygen-bearing film against bare steel. Shell’s response was to stop continuous methanol injection, which the follow-up RFT runs confirmed had brought the corrosion under control.
How is a lined sour gas pipeline inspected?
The pipeline is cleaned with preparatory pigging runs, gauged for restrictions, then run with an RFT in-line inspection tool launched through a pig trap, a riser adaptor, or an excavated access point. The tool records continuous wall thickness data on board while it travels with the product flow or on a tow line. Data is downloaded after retrieval and analyzed offsite. Verification digs at selected indications confirm sizing accuracy, usually with handheld electromagnetic and ultrasonic measurement at the exposed pipe.
Can corrosion behind the liner be prevented?
It can be controlled once you know it is happening, which is the harder half of the problem. Shell’s corrective action was operational rather than mechanical: ending continuous methanol injection removed the main contributor to the annulus environment. Repeat RFT runs then showed the corrosion rate had effectively stopped. Prevention on a lined system depends on managing what can permeate into the annulus and on periodic in-line measurement to confirm the strategy is working rather than assuming it is.
How much does inspecting a lined pipeline cost?
For small and medium diameter metallic lines in the 4 to 24 inch range, in-line inspection programs run from several thousand dollars to roughly $40,000 per mile depending on access, cleaning requirements, and line length. Large diameter out-of-service programs run $100,000 to $200,000 or more per mile. Against that, a single sour gas release carries release response, regulatory, remediation, and lost production costs that reach well into the millions, before any consideration of personnel exposure to H2S.
What size lined pipelines can be inspected in line with RFT?
PICA’s RFT tools cover 2 to 96 inches overall. In-service free-swimming tools including SeeSnake and Chimera handle 2 to 36 inch lines at operating pressures of 300 to 500 psi. Out-of-service tools including EMIT and RAFT cover 36 to 96 inches, with EMIT rated for internally lined AWWA C-301 and C-303 pipe and any lined metallic pipe from 48 to 96 inches. Oil and gas lined pipeline work has concentrated in the small to medium diameters, generally under 20 inches, which is where most lined production and gathering systems sit.
Do you know what your lined pipelines look like behind the liner?
If your integrity program relies on leak detection and product-stream coupons, corrosion behind the liner is invisible to it. PICA inspects lined steel pipelines from 2 to 96 inches using RFT tools that measure remaining wall thickness through the liner, with over 100 kilometres of HDPE-lined pipeline inspected across 20+ years.
Call: 1-800-661-0127 | Email: [email protected]