By the PICA Corp Engineering Team  |  Updated September 2026  |  Est. reading time: 9 min

A liner is installed to protect the steel. It also hides it.

That is the problem operators of lined pipelines hit the first time they schedule a condition assessment. The HDPE liner in a sour gas line, the cement mortar in a transmission main, the coal tar epoxy in an older water main: each puts a barrier between the sensor and the metal that carries the load. Handheld ultrasonic testing needs acoustic contact with that metal. Magnetic flux leakage needs a magnetic circuit to it. Put three quarters of an inch of polyethylene in the way and both have limited inspection capabilities.

Remote Field Testing works differently, and the difference explains why a technique first demonstrated in 1951 became the default method for assessing pipe nobody else can read.

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What is RFT inspection, and how does it read through a liner?

Remote Field Testing measures pipe wall thickness by sending a low-frequency electromagnetic field through the wall and picking it up further along the pipe. The Remote Field Eddy Current Testing method was first demonstrated by W.R. MacLean in 1951, using a setup still recognisable in modern tools: an exciter coil and a detector coil oriented along the pipe axis, separated by several pipe diameters.

The separation is the whole trick. The field from the exciter propagates both inside and outside the pipe. Inside, it attenuates sharply and becomes negligible within two to three pipe diameters. That is the direct field. Outside, it spreads along the pipe axis with far less attenuation, and at two to three diameters out it diffuses back through the wall. This returning component is the remote field, and it has crossed the pipe wall twice before a sensor ever reads it.

Figure 1. A basic RFT setup and plotting of ID and OD wall magnitude in three zones: direct, transition, and remote field. 1D, 2D, and 3D indicate one, two, and three pipe diameters from the exciter coil.

The consequence for lined pipe is direct. Because the measurement rides on a field that travelled through the wall rather than a sensor pressed against it, the sensor never needs to touch the steel. Liner, scale, deposits, and tool standoff are all just gap, and RFT tolerates gap.

Why liners defeat ultrasonic and magnetic flux leakage tools

The alternatives are not inferior methods. On unlined steel they are excellent. They just need something a liner takes away.

Ultrasonic testing needs acoustic contact

Handheld ultrasonic thickness measurement times a sound pulse’s return from the far wall. That pulse has to cross into the steel efficiently, which requires a couplant and a sensor near the surface. HDPE is acoustically dissimilar to steel, so the pulse scatters at the interface instead of crossing cleanly, and cement mortar behaves much the same. PICA uses handheld ultrasonic and EMAT probes heavily, but at excavated locations, not as an in-line method through a liner.

Magnetic flux leakage needs a magnetic circuit

MFL tools magnetise the wall to saturation and read the flux that leaks out at a defect. Saturating the wall requires brushes or magnets riding close to the steel. MFL has been the standard for in-line inspection of unlined steel pipelines in oil and gas for more than 50 years and remains the right tool there. On lined pipe the standoff weakens the magnetic circuit and capability drops accordingly.

Liftoff tolerance is the deciding property

Liftoff is the distance between sensor and steel. For UT and MFL it is an error source to be minimised. For RFT it is close to irrelevant within the working range, which is why the pipe types PICA inspects include materials unreadable to most in-line tools, and why a lined line can be assessed without cleaning back to bare metal. One limit: RFT reads the steel underneath the liner, so there has to be steel underneath the liner. It cannot inspect pure plastic or asbestos cement pipe.

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What RFT measures once it is inside a lined pipeline

RFT detects both local and general wall loss. Local loss covers discrete features such as pitting, dents, and cracks; general loss covers thinning spread over a broad area, which is what erosion produces. Reported accuracy is plus or minus 15 percent for local wall loss and plus or minus 5 percent for general wall loss, with a minimum reported defect volume of 1 inch by 1 inch at 20 percent wall loss.

Modern tools use multi-sensor arrays rather than a single detector. Each sensor reads a particular circumferential position, so the tool builds a picture rather than a line trace. That produces a C-scan style colour map of pipe condition and makes small pits detectable: a pit one sensor might clip is usually caught by two or three.

Figure 2. Colour map display of a pipe joint inspected by an RFT tool.

The limitation to be clear about

RFT sees wall loss on the internal surface and the external surface with equal sensitivity. It cannot tell you which one. The through-transmission signal crosses the full wall thickness, so internal and external loss appear together without differentiation. An analyst gets depth, length, and circumferential position, but not surface attribution. When that distinction drives a repair decision, the location is excavated and confirmed with ultrasonic or bracelet probe measurements. Anyone selling RFT as a technique that pinpoints ID versus OD corrosion is overselling it.

Stress registers too. Ground movement, uneven backfill, and subsidence during construction produce indications that ultrasonic and magnetic flux leakage inspection do not detect at all.

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Field results from lined and coated pipelines

HDPE-lined sour gas

Sour gas lines are internally lined with HDPE at a typical thickness of about three quarters of an inch, and many are insulated or rock-jacketed externally. That combination is close to a worst case for conventional in-line tools and a best case for RFT.

On one 6 inch HDPE-lined sour gas pipeline with a measured liner thickness of 0.62 inches, joint-average remaining wall came in within the manufacturing tolerance of plus or minus 10 percent of nominal. The line was in good general condition, but not uniformly good: three local wall loss defects between 25 and 40 percent deep sat near a girth weld. A general survey would have called that line healthy. The array found the three spots that were not.

Figure 4. Pipe joint average wall thickness versus pipeline distance for a 6 inch HDPE-lined pipe.

Corrosion inside a dent, under a jacket

A yellow-jacketed gas pipe had a rock pressing against it at the 6 o’clock position. The jacket was damaged, the pipe was dented, and corrosion started in the dent and continued unobserved. By the time of the RFT inspection, wall loss in the dented area had reached 95 percent. The jacket meant to protect that pipe is what concealed the damage while it progressed.

Figure 5. Corrosion within a dent caused by a rock pushing against a yellow jacketed pipe at the 6 o’clock position.

Under-deposit pitting in an oil line

Internal pitting beneath deposits rewards a multi-sensor array. In an 8 inch carbon steel oil pipeline with a 0.156 inch wall, an RFT run returned pits varying in depth and volume, several registered by more than one sensor.

Figure 6. Pitting defects detected by an RFT tool in an 8 inch carbon steel pipe with a wall thickness of 0.156 inch.

PICA’s published work on this application is set out in the technical paper on inspection of lined pipelines with in-line inspection tools.

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How an RFT tool is deployed in a lined pipeline

A tool consists of an exciter coil, detector arrays, and supporting modules for electronics and centralisation, built into sealed pressure-proof housings and articulated to negotiate elbows and fittings.

Figure 3. A PICA SeeSnake RFT tool.

Tools run free-swimming or tethered on a steel or fibre rope tow line, launched and retrieved through a standard pig launcher or an adaptor fitted to a riser. A tow pig and trailing stabilisation modules hold travel speed constant as pressurised fluid pushes the assembly along, and distance encoders fix defect locations precisely. Speed reaches about 1- 6 metres per minute depending on pipe size, wall thickness, and material. Onboard battery and storage support several days of continuous running, so a free-swimming tool covers dozens of kilometres in one run, while a tethered tool is limited by tow line length, usually under 4 kilometres. Data is downloaded after retrieval for analysis by PICA analysts.

Which tool goes in depends on diameter and whether the line can stay in service. HydraSnake enters 6 and 8 inch cast and ductile iron water mains through a fire hydrant with no excavation and limited service interruption, since flow still has to be reduced to manage tool speed. The SeeSnake and Chimera tools cover 2 to 36 inches in service. RAFT covers 36 to 48 inches and EMIT covers 48 to 96 inches, both out of service and assembled inside the pipe through standard access.

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Why one inspection method is rarely enough

RFT is the right answer for lined pipe. It is not the whole answer for a pipeline.

An RFT run returns steel condition. It does not photograph a cracked liner, map ovality, count broken prestressing wires with the sensitivity of a dedicated tool, or find a leak in a line that is still pressurised.

PICA selects methods against the failure mode rather than running one tool everywhere. Near Field Testing quantifies 5 or more adjacent broken wires or bars in concrete pressure pipe, and is used where RFT cannot be deployed. CCTV with laser and lidar profiling documents liner damage, joint condition, and internal deformation an electromagnetic tool cannot see. The NAVIGATOR multi-sensor acoustic sphere screens live pressurised lines for leaks, gas or air pockets, and flow-restricting deposits before anything is dewatered.

PICA’s article on NFT and RFT inspection tools compares the methods in detail, and the TRWD case study shows RFT on large-diameter concrete pressure pipe.

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What lined pipeline inspection costs

Cost follows diameter and access. Small and medium metallic lines in the 4 to 24 inch range typically run from several thousand dollars up to about $40,000 per mile, which covers most oil and gas production and gathering work and most distribution-scale water main inspection.

Large-diameter out-of-service programs are a different budget line. Concrete pressure pipe and lined transmission mains inspected with EMIT or RAFT run $100,000 to $200,000 or more per mile, driven by mobilization, dewatering, and the labour of assembling a tool inside the pipe.

Either figure is easier to approve next to the alternative. Inspection typically costs 10 to 50 times less than an unplanned failure on the same segment, before counting the regulatory exposure that follows a hydrocarbon release. PHMSA and AMPP both treat periodic assessment as a baseline expectation.

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Frequently asked questions

What is a lined pipeline, and why is it difficult to inspect?

A lined pipeline is a metallic pipe with a protective internal layer that stops the transported fluid from contacting the steel. Common linings include HDPE, cement mortar, coal tar epoxy, and plastic coatings. The lining is what makes inspection hard. Handheld Ultrasonic testing needs acoustic contact with the steel and magnetic flux leakage needs a strong magnetic circuit to it, so both have limited inspection capabilities once a liner separates the sensor from the pipe wall. Remote Field Testing tolerates that separation.

How thick a liner can RFT inspect through?

PICA’s RFT tools measure remaining steel wall thickness through internal linings, scale, cement, epoxy, and plastic coatings up to 25-30 mm, roughly 1 inch, thick. That covers the great majority of lined pipe in service. HDPE linings in sour gas pipelines typically run about three quarters of an inch, well inside the working range. Liner thickness has only a minor effect on sensitivity, because RFT measures through the full pipe wall rather than reading off the inside surface.

Does RFT tell you whether corrosion is on the inside or outside of the pipe wall?

No. RFT detects wall loss on the internal and external surfaces with equal sensitivity, but the through-transmission signal sees both at once and cannot separate them. An operator learns that a defect exists, its depth, its length, and its circumferential position, but not which face of the steel it sits on. Where surface attribution drives a repair decision, the location is excavated and confirmed with handheld ultrasonic or bracelet probe measurements.

Can RFT inspect HDPE-lined sour gas pipelines?

Yes. HDPE-lined sour gas lines are one of the applications RFT handles best. These pipes are lined internally to resist wet sour service and are often insulated or rock-jacketed externally as well, which leaves handheld ultrasonic and magnetic flux leakage tools with limited capability. RFT reads through the liner from the inside. PICA has inspected over 100 kilometres of HDPE-lined steel pipeline across more than 20 years of field trials and projects.

What size lined pipelines can RFT inspect?

PICA’s RFT tools cover 2 to 96 inches, selected by diameter and by whether the line can stay in service. HydraSnake handles 6 and 8 inch cast and ductile iron water mains through a hydrant. SeeSnake and Chimera cover 2 to 36 inches in service. RAFT covers 36 to 48 inches and EMIT covers 48 to 96 inches, both out of service and both assembled inside the pipe through standard access. Oil and gas work has concentrated on lines under 20 inches.

Can corrosion under a pipeline liner be caught before it causes a failure?

Yes, and this is the argument for inspecting lined pipe on a schedule rather than after an incident. Corrosion under a liner develops quietly, because the liner that hides the damage is also what makes operators assume the steel is protected. RFT measures remaining wall continuously along the run, so a thinning section is identified while it still holds pressure. The 95 percent wall loss found inside a rock-induced dent on a jacketed gas line was measurable long before it reached that depth.

How much does inspecting a lined pipeline cost?

Cost tracks diameter and access. Small and medium metallic lines from 4 to 24 inches typically run from several thousand dollars up to about $40,000 per mile. Large-diameter out-of-service programs on concrete pressure pipe and lined transmission mains run $100,000 to $200,000 or more per mile, reflecting mobilization, dewatering, and tool assembly inside the pipe. Against either figure, inspection typically costs 10 to 50 times less than an unplanned failure on the same segment.

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