MFL Pipeline Inspection: Vendors, Cost Drivers & When to Use MFL vs UT (2026)

How MFL in-line inspection works, step by step

In one paragraph: An MFL in-line inspection tool is a train of modules pushed through the pipe by the product flow. Strong permanent magnets magnetize the steel wall close to saturation between two steel-brush poles. Where corrosion has removed metal, the remaining wall cannot carry all the flux, so some leaks into the pipe bore. A ring of sensors between the poles records that leakage continuously. Odometer wheels and inertial data tie each signal to a distance and clock position. Analysts later turn those signals into estimated length, width and depth for each metal-loss feature.

Each part of that chain affects what the final report can and cannot tell you.

• Magnetizer section. High-strength permanent magnets sit on a steel backing iron. Wire brushes or steel pole pieces press against the pipe wall and close the magnetic circuit, so the flux runs through the wall between the two poles. The aim is to drive the wall near magnetic saturation. A saturated wall gives a predictable leakage signal for a given loss of metal. A wall that is not saturated gives weak, distorted signals that are hard to size.
• Main sensor ring. Between the poles, a ring of sensors rides on the wall, usually Hall-effect devices or induction coils. Sensor spacing around the circumference largely decides the smallest feature the tool can resolve and how well it can estimate width. "High resolution" tools are mainly tools with denser sensor arrays and finer sampling along the pipe.
• ID/OD discrimination sensors. Leakage alone does not show whether metal is missing from the inside or the outside surface. Most tools carry a second sensor set, often eddy-current based or responding to the residual field after the magnetizer has passed. These sensors react only to near-surface internal features, so analysts can classify each call as internal or external. That matters because internal and external corrosion have different causes and different fixes.
• Odometers, inertial unit and caliper. Odometer wheels measure distance. An inertial measurement unit records pipe orientation and curvature. A caliper or geometry module records dents and ovality. Above-ground markers placed at known locations along the route let the data be corrected for odometer slip.
• Data and power module. Batteries and solid-state storage record everything for the whole run. Nothing is analyzed live. The data is downloaded after the tool is received at the trap.

A typical run sequence looks like this:

1. The operator confirms the line is piggable: launcher and receiver traps, bend radii, valve bores, tees with bars, and diameter changes.
2. Cleaning pigs remove wax, scale and debris that would lift sensors off the wall.
3. A gauging or dummy run confirms the tool will pass.
4. The tool is launched with the flow conditions agreed with the vendor.
5. After receipt, the vendor checks that sensors, odometers and data recording worked over the full length before the line returns to normal flow.
6. Analysis follows, under the reporting schedule in the contract.

Why speed, wall thickness and cleanliness change the result

The short version: MFL signals depend on how strongly and how steadily the wall is magnetized and how closely the sensors follow it. Anything that weakens magnetization or lifts the sensors degrades detection and sizing, even when the tool runs end to end without a fault.

Velocity. A magnetizer moving along steel induces eddy currents in the wall. These distort the field, and the effect grows with speed. A published review of ILI methods cites roughly 5 m/s as a practical upper limit for MFL because of this effect. Vendors state an acceptable speed band for each tool. Gas lines with high flow may need speed-control tools that bypass some gas, or reduced throughput during the run. Stretches run above the specified speed are normally flagged in the report as reduced-confidence data.

Wall thickness. Heavier walls need more magnetic energy to saturate. In thick-wall pipe, the tool's magnetizer may not reach full saturation. Signals for a given depth of metal loss then become smaller and sizing tolerances widen. Vendors state the wall-thickness range each tool is specified for. Check that heavy-wall sections such as road crossings, river crossings and station piping fall inside it.

Sensor lift-off. Debris, wax, internal deposits, weld protrusions and tight bends can lift sensors away from the wall. The leakage field falls off quickly with distance, so lift-off shows up as gaps or weak data. Thorough cleaning is part of getting usable data, not a formality.

Material and residual stress. MFL relies on the steel's magnetic properties. The review notes poor performance in poorly magnetized materials such as austenitic stainless steel. Changes in pipe grade or manufacturer along a line can also shift the baseline signal. Residual stress, cold work and dents change local magnetic properties and can produce signals that look like metal loss, or hide it.

How MFL tools size corrosion, and how to read a performance specification

The short version: MFL does not measure wall thickness directly. It measures a magnetic field and infers the geometry of the missing metal through calibrated models. Every reported depth is therefore an estimate with a stated tolerance and a stated level of confidence. It is not a measurement in the way a UT reading is.

Analysts classify each feature by shape, because sizing models behave differently for different shapes. Common classes include:

• general (broad) corrosion;
• pitting;
• axial and circumferential grooving;
• axial and circumferential slotting;
• pinholes.

The classes are usually defined relative to wall thickness. An MFL tool will typically size a broad patch of general corrosion better than a narrow pit of the same depth. Very small-diameter pits may be detected without being reliably sized.

A vendor's performance specification normally states three things for each feature class:

• Probability of detection (POD): the likelihood of detecting a feature above a stated size threshold.
• Probability of identification (POI): the likelihood of correctly classifying what the feature is, for example metal loss rather than a manufacturing anomaly.
• Sizing accuracy: a depth, length and width tolerance at a stated certainty, for example "plus or minus a percentage of wall thickness, a stated proportion of the time".

Read the certainty level as carefully as the tolerance. A tolerance that holds only most of the time means some features will be larger than reported. Integrity engineers allow for that when they set excavation and repair criteria.

API Std 1163 is the industry standard for qualifying ILI systems and validating their results. It covers how the stated performance is supported and how an operator confirms the tool met it on a specific run. ASNT ILI-PQ covers qualification of ILI personnel, and NACE SP0102 covers ILI programme practice.

What MFL misses, and why

The short version: MFL finds features that remove metal across a reasonable width. It is weak on anything that removes almost no metal, or that is lined up with the magnetic field.

A clean MFL report means no metal-loss features above the tool's reporting threshold were found. It does not mean the line has no cracks.

US integrity-management rules require operators to identify the threats on each segment and choose assessment methods able to address them. When cracking is a credible threat, a metal-loss MFL run on its own does not cover it. The 49 CFR 192/195 integrity management guide explains the threat-to-method link.

The regulatory chain: which rules point to ILI, and what they require

The short version: US federal pipeline rules do not require MFL by name. They allow in-line inspection as an assessment method, set the standards an ILI must follow, and set timelines for acting on the results.

• ILI conduct standards. 49 CFR 192.493 (gas) and 49 CFR 195.591 (hazardous liquid) require operators conducting in-line inspections under those parts to comply with API Std 1163, ANSI/ASNT ILI-PQ and NACE SP0102, which are incorporated by reference. Both allow tethered or remotely controlled tools if they comply with the applicable sections of NACE SP0102.
• Hazardous liquid integrity management. 49 CFR 195.452 lists in-line inspection tools capable of detecting corrosion and deformation anomalies among the allowed assessment methods. It sets continual assessment at intervals of five years, not exceeding 68 months, unless a longer interval is justified as the rule provides. Operators must obtain enough information about a condition to decide whether it threatens integrity promptly, and no later than 180 days after an assessment. Among the immediate repair conditions, the rule lists metal loss greater than 80% of nominal wall, regardless of dimensions.
• Gas transmission integrity management. 49 CFR 192.939 sets a maximum reassessment interval of seven calendar years for pipelines operating at or above 30% SMYS when assessed by an allowable method. It also provides a confirmatory direct assessment option where an operator's longer interval is justified. ASME B31.8S is the industry standard for gas integrity management that the Part 192 rules draw on. The ASME B31.8 guide and ASME B31.4 guide cover the construction codes.

The regulations have been amended several times, including changes to repair criteria and the extension of assessments beyond high consequence areas for gas transmission. Read the current eCFR text and PHMSA guidance rather than older summaries. A correction to the summary above on this page: the seven-year gas reassessment limit sits in 49 CFR 192.939, while 192.493 is the rule that brings API 1163, ASNT ILI-PQ and NACE SP0102 into ILI work.

From ILI call to dig: what happens at the excavation

The short version: Dig verification serves two purposes. It confirms or rejects specific anomalies so they can be repaired or cleared. It also supplies the field measurements that show whether the tool performed to its specification on this run. Both depend on good in-ditch NDE.

The work at a typical dig runs in this order:

1. Locating the feature. The dig sheet gives distance from the nearest upstream girth weld and from above-ground markers, plus clock position. The crew counts girth welds in the exposed pipe and measures from the reference weld to find the reported location.
2. Coating removal and visual examination. The coating condition is recorded before removal, because disbondment and the condition of the soil-side surface help explain external corrosion. After cleaning, the area is visually examined and photographed against a reference grid.
3. Measuring the metal loss. External corrosion is profiled with a pit gauge or a laser scanning system. Remaining wall is measured with ultrasonic thickness readings. Where internal corrosion was reported, ultrasonic corrosion mapping or phased array is used to map remaining wall over the whole reported area, not just one spot.
4. Looking for cracks. Magnetic particle testing (often wet fluorescent) on the cleaned surface finds surface-breaking cracks, including SCC colonies the MFL tool would not report. Where cracking is found, ultrasonic methods such as PAUT or TOFD help estimate depth.
5. Reporting against the tool call. The field report gives measured length, width, depth and location for each feature, in a format that can be matched to the ILI listing. The operator's integrity engineers then calculate remaining strength (for example by ASME B31G-type methods) and decide on repair. NDE technicians do not make that decision.

For tool validation, operators compare measured depth with reported depth for each verified feature, often on a unity plot. Points that fall consistently outside the stated tolerance, or that lean one way (such as consistent under-calling), point to a performance problem. That can change how the remaining anomalies on the run are treated. Consistent, well-documented dig measurements make this comparison meaningful. Single spot readings with no grid, location reference or calibration record do not. The ILI dig verification and API 1163 article covers the validation side in more depth.

Canada note

In Canada, CSA Z662 is the national standard for oil and gas pipeline systems. Federally regulated interprovincial and international pipelines are overseen by the Canada Energy Regulator. Provincially regulated lines are overseen by provincial regulators, such as the Alberta Energy Regulator in Alberta. These regulators expect integrity management programmes, and in-line inspection, including MFL, is widely used within them. The specific assessment and response requirements come from CSA Z662 and each regulator's rules, not from 49 CFR, so confirm them with the authority having jurisdiction.

Where Atlantis fits in an MFL ILI programme

Atlantis NDT does not run in-line inspection tools and does not set repair criteria. ILI runs are done by specialist ILI vendors. Decisions on remaining strength, repair and reassessment belong to the operator's integrity engineers.

Our role is the in-ditch NDE that the programme depends on:

• ultrasonic thickness and corrosion mapping;
• phased array;
• magnetic particle testing for cracking and SCC;
• TOFD for crack sizing;
• visual documentation.

The work is done by ASNT-certified technicians to procedures approved by an ASNT NDT Level III and reported in a format that can be matched against the ILI listing. Atlantis has supported more than 1,500 inspection activities. See pipeline inspection services, ultrasonic testing for pipelines and magnetic particle testing for pipelines, or request a dig-verification NDE scope. We reply within one business day.

More questions about MFL in-line inspection

How does an MFL pig work?

Permanent magnets and steel brushes magnetize the pipe wall near saturation as the tool travels with the flow. Where metal is missing, flux leaks out of the wall. A ring of Hall-effect or coil sensors records the leakage, and odometers and inertial data locate each signal along the line.

Can MFL tell internal from external corrosion?

Not from the main leakage signal alone. Most tools carry a secondary sensor set, often eddy-current based or responding to the residual field, that reacts only to near-surface internal features. Analysts use it to classify features as internal or external.

What is the difference between axial and circumferential MFL?

Axial MFL magnetizes along the pipe and is best for general metal loss and circumferentially oriented features. Circumferential or transverse-field MFL magnetizes around the pipe and responds better to axially oriented features such as narrow axial grooves. Research found it still detects only larger cracks.

Why can't MFL find stress corrosion cracking?

SCC cracks are tight and remove almost no metal. In axial-field tools they also run parallel to the field. Very little flux leaks, so the signal is below detection. Crack threats need ultrasonic or EMAT crack tools, plus in-ditch magnetic particle testing during digs.

How accurate is MFL depth sizing?

It depends on the tool, feature class, wall thickness and run conditions. Vendors state depth, length and width tolerances at a stated certainty for each feature class. Dig verification shows whether the run met that specification.

What rules govern how ILI is done in the US?

49 CFR 192.493 for gas and 49 CFR 195.591 for hazardous liquid require operators to follow API Std 1163, ANSI/ASNT ILI-PQ and NACE SP0102 when conducting in-line inspections. Integrity-management sections then set assessment intervals and response timelines.

What NDE is done at an ILI dig?

Typically visual examination and profiling of external corrosion, ultrasonic thickness or corrosion mapping for remaining wall, magnetic particle testing for surface cracks, and PAUT or TOFD where crack depth is needed. Results are reported against the ILI feature list.

Next step

Atlantis performs the NDE this work needs and reports to your inspector of record. To go further, request an inspection quote or talk to a Level III about procedures and technique. We reply within one business day.