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Pipeline In-line Inspection –
Challenges to NDT

J. Bruce NESTLEROTH, Battelle, Columbus, OH, USA

Abstract. A vast network of pipelines transports large volumes of energy products
over long distances from production wells to processing and consumption sites. The
pipeline industry relies on nondestructive testing (NDT) methods to detect and
characterize the degradation and damage. To quickly and economically survey the
large portions of the infrastructure, autonomous in-line inspection tools, commonly
referred to as pigs, examine the pipe from the inside as they are propelled by the
product flow. Thousands of kilometres of pipelines are examined using various
implementations of electromagnetic and ultrasonic modalities. Inspection tool
developers are challenged to implement sensitive measurement technology on a
platform that must survive the pipeline environment. This paper will review
fundamental challenges that restrict the implementation of NDT technologies that
are applied in other industries. The anomaly types that affect pipeline operation will
also be reviewed to frame the gaps between inspection capability of existing tools
and inspection needs of the pipeline industry.

A vast network of pipelines transports large volumes of energy products over long
distances from production wells to processing and consumption sites. Historically,
pipelines have proven to be a relatively safe transportation mode. As with any
infrastructure, the integrity can be affected by time dependent degradation and abrupt
damage from outside forces. The pipeline industry relies on nondestructive testing (NDT)
methods to detect and characterize the degradation and damage. To quickly and
economically survey the large portions of the infrastructure, autonomous in-line inspection
tools, commonly referred to as pigs, examine the pipe from the inside as they are propelled
by the product flow. Inspection tool developers are challenged to implement sensitive
measurement technology on a platform that must survive the pipeline environment.
Inspection tools must meet measurement specifications for long distances at high speeds,
while negotiating tight bends that induce substantial forces, obstructions that protrude into
the pipe, debris that forces the sensors from the pipe and other inspection dilemmas.
Furthermore, the reliability of the inspection system must be high since the pipeline
anomalies are typically localized events, not general degradation. One inspection
technology, magnetic flux leakage, can be implemented to overcome the physical barriers
while adequately detecting and characterizing corrosion anomalies. Other technologies
address other classes of anomalies such stress corrosion cracking, mechanical damage,
seam weld anomalies and more precise corrosion assessment. Some pipelines, referred to
as unpigable, have excessive physical or operational barriers that prevent the use of
available pigs. Crawler technologies are being implemented that overcome these barriers,
sometimes with alternative inspection methods. After internal inspection, the details of the
anomalies are commonly quantified after excavation using more classical NDT methods.
In-the-ditch sizing methods for corrosion and cracking are used to quantify pigging results.
This paper will review the fundamental challenges that restrict the implementation of NDT
technologies that are applied in other industries. The anomaly types that affect pipeline

ECNDT 2006 - Mo.2.5.1


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operation will also be reviewed to frame the gaps between inspection capability of existing
tools and inspection needs of the pipeline industry.

Application of Inspection Methods to Pipelines

In-line inspection equipment is commonly used to examine a large portion of the long
distance transmission pipeline system that transports energy products from well gathering
points to local distribution companies. A piece of equipment that is inserted into a pipeline
and driven by product flow is called a ‘pig’. Using this term as a base, a set of terms have
evolved. Pigs that are equipped with sensors and data recording devises are called
‘intelligent pigs’. Pipelines that cannot be inspected using intelligent pigs are deemed
‘unpigable’. But many factors affect the passage of a pig through a pipeline, or the
‘pigability’. The concept of pigability pipeline extends well beyond the basic need for a
long round hole with a means to enter and exit. An accurate assessment of pigability
includes consideration of pipeline length, attributes, pressure, flow rate, deformation,
cleanliness, and other factors as well as the availability of inspection technology. All
factors must be considered when assessing the appropriateness of in-line inspection (ILI) to
assess specific pipeline threats. The process is illustrated in Figure 1.

In terms of implementing an integrity management plan (IMP), the first step is the
evaluation of potential threats that exist in the pipeline or segment being considered and
their credibility. Once the credible threats are established, the appropriate integrity
assessment method(s) are then selected. Where instrumented non-destructive ILI tools are
deemed appropriate, several preliminary aspects must then be considered. Otherwise,
alternative integrity assessment methods that may include pressure testing and direct
assessment will be required.

The first decision point shown in Figure 1 concerns the availability of inspection
technology. Each inspection technology implementation must be examined to determine
suitability of both assessment of threats and passage of pipeline attributes.

Some pipelines may constitute a single source of supply to a locale that cannot be easily
interrupted even for scheduled ILI or other maintenance operations. If an interruption does
occur, alternative (and often very expensive) supply sources such as truck is required to
maintain service. Even where suitable permanent launchers/receivers (or some temporary
configurations) are available, pipeline operating characteristics may need to be modified to
conduct a successful ILI integrity assessment. Such operating parameter modifications can
impact gas delivery and may not be acceptable. Also, more detailed piggability
assessment should be performed to ensure free passage of ILI tools.

The length of the pipeline or segment to be assessed is also an important initial
consideration. It is rarely practical to run product driven ILI tools in short segments of
pipeline that might include a short high consequence area (HCA), crossovers between
pipelines, and short length laterals. Equipping such pipelines or segments for periodic ILI
tool operation would be expensive unless the equipment was also used for other pipeline
operational purposes such as liquid removal. Furthermore, the required flow conditions for
proper ILI operation may be difficult to achieve in short segments. Costs for gas driven ILI
tools are typically compared on an approximate cost/mile basis that includes the ILI
vendor’s fixed mobilization charge. A typical cost/mile analysis shows that gas driven ILI
run lengths should exceed about 50 kilometres (30 miles) to approach the least unit cost.


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Other types of instrumented ILI tools (i.e., wireline ILI tools) are more appropriate for
shorter lengths of pipe.

Another initial consideration is the particular instrumented ILI technology that is capable of
assessing the established threats and the suitability of that technology in pipelines. Each of
the available ILI technologies has its strengths and limitations for anomaly detection. A
description of anomaly types that occur in pipelines is included later in this paper.
Inspection technologies for each of these conditions are at various stages of development.
Many of the inspection technologies are product specific and may not applicable in gas or
liquid pipelines in all cases.

Pipeline operating pressure and flow conditions can dictate if it is feasible to satisfactorily
operate an ILI tool. For gas natural pipelines, low pressure (25-40 bar, 400-600 psi) and
flow conditions may not be sufficient to efficiently drive a pig. A minimum gas pressure is
needed to assure stable ILI operation since higher pressures create a higher density fluid
column behind and in front of the pig thus minimizing speed variations and surges. The
effects of low pressures can be more extreme in hilly terrain since the gas column would
not effectively restrain the tool thus permitting velocity variations. Instrumented ILI tools
should be operated within their recommended velocity ranges to achieve optimum
inspection results. For example, magnetic flux leakage (MFL) tools speeds are typically 1-
3 m/s and inspection results can degrade when an ILI tool when operated out of the
recommended range, especially where excessive velocities occur.

Typical pipeline operating parameters may require modification to control flow rates and
product pressures thereby optimizing ILI inspection results. In some pipelines, the pressure
increases needed to assure satisfactory ILI operations may be precluded by pressure
limiting restrictions. This may include pressure regulator adjustments, compressor station
operation modifications, and flow throttling with valves. ILI tools equipped with gas
bypass technology are now being applied to provide improved inspection velocities in a
wider range of flow conditions.

Other operating conditions that can affect ILI operations include gas corrosivity that may
damage ILI tool components and high temperatures (> ~60 C) that can damage on-board
electronic components

Some pipelines contain identified threats that can potentially affect ILI passage such as
deformation and mechanical damage such as dents. Deformation may result from the action
of outside forces such as slides or floods. ILI passage can be limited by more localized pipe
deformation such as dents resulting from rocks in the right of way and impacts on the pipe
which is a leading cause of pipeline incidents. Deformation may reduce the pipe internal
cross section to the point that ILI tool passage may be impaired and repair would be
required prior to attempting an ILI tool run.

Other construction related threats such as wrinkle bends can have sufficient associated pipe
deformation that will impede pig passage. Mechanically coupled pipelines can be another
issue affecting ILI tool applications although some coupled pipelines have been
successfully assessed. ILI passage is not restricted by mechanical couplings but they
present a potential safety issue due to the lateral deformation that may be result when the
tool passes a coupling that is not sufficiently supported by the backfill.


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Pipelines can contain dirt, debris, debris, and deposited solids such as salt. Solid deposits
(i.e., salt) can form an adherent, solid barrier that affects pig passage and adversely impacts
ILI data quality, and can be very difficult to remove. Depending on conditions, pre-ILI
cleaning can be an essential element in obtaining good quality integrity data. Such foreign
materials can interfere with the sensors on instrumented ILI tools and also affect the
accuracy of geometry tools that may be run prior to the ILI. Cleaning can be accomplished
by various methods including chemical and dry (scrapers, brushes, magnets). Although an
ILI tool could be run in a dirty pipeline, the resulting data would be questionable thereby
implying a “pigability” issue.

Pipeline attributes are one of the most frequently quoted criteria that impact pipeline
pigability. This includes physical attributes such as reduced port or plug valves, short radius
or mitre bends, back-to-back bends, and branches or tees (side or inverted positions)
without bars. Pipelines containing any of these attributes must be modified prior running an
instrumented ILI tool. Other common features such as pipe diameter changes (> 2 inches)
can also prevent a continuous ILI run but can usually be assessed in separate segments.
Another similar issue is the presence of pipeline drips for fluid collection. In some cases, a
larger diameter pipe section (expansion chamber) is installed in the pipeline above the drip
to reduce the gas velocity and promote liquid drop-out into the off line drip barrel. Some
check valves can have internal dimensions larger than the pipeline. Depending on the
magnitude of such internal diameter increases, the ILI tool driving force imparted by the
flowing gas may be reduced to the point the tool stops.

Heavy wall pipe sections, such as those at road crossings and required by construction
codes, are another pipeline attribute that can affect pig passage. Line pipe is purchased
based on outside diameter tolerances so the internal cross section is reduced as the wall
thickness increases. This reduced internal cross section diameter of heavy wall pipe can
encroach on the minimum required diameter for ILI passage. Although some ovality is
present in most line pipe, its effect is more critical when considering ILI passage in heavy
wall pipe through further reduction of the internal bore. Pipeline components such as
induction bends and ells are often formed from heavy wall pipe to allow for thinning that
occurs during the forming process. The combination of heavy pipe walls and ovality in
induction bends have caused ILI tools to become stuck in a pipeline.

Other less frequently cited attributes can also exist that can also impact pigability. One such
feature is a suspended, aerial pipeline crossing. The additional dynamic stress created by
the moving ILI tool should be considered. Also, the configuration of the pipeline entering
and exiting such a crossing may preclude ILI passage. This type of feature would impede
the continuous pigability of a pipeline or segment but the adjacent pipeline could be
evaluated separately.

The tiered definition of pigability described above includes the presence of launcher/
receiver equipment. Several typical launcher/receiver configurations are:

1. Permanent launcher/receiver equipment installed.
2. Pipeline is equipped with permanent piping transitions to the mainline that include

full opening valves and flanges that permit attachment of launcher/ receivers and
associated piping while the line is in operation. ILI tools can then be run without
removing the pipeline from service.

3. The pipeline or segment is removed from service, cut, and temporary
launcher/receiver equipment is attached at the open ends to run the ILI tool. The


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temporary equipment is then removed and the segment is re-inserted into the line
following completion of the ILI tool run.

The first two launcher/receiver configurations facilitate ILI tool runs since the pipeline does
not have to be removed from service. These would be acceptable options for pipelines that
serve areas without redundant gas supply. The third option requires service interruption and
access to two locations for launcher/receiver installation and removal. In locations where
access to the pipeline is an issue and continuous supply is required, this option would
significantly impair pigability even though the pipeline attributes are suitable for ILI tool
passage. Another related issue concerns some pipelines that are equipped with permanent
launcher/receiver equipment that are too short to accommodate instrumented ILI tools.

Some pipes are not suitable for in-line inspection. For example, pipelines constructed of
seamless pipe can present unique log interpretation problems especially for MFL ILI tools.
Welded pipe produced from plate or skelp typically has a uniform wall thickness with good
surface quality. Seamless pipe, however, is often eccentric with a systematic wall thickness
variation around the pipe circumference. Also, the piercing process used in seamless pipe
production tends to introduce deformation at the pipe ID surface which is detected by ILI
tools. Compared to welded pipe, the inherent surface roughness of seamless pipe is another
issue. These features combine to produce higher ILI signal “noise levels” (high signal/noise
ratio) that are difficult to separate from defect signals when interpreting the log. This
reduces the accuracy of the integrity assessment made from the ILI log. For ultrasonic ILI
tools, the inclusion content is an important factor. The inclusion content can vary
significantly from joint to joint, with one joint permitting a high quality inspection and the
next being not inspectable.

Classes of Pipeline Anomalies

Inspection systems must provide information on anomalies that are likely to cause failures.
The United States Department of Transportation keeps a data base available via the internet
of failures on interstate pipeline failures. In these data, four general categories of failure
mechanisms are used:

Outside force and third party damage. These incidents involve an external force acting on
an otherwise sound pipe that damages or overloads the pipe to the point where failure
occurs. The force may be naturally occurring, such as in a landslide, or it may result from
construction equipment accidentally digging into or hitting the pipeline. Included here are
dents, gouges, dents with gouges, wrinkles, ripples, buckles, and over-stressed areas.

Environmentally induced failures. These incidents involve anomalies that were created by
the action or attack of an environment on the pipe. Included here are internal and external
corrosion, stress corrosion cracking, chemical attacks, weld seam corrosion, and internal

Material, construction and fabrication failures. These failures are due to anomalies that
were created during material processing, fabrication, and construction. Included here are
seam and girth weld anomalies, laminations, hard spots, and weld pinholes.

Operational error and miscellaneous causes. Failures in this category are generally the
result of operational or operator errors. An example of an operational error is cutting into a


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pipe line while it is under pressure. Incident data in this category were not considered as
candidates for inspection.

Anomaly Prioritization

Excluding operational causes of failures, the major cause of incidents is third-party damage
and outside force. Most of the failures due to third-party damage occur very soon after the
damage. Therefore, prevention of mechanical damage is key. Systems that monitor the
pipeline right of way of excavation equipment would prevent many failures; however there
is not a widely accepted practical approach to preventing third-party damage along
thousands of kilometres of right-of-way. Opportunities for a mechanical-damage detection
tool to detect the presence of mechanical damage are present because the impact to the
industry is high.

The next largest cause of pipeline failures is environmental anomalies. Environmental
failures were subdivided into a variety of categories, such as pitting, general corrosion,
erosion, and stress-corrosion cracking. Of these, the largest cause of failures is pitting
corrosion; general corrosion causes a significant, but smaller, number of incidents. These
two categories account for nearly 80 percent of the environmental incidents, and so, they
were given high priority. There are few incidents caused by stress-corrosion cracking.
Nonetheless, stress-corrosion cracking is a significant problem because it is expensive to
control, and, so it was given medium priority.

Material and construction anomalies cause the smallest number of incidents. While small,
the number attributed to each is comparable to that due to general corrosion and delayed
mechanical-damage failures. However, many material and construction anomalies can be
uncovered or proved to be inconsequential using hydrotests. So, they were given low

High Priority Anomalies

Pitting. Individual pits, by themselves, rarely cause ruptures. Instead, they generally lead to
leaks when not detected or sized properly. Pits are most important for liquid pipelines
where the cost of environmental remediation of leak defect can be significant. The most
important inspection parameter for individual pits that NDT systems should measure is

Patches of pits can interact to produce a combined defect whose length exceeds the critical
(unstable fracture) length of the pipeline. When this happens, a rupture can occur.
Consequently, separation of pits and the presence of corrosion between pits are important.
Analysis methodologies and prior test data suggest that pit interaction is small if the
separation is greater than, for example, six times the wall thickness or one inch.
Consequently, the most important inspection parameters for groups of pits that NDT
systems should measure are the separation distances, individual pit depths, overall (group)
length, and the presence of corrosion between pits.

General Corrosion. General corrosion, wall thinning, and other forms of general wall loss
can cause ruptures when the length of these anomalies is larger than the critical length for a
pipeline. Errors in reported length are generally not important. As a result, the most
important geometry parameters for general corrosion that NDT systems should measure are
depth and axial length.


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Medium Priority Anomalies

Gouges in Dents. For excavation damage that remains in the pipe, test and field data have
shown that cracking can occur at gouges in dents with significant rerounding. Gouging
creates a stress concentration and damages the microstructure under the indenter.
Rerounding locally strains the damaged zone, leading to micro or macro cracks. Subsequent
pressure cycles extend the cracks by stable tearing or low cycle fatigue. As a result, the
most important parameter for dents with gouges and rerounding that NDT systems should
measure is the presence of cracks. This has proven to be an elusive goal. A secondary,
parameter that may be more practical is the presence of dents with gouges and rerounding,
from which the cracking can be inferred.

Stress Corrosion Cracks. Stress corrosion cracks in pipelines typically start at many
locations. Stress corrosion cracking can lead to ruptures when multiple cracks coalesce to
form a single long defect. Crack coalescence is the subject of ongoing research and
development. Results suggest that coalescence is most likely in areas of sparsely populated
cracking when the cracks are nearly aligned axially. Coalesced cracks can grow in a stable
fashion until they are nearly through wall in high-toughness materials. So, the most
important defect parameters for stress corrosion cracks that NDT systems should measure
are depth and alignment of individual and coalesced cracks, especially in areas where the
cracking is relatively sparse.

Gouges without dents. The most important defect parameters for gouges without dents are
the width, depth, and length of microstructural damage.

Seam Weld Corrosion. Seam corrosion, when it occurs, often causes deep and long
anomalies, which can lead to ruptures. So, the maximum depth and length over which the
corrosion occurs are the most important defect parameters.

A Differential Inspection Pig

Magnetic flux leakage (MFL) is and will remain the most commonly used in-line
inspection method for pipelines[1]. MFL technology can successfully overcome the
physical and practical inspection challenges presented by transmission pipelines.
Ultrasonic systems are also useful in liquid pipelines for both corrosion and cracks [2-3].
However, many anomalies can affect the serviceability of a pipeline. Current in-line
inspection tools are limited in the variety of anomalies they can detect, and no
comprehensive method is available for finding all defect types.

Engineering decisions often require a broad range of information on all anomalies, as
opposed to detailed information on a limited number of defect types. A broad range of
information is better for overall risk assessment, while detailed information is better for
defect assessment and maintenance prioritization. Hydrotests can provide go/no go
information on most anomalies that can threaten pipeline integrity at the time of the test.
However, they are expensive, difficult, provide no information on subcritical (but possibly
active) anomalies, and not always practical. So, an alternative is needed that provides an
overall assessment of a line by determining whether any potentially threatening defect is
present. Such an assessment would be done as a replacement for hydrotesting.


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In-line inspection pigs have historically been used to detect and size corrosion defects.
More recently, tools have been built to detect and size other defects, such as mechanical
damage and cracks. But all tools have limitations, and no tool can accurately size all
defects. This is not a problem with one type of tool or another: regardless of the technology
used, all smart pigs have inherent limitations with regard to defect sizing. While these
limitations can be reduced through developments, pipeline operators will always be forced
to make potentially decisions for many years: leaving known anomalies in pipelines where
smart pigs indicate seemingly insignificant anomalies.

Pipelines can and do operate safely with corrosion, mechanical damage, and other defects.
Static defects rarely cause problems. Instead, new, spreading, or growing defects cause
problems. This new smart pig process that overcomes inherent limitations in current
pigging by:
Providing a smaller, easier to use, and cheaper to run tool whose primary purpose is to

detect changes
Detecting and prioritizing changes that could lead to integrity problems, including those

due to corrosion, mechanical damage, and coating disbond.
The pig would be designed to be run on a regular basis and use automated analysis

Because the pig would be built for detecting changes only, its sensor packages could be
simpler and smaller. The pig could be designed to pass through difficult obstructions (e.g.,
very tight bends and some reduced-port valves). In addition, it could be made to run with
little outside support and without the need for changes in operating conditions as the
inspection was performed. To apply the process, a pipeline company would purchase,
lease, or contract for a set of inspections using a difference-detection pig. Normally, the
same pig would be run each time, making data alignment and interpretation easier.
Software would quickly identify potential problems, directing maintenance and repair to
areas where they are most needed.


The pipeline industry relies on non-destructive inspection to ensure the serviceability of this
energy transportation infrastructure. The inspection is primarily performed by service
companies dedicated to providing implementations that overcome the physical constraints
of the pipeline system. However, not all pipelines can be inspected with current equipment
and not all potentially service limiting anomalies can be detected. Developments in new or
improved inspection technologies and novel deployment methods will help keep this
historically safe transportation mode functional for many more decades.

1. Nestleroth, J.B. and Bubenik, T. A., “Magnetic Flux Leakage (MFL) Technology for
Natural Gas Pipeline Inspection,” Battelle, Report Number GRI-00/0180 to the Gas
Research Institute, February 1999.
2. Reber, K, M. Beller, O.A. Barbian, and N. Uzelac, “A New Generation of Ultrasonic
Inspection Tools; How Defect Assessment Methods Influenced Design,” The Pipeline
Pigging, Integrity Assessment and Repair Conference, Feb 2002.
3. Williams, H.H., O.A. Barbian, and N.I. Uzelac, “Internal Inspection Device for
Detection of Longitudinal Cracks in Oil and Gas Pipelines,” ASME International Pipeline
Conference, Calgary, 1996.


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