Review
Inspection and monitoring systems
subsea pipelines: A review paper
Structural Health Monitoring
2020, Vol. 19(2) 606–645
Ó The Author(s) 2019
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DOI: 10.1177/1475921719837718
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Michael Ho1 , Sami El-Borgi2, Devendra Patil3 and Gangbing Song1
Abstract
One of the largest movers of the world economy is the oil and gas industry. The industry generates billions of barrels of
oil to match more than half the world’s energy demands. Production of energy products at such a massive scale is supported by the equally massive oil and gas infrastructure sprawling around the globe. Especially characteristic of the industry are vast networks of pipelines that traverse tens of thousands of miles of land and sea to carry oil and gas from the
deepest parts of the earth to faraway destinations. With such lengths come increased chances for damage, which can
have disastrous consequences owing to the hazardous substances typically carried by pipelines. Subsea pipelines in particular face increased risk due to the typically harsher environments, the difficulty of accessing deepwater pipelines, and
the possibility of sea currents spreading leaked oil across a wide area. The opportunity for research and engineering to
overcome the challenge of subsea inspection and monitoring is tremendous and the progress in this area is continuously
generating exciting new developments that may have far reaching benefits far outside of subsea pipeline inspection and
monitoring. Thus, this review covers the most often used subsea inspection and monitoring technologies as well as their
most recent developments and future trends.
Keywords
Subsea pipeline, inspection, monitoring, oil and gas, sensors, pipeline monitoring, damage detection, leak detection,
smart sensing, robotic inspection
Introduction
Background
The oil and gas industry stands as the world’s foremost
producer of energy. In the year 2016, more than half of
US energy was produced by the oil and gas industry
(Figure 1, left). Furthermore, according to a review
conducted by BP, world energy consumption is still
dominated by oil and gas products (Figure 1, right).
The demand of energy is expected to keep growing
as several countries are entering an economic growth
phase, which leads to increased demand on the energy
sector.3 As energy demand around the world increases,
the energy production infrastructure expands correspondingly. An increasingly favored direction for such
expansion is toward oil and gas production, including
subsea. Subsea oil and gas operations are complex,
requiring a wide range of structures and systems to
work together to extract petroleum from underground
reservoirs and carry them to the topside. Such operations must be executed with the goal of simultaneously
staying within economical limits and minimally affecting the environment. Crucial to this goal are subsea
pipelines, which carry oil and gas across vast distances.
For example, the US Gulf of Mexico (GoM) has hosted
the installation of over 45,000 miles (;72,000 km) of
pipelines from 1952 to 2017, 26,000 miles (;42,000 km)
of which are still active.4 Subsea pipelines can also
extend into tremendous depths, with one of the deepest
pipelines installed at 9500 ft. (;2,900 m) in the US
GoM.5 Similarly ambitious is the Nord Stream, which
is so far the longest single subsea pipeline, stretching
across 761 miles (;1220 km) in the Baltic Sea.4
1
Smart Materials and Structures Laboratory, Department of Mechanical
Engineering, The University of Houston, Houston, TX, USA
2
Mechanical Engineering Program, Texas A&M University at Qatar, Doha,
Qatar
3
Department of Mechanical Engineering, BITS-Pilani KK Birla Goa
Campus, Zuarinagar, Goa, India
Corresponding author:
Michael Ho, Smart Materials and Structures Laboratory, Department of
Mechanical Engineering, The University of Houston, 4800 Calhoun Road,
Houston, TX 77204, USA.
Email: siuchun.ho@gmail.com
Ho et al.
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Figure 1. (Left) Energy production in US by sector.1 (Right) World energy consumption by energy type.2
Figure 2. (Left) Offshore pipeline accidents (red dots) in the Gulf of Mexico.10 (Right) Proportion of causes leading to pipeline
damage and failure.8
Transportation of produced hydrocarbons have
always been a major financial concern for the industry,
as transportation by either pipeline or by tankers
requires major, upfront investment before any hydrocarbon is produced. Through economic, safety, and
environmental point of view, pipelines could be considered as the most preferred method of transportation of
petroleum fluids during exploration from subsea structures (such as wells) to the floating production facilities
and during transportation from these facilities to the
onshore processing plants. The diameter and length of
these pipelines, operating pressures, subsea terrains,
submarine environments, and fluid characteristics are
key determinants of subsea pipeline costs. Based on
these factors, the cost to build a subsea pipeline ranges
from several hundred thousand dollars per kilometer to
several millions per kilometer. For example, the 753mile-long (;1,213 km) Blue Stream gas pipeline that
crosses the black sea cost US$3.2 billion.6
With pipelines being the costliest, largest and most
widely installed component of the subsea infrastructure, they also bear the highest possibility of suffering
damage from both artificial and natural causes. A
study by DNV (Det Norske Veritas) shows that the
frequency of failure for various types of offshore pipeline structures ranges from 6.8 3 1026 to 4.5 3 1023
per km year.7 A recent report from the Bureau of
Ocean Energy Management stated from 1964 to 2013,
a total of 514 offshore pipeline–related oil spills were
recorded, 20 of which involved spills greater than
1000 bbl of oil.8 Based on extensive investigation by
Bureau of Safety and Environmental Enforcement
(BSEE) analysts, offshore pipeline failures were categorized into five categories: equipment failure, external
forces (e.g. human error), corrosion, weather/natural
causes, and vessel/anchor/trawl damage.8 Section
‘‘Possible failure modes of subsea pipelines’’ will further
discuss causes of subsea pipeline failure, including a
similar categorization by the US Department of
Transportation (DOT) and CONCAWE. These five
causes account for a majority of subsea pipeline failures, although several factors may cooperate to result
in severe consequences, such as the case for the
Humble Oil pipeline in 1967 where an anchor tore
through an already corroded pipeline (160,638 bbl).9
Figure 2 (left) depicts the locations of pipeline-related
accidents in the GoM, which is a hot spot for oil and
gas activity, and Figure 2 (right) shows the distribution
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Figure 3. Distribution of damage causes to different levels of oil spills from subsea pipelines.8
of offshore pipeline accidents due to the listed five
causes.
On the contrary, Figure 3 details the factors contributing to different spill volumes. Several trends can be
observed; for example, corrosion is more predominant
in small leaks, whereas vessel-related accidents are more
prevalent in large leaks. Thus, the data suggest that
small and large leaks may be more easily detected and
their damage mitigated by monitoring for corrosion
and impacts, respectively. Equipment failure and external forces, which include human error, are mostly constant across all types of failures, and monitoring for
specific causes within these two families of damages will
be useful in mitigating damage for all sizes of oil spills.
The relatively wide spread presence of equipmentrelated pipeline accidents is highlighted by the recent
BSEE reports regarding bolted connection failures in
subsea components, including risers and issuance of an
industry-wide alert to improve safety standards.11 In
response to the constant occurrence of pipeline accidents and the potential threat of each accident to all
stakeholders, several industrial organizations have
gathered to form response teams as well as dedicated
groups aimed to rapidly counteract pipeline emergencies. Examples include the Chevron Deepwater Pipeline
Repair System project12 and the Deepwater Response
to Underwater Pipeline Emergencies (DW-RUPE),
which is a joint industry organization headed by Stress
Engineering.13
A way to minimize damage due to the consequences
of pipeline failure is to continually monitor pipelines
for potential sources of failure. Structural health monitoring (SHM) technologies, which have long been used
for the monitoring of civil structures, are now also
being applied for the monitoring of subsea pipelines.
The added challenge of the subsea environment and the
sheer size and scope of the problem presents a
uniqueness to much of the SHM methods used for subsea pipelines.
In the literature survey that follows, a brief survey
of various SHM strategies is provided. The premise is
that, given the right selection of sensors and algorithms
for continuous monitoring of the structure in question,
SHM technology can successfully be used to identify
precursory anomalies that can lead to failure.14 It is
important to reiterate that successful implementation
of a SHM strategy depends on two key technical
aspects, that is (a) instrumentation and (b) algorithms
and mathematical models for analyzing the measured
signals. Hence, the literature survey will focus on delineating the dual challenges of instrumentation and
modeling from the standpoint of subsea pipelines.
Challenges in inspection and monitoring of subsea
pipelines
Multiple issues and obstacles make the inspection and
monitoring of subsea pipelines a challenging task.
Problems may occur throughout the life of the pipe,
and the environment in which the pipeline may lay for
decades is highly complex and full of potential dangers.
Potential issues in pipeline integrity begin at the design
stage. Pipeline design is affected by multiple factors
identified during the early stages (i.e. conceptualization,
front end engineering and design (FEED) stage,
detailed engineering) of a project.15 Key aspects such as
the site selection, pipeline route survey, local oceanic
conditions, material selection, wall thickness design,
pipeline protections (e.g. coatings, sleeper supports),
and the budget all contribute to the life expectancy of
the pipeline and can limit what kind of inspection and
monitoring routines and solutions can be used in the
future. Once the project is executed, both expected and
unexpected challenges to pipeline integrity need to be
Ho et al.
resolved for flow assurance. The following provides an
overview of challenges to inspection and monitoring of
subsea pipelines; for further details in pipeline design
and flow assurance, references such as Bai and Bai16
may be consulted.
The pipeline physically begins at the manufacturing
stage, where raw stock material is processed into plates
or rods and processed into tubular structures. Defects
in the raw material and imperfect welding (if welding is
used) should be detected to minimize problems later.
The size of the pipe (diameter from 3 in for gas to 72 in
for oil and gas17,18) and wall thickness (3/8 to 3 in18) of
the pipe determines the manufacturing process to be
used. The size and wall thickness will also decide what
inspection and welding technologies will be feasible.
Welding is a complicated procedure involving careful
selection of proper equipment and weld material.
During the manufacturing process, pipe segments can
be coated to protect against corrosion and abrasion.
Additional layers can be added depending on the
requirements of the project. For example, subsea pipelines often have an outer concrete coating to help protect against corrosion and impacts and stabilize the
pipeline by adding additional weight.19,20 Pipe-in-pipe
designs may also be implemented if additional layers of
protection and thermal insulation are needed.21
From an inspection and monitoring perspective,
each layer of coating poses an additional layer of challenge. In addition to the inspection of the primary
metallic body of the pipeline, each layer may also need
to be inspected for damage and debonding from the
pipeline. Depending on the inspection task and the
technology used, part of the pipe may need to be completely stripped of coatings in order to fully inspect for
damage. Completed and quality tested pipes are eventually shipped to the pipe-laying ship. The long-term
effects of the environment on the pipe and its coatings
should be considered if the pipes are to be stored on
the ship and are continuously exposed. If repeatedly
exposed to air and moisture, the pipes may put at risk
of accelerated corrosion.
During the pipe lay process, individual pipe segments are welded end to end to form the pipeline. The
pipeline is deposited from the ship at the same time that
new pipe segments are added to the pipeline. If the pipe
lay is not done properly, excessive bending stresses can
cause fractures and buckling in the pipeline when the
pipeline slides down from the ship and when the pipeline touches down on the sea floor. Different pipe lay
methods are available to suit the particulars of a project
and minimize the risk of pipeline damage. As the pipeline reaches the seafloor, immense hydrostatic pressure
of the water column attempts to crush the pipeline,
especially when no internal pressure is present during
installation. On the other hand, the low temperature of
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the sea floor (4°C) can cause a global contraction of the
pipeline, while heat coming up from the reservoir fluid
will cause local thermal expansion of the pipeline. If the
pipeline is restrained and not allowed to axially compress or expand, stress develops in the pipeline. If the
stress exceeds the hold of the restraints (e.g. rock
dumps), the initial temperature change from the influx
of warm reservoir fluids can cause the pipeline to
deform laterally and shift positions (i.e. ‘‘pipeline walking’’). Temperature or pressure changes later in the
pipeline operation can still cause pipeline walking if the
proper restraints are not put in place. The effects of
temperature and pressure are further complicated by
irregularities in the seafloor terrain and the friction
between the pipeline and the seafloor (i.e. pipe-soil
interaction).22 Without proper design and compensating measures (e.g. embedment into seafloor, use of sleeper supports, and concrete coatings), the stress build up
in the pipeline can cause buckling in multiple places.23–26
Monitoring of the pipeline installation process can help
ensure pipeline integrity. Surveying the pipeline will let
operators know if pipeline walking has occurred (and
thus suggesting problems with restraints or that pressures and temperatures have exceeded expectations)
and if remedial action is needed.
Over time, on the seabed, the pipeline faces another
set of potential dangers. Debris from the topside can
fall down and impact the pipeline. Ship anchors and
fishing equipment dragging the seabed can snag onto
and drag the pipeline.27,28 Ocean currents can scour the
soil underneath the pipeline to cause free spanning,
where a segment of the pipeline becomes unsupported
except at the two ends of the free span length. Free
spanning can enable vortex induced vibrations (VIV)
where passing currents can vibrate the free spanning
length of the pipeline and can fatigue the affected pipe
segment.29–31 Corrosion and erosion can occur from
chemical attack and abrasion from the internal fluids,
which can often be sour (i.e. contains H2S) and contain
abrasive sand particles traveling at high velocities. All
of these factors necessitate the routine inspection of the
pipeline and/or the use of a permanent monitoring
technology. The challenge for subsea pipeline inspection once the pipeline is in place is the often extreme
water depths. Many excellent inspection technologies
cannot be delivered to the pipeline without costly and
dangerous (if divers are involved) equipment and procedures. If the pipeline is multilayered, the cost of stripping away layers of coatings underneath thousands of
meters of ocean water just for routine inspection is
impractical. Inline inspection may be used to inspect
the pipeline and the inner from the inside, but the benefit of the inspection needs to be balanced with the cost
of shutting down the pipeline to allow the inspection. It
is more desirable and cost effective where possible to
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use a less invasive screening inspection or monitoring
tool that provides a more global perspective of the
pipeline and suggest which area may require additional
attention.
The research and development of inspection and
monitoring technologies for subsea pipelines aims to
overcome the above-mentioned challenges. As the main
focus of failure prevention is the preservation of the
primary pipe body, many of the newest technologies
are first demonstrated on a simple pipe in controlled
laboratory environments. What may initially work on
an uncoated, thin pipeline may not work or be practical
for a multilayered, thick-walled pipeline deep at the
bottom of the ocean. As the technology matures, the
technology can be further engineered to tackle additional challenges. The economy offered by the technology, such as through reduced inspection time and
decreased deployed costs, will also be a major driver
for the path of development taken by the technology.
Therefore, the reader should keep in mind the practical
issues and challenges discussed in this section when
considering the use of both established and emerging
inspection and monitoring technologies.
Review organization
Section ‘‘Background’’ provided a broad background
that frames the discussion of subsea pipeline inspection
and monitoring. Section ‘‘Challenges in inspection and
monitoring of subsea pipelines’’ highlighted the
ongoing challenges in this industry especially in regard
to inspection and monitoring. The following sections
start with a brief overview (section ‘‘Possible failure
modes of subsea pipelines’’) of the possible failure
modes of subsea pipelines. The overview includes a discussion of the damage classifications set by government
agencies and summarizes some of the common pathways toward pipeline failure. This discussion is followed by a review of major inspection and monitoring
technologies. The review begins with sensors that rely
on electromagnetic phenomena. Thus, sections
‘‘Overview of sensing technologies’’ and ‘‘Electrical
phenomena’’ focus on magnetic flux leakage (MFL)
and eddy current sensing. Afterwards, the review
focuses on the wide family of inspection technologies
that rely on acoustics and vibrations. Sections
‘‘Ultrasound inspection’’ and ‘‘GWT’’ discuss ultrasonic inspection and guided wave testing (GWT), followed by acoustic emission (AE) and sonar in sections
‘‘Acoustic emission’’ and ‘‘Sonar mapping’’, respectively. In section ‘‘Radiography,’’ the review covers
radiography, which is another prominent type of
inspection technology. In sections ‘‘Inline inspection’’
and ‘‘Robotic vehicles,’’ the review shifts gears toward
inline inspection and underwater robotic vehicles,
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respectively. Section ‘‘Fiber optic sensors’’ moves on to
fiber optic sensors (FOS), which is a prominent method
in enabling long-term, long distance monitoring across
subsea pipelines. Section ‘‘Synergy of sensor technologies’’ provides a critical comparison and discussion of
synergy among the discussed inspection and monitoring technologies. Finally, Section ‘‘Conclusion’’ concludes the review with a brief discussion of observed
trends and the possible future in subsea pipeline inspection and monitoring.
Possible failure modes of subsea pipelines
Unlike onshore pipelines, subsea pipelines operate in a
severe physically and technically demanding submarine
environment and are susceptible to various hazards that
undermine their safe operation. These damage threats
cannot be taken lightly as they can lead to catastrophic
pipeline failure resulting in disastrous consequences,
both economic and environmental. Like the BSEE, the
US DOT provides a broad classification of the major
causes of failure in subsea oil and gas pipelines grouped
into five categories:15,32,243
1. Mechanical: This includes failure due to manufacturing or installation-related issues, for example,
material defects or construction faults (such as
inadequate welds and inappropriate sealing). Poor
installation can result in excessive free span lengths
that exceed the design guidelines. Sea waves and
currents can also lead to scouring which can accentuate the free span problem. Free span lengths
above allowable design limits can lead to fatigue
damage through VIV.29
2. Operational: This is mainly due to any malfunction
of instrumentation or mechanical systems such as
pressure relief valves. This could also be due to
operator neglect or mistakes.
3. Corrosion: This may be internal or external.
External corrosion is mainly due to exposure to the
submarine environment. Corrosion when combined with tensile stresses can lead to stress cracking, leakage, and failure in pipelines.
4. Natural hazards: Seabed quakes, wave currents, sea
storms, and so on can lead to failure.
5. Third party: This is especially important for pipelines in shallow water. Shipping vessels can damage
the exposed pipeline on the seabed while anchoring, trawling and so on. Also, heavy objects inadvertently dropped into the sea can cause damage to
pipelines.
Each of the damage modalities follow a unique
pathway that leads to the same end result of pipeline
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Figure 4. Possible damage modes of subsea pipelines.33
leakage. Davis and Brockhurst illustrates the potential
pathways from multiple different damage sources
(Figure 4). Ideally, sensor technologies (section
‘‘Sensing strategies for subsea pipeline SHM’’) are able
to detect damages before the pipeline status completes
a pathway and experiences leakage.
Sensing strategies for subsea pipeline
SHM
or used prior to pipe laying, methods must be developed in order to deliver such sensors to their targeted
structures. For subsea pipelines, sensors can be delivered by divers, or when personnel safety is a concern,
by remotely operated vehicles (ROVs) or autonomous
underwater vehicles (AUVs). Sensors can also be introduced into the pipeline for internal inspection via intelligent pigs and crawling robots. Thus, methods of
delivery will also be discussed following the discussion
on sensor technologies.
Overview of sensing technologies
A staggering amount of different technologies are available and are being developed for inspection and monitoring of subsea pipelines. Sensor technologies cover a
wide range of physical principles, including electrical,
optical, radiographic, chemical, and acoustic domains.
Each technology has their own strengths and weaknesses and often requires simultaneous deployment of
multiple technologies for a more comprehensive assessment of pipeline health. The following section will
attempt to cover some of the most commonly used sensor technologies while also including recent research
into sensor advancements. Unless the sensors are meant
to be permanently installed on the pipeline (e.g. FOS)
Electrical phenomena
MFL. Perhaps the most commonly used tool for pipeline inspection is MFL. Originally, MFL inspection
consisted of saturating a metallic surface (e.g. the pipe
wall) with a magnetic field and scattering ferromagnetic
powder over the pipe surface in order to visualize the
magnetic field.34 Defects within the surface disrupt the
smooth flow, or flux, of the magnetic field and cause an
aberration in the field outside of the pipe surface. The
aberration can be visualized by observing the pattern of
the scattered powder, or with more current technology
can be measured by a sensor (e.g. Hall Effect sensors).
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This aberration is referred to as the leakage, hence the
name magnetic flux leakage. The process of the magnetic field leaking out of the pipe surface may seem like
a simple process, but in-depth studies have been carried
out that show the complexity of the physics involved in
the leakage.35 As will be discussed, the properties of the
leaked magnetic field can provide information about
the cause of leakage. By scanning the surface systematically, defects in a pipeline can be detected and mapped
out.
Depending on the application, three different methods for magnetizing the pipe wall are available. In alternating current (AC) magnetization, an AC in an
external circuit is used to generate an oscillating magnetic field across the pipe surface. Due to its oscillating
nature, eddy currents, which produce an opposing magnetic field, will be generated (i.e. the ‘‘skin effect’’). The
skin effect limits the magnetic field to a smaller area
and also prevents the field from penetrating deeper into
the pipe wall. However, devices based on AC current
are readily available, low cost, and easy to control. Due
to low surface penetration, AC magnetization is mainly
used for surface and near-surface inspection. In direct
current (DC) magnetization, a unidirectional magnetic
field is generated and can penetrate more than 10 mm
into a pipe surface. As the residual magnetic field may
interfere with other electronic components (e.g. using
other electronic sensors in the future) or with any welding process (e.g. before the pipe segment is welded to
the pipeline during the pipe-laying process), demagnetization of the pipe wall may be needed after using DC
magnetization.34 Demagnetization may be accomplished by wrapping a solenoid around a section of the
pipe (typically near the section where welding will
occur) and applying an AC current. The AC current in
the solenoid randomizes the magnetic field of the pipe
and thus effectively demagnetizes the pipe. Rectifying
circuits can be used to modify AC magnetic fields so
that the field will only travel in one direction.
Furthermore, by inverting the negative portion of the
AC magnetic field, an AC field may be able to function
similar to a DC generated magnetic field while keeping
the low-cost benefits of using AC power. Finally, permanent magnets are the most commonly used method
for pipe wall magnetization. The penetration of magnetic fields generated by permanent magnets is similar
to those of DC magnetic fields. The high energy density
of rare earth magnets allows for small-sized magnets,
and coupled with the fact that no power is needed,
make permanent magnets popular for MFL.34
While the presence of MFL indicates an anomaly,
such as a defect, in the pipe wall, in-depth analysis of
the MFL signal is needed in order to extract additional
information about the anomaly. Modeling of MFL
through both analytical and numerical simulations has
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been done to retrieve the defect geometry based on
measured magnetic field signals. Since the 1960s the
magnetic dipole model has been the foundation analytical model that helped predict the size of defects using
MFL.36 In the dipole model, the magnetic field induced
within the pipe wall is aligned in parallel with the external magnetic field. However, as the field lines approach
the defect, they form unpaired poles at the face perpendicular to the field lines. The field then escapes from
the face at the unpaired poles and are the basis of the
magnetic flux that can be detected by sensors. For a
long time, MFL devices measured amplitude of magnetic flux as an indicator for the depth or severity of
the crack. However, the dipole model does not always
predict the correct amplitude for a certain defect size.
Thus, over the years, modifications to the model have
been researched to allow finer and finer predictions of
increasingly complex defect geometry.37–44 New
advances in modeling have suggested the use of weaker
magnetic fields or magnetic shields in order to reduce
background noise and provide more clarity.34 Use of
weaker magnetic fields has also been reported to allow
the use of MFL, under the right conditions to detect
defects both inside and outside of the pipe.45 The later
models have also take into consideration the other
components of the magnetic flux (i.e. axial, radial, and
tangential components (Figure 5)) in order to more
fully characterize a defect. Correspondingly, recent
MFL devices include three mutually perpendicular sensors to measure the different components.
As computational capacities increased in the 1970s,
finite element–based models of MFL were established.46 Through finite element, the effects of highly
complex defect geometries on MFL can be studied.
Recent research in finite element–based MFL modeling
has looked into the effects of defect placement (e.g.
inside or outside the pipewall), magnetization methods,
pipe material, pipe pressure, movement of MFL device,
and so on.34,47,48 As finite element methods become
more advanced, additional parameters related to MFL
detection will be added to get an increasingly clear picture of defects in pipelines. Conclusions drawn from
the above models can be applied to measured data to
visualize the defect shape.
In order to detect MFL and obtain data, the sensor
must be sensitive to changes in a magnetic field. A wide
variety of sensors are available for MFL measurement,
including induction coils and magnetic flux gates.34 The
most mature and commonly used sensor technology for
measuring MFL is the Hall Effect sensor. The Hall
Effect sensor measures the electrical potential caused
by the magnetic field–induced separation of positive
and negative charges in a current carrying metal. Thus,
when a magnetic field passes through a Hall Effect sensor, the sensor produces a voltage signal in proportion
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Figure 5. The different components of MFL.34 (a) Defeat leakage field, (b) axial component, (c) radial component, and (d) tangential
component.
Figure 6. (Left) Cross section of an MFL assembly in a pig. (Right) Photo of MFL section in a pig.49
to the strength of the magnetic field. Figure 6 shows the
application of Hall Effect sensors on a pipeline inspection gauge (Pig), which is an instrument that will be discussed in section ‘‘Radiography.’’ Brushes mounted
near the magnetic poles transfer magnetic flux into a
section of the pipewall, and an array of Hall Effect sensors will capture the flux leakage.
Despite the advantages that make MFL a popular
tool for subsea pipeline inspection, there remain some
drawbacks that are still subjects of research. For pipeline inspection, the MFL measurements are influenced
by the dimensions of the MFL tool, including distance
between magnet poles, speed of the pig, and quality of
the brushes. As an emphasis on the effect of speed on
MFL measurements, Figure 7 shows a recent study
that attempts to optimize the capture of defect-induced
MFL as the tool moves at different speeds relative to
the pipe wall.50
External factors such as residual magnetism in the
pipe wall, the pipe material, and the pipe pressure also
affect the MFL readings. The strength of the applied
magnetic field should also be adjusted based on the
pipe wall, with thick walls requiring stronger fields in
order to reach full saturation.34,51 Reading MFL signals still requires skill and experience. For example, the
difference between a weld and a defect in an MFL may
require human experience to resolve, although research
in artificial intelligence (AI) is starting to be applied
toward defect recognition through MFL data.52,53 Liftoff (i.e. distance of MFL tool to surface) can also be
affected by debris, further complicating interpretation
of measurements.54 The orientation of the defect along
the pipe will also affect the sensitivity of the MFL tool
in detecting the defect. If the magnetic field direction is
parallel to the defect shape, the magnetic field may not
be deflected adequately enough for the tool to detect
the anomaly55 (Figure 8). The research direction in
MFL aims to either compensate for the above drawbacks either through advanced modeling or through
modifications to the MFL tool components.
Electrical/field signature mapping/potential drop mapping. The
fundamental operational principle of electrical field
mapping (EFM) techniques is to pass a current between
two electrodes in contact with the pipe wall and measure
the voltage drop between the two electrodes. Through
Ohm’s law, the voltage drop associated with a current is
correlated to the resistance of the medium between the
two electrodes. The resistance is based on multiple physical parameters, including the cross-sectional area of the
tested volume in the pipeline surface. Defects such as
cracking and corrosion alter the area and thus the measured resistance of the tested volume.56 Thus, a change
in the potential drop across two electrodes may indicate
a change in the wall thickness that is likely due to
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Structural Health Monitoring 19(2)
Figure 7. Distribution of magnetic flux lines at two different speeds for the same defect.50
Figure 8. Orientation of the magnetic field is important depending on the shape and orientation of the defect. Application of
magnetic flux in multiple directions may be necessary to catch all defects.
damage. For most applications, this technique involves
the permanent installation of a matrix of electrodes at
key locations in pipeline networks to test for corrosion,
cracking, and erosion. Since devices used to perform
EFM are stationary and permanently welded, they are
often used to monitor areas of the pipeline, such as
joints and welds, which are more prone or vulnerable to
damage. Figure 9 shows the different embodiments of
EFM for both onshore and offshore pipelines.
The performance of the electrode matrix is dependent on distance between electrodes, the thickness of
the pipeline wall (or any other test structure), as well as
the conductivity and permeability of the pipeline wall.
In order to optimize the usage of the electrode matrix
for mapping the pipeline wall for defects, finite element
simulations are often run in order to determine the best
configuration of electrodes within the matrix.59
Penetration of the current into the thickness of the
pipewall is dependent on the current frequency.
Oftentimes, DC or low-frequency current of several Hz
can be used to monitor the entire wall thickness.57 On
the other hand, changes in temperature and current levels used may disturb measurements and require a reference plate as a compensation mechanism.60 While
EFM requires permanent installation onto the pipeline,
EFM possesses several advantages, including the ability
to detect, classify, and locate corrosion or erosion
inside and outside the pipe wall, potential for continuous online measurements, and having a large range for
operational temperatures. The direct contact with the
pipe furthermore increases the accuracy and reliability
of readings from EFM.61,62 On the other hand, some
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Figure 9. (a) Example of EFM/FSM results showing the size and depth of pitting corrosion,57 (b) exposed EFM/FSM matrix on a
pipeline,58 and (c) illustration of EFM/FSM principle on the inspection of a pipe wall.
obstacles to this technology include erroneous readings
caused by the presence of conductive deposits and the
potentially high energy (thus danger) needed for the
technology to function.63
Research and development in EFM has centered on
increasing the accuracy of the method. EFM is highly
versatile and able to monitor the progress of general
and local corrosion as well as erosion and cracks in
pipelines under a wide variety of environments.60
Modifications to the technique helped to estimate certain aspects of damage, such as the length of cracks.64
However, such estimations were based on empirical
formulas, which lead to large potential errors.
Furthermore, later simulations of EFM have shown
that the damage geometry may cause unpredictable
effects on the flow of current in the sensing matrix.
Thus, a larger drop in electrical potential does not
necessarily correlate to the size of damage since the
path of current may simply be altered. Some efforts,
such as electrode placement optimization57,65 and current distribution calculations,66 have been reported to
combat such drawbacks. Recent work in this field has
proposed both the use of a large database to match
current distribution patterns to certain types of damage67 and improvements to the mathematical modeling
of damage-induced current redistribution.68 The latest
model of electrical current redistribution, which subdivides the electrode network into smaller portions,
shows a major improvement in determining pitting corrosion depth (1.8% wall thickness error using the new
method vs 33.9% wall thickness using traditional methods). Future work in this area involves identifying
damage that has more complex geometry.58
Eddy current inspection. Eddy currents are circular patterned electrical currents that form in a conductor due
to changes of a magnetic field passing orthogonally to
the conductor. A varying magnetic field can be created
by passing an AC into a coil. As the varying magnetic
field penetrates the target inspection surface, induction
occurs and eddy currents are generated in the surface
material. The eddy currents in the material, due to their
circular path, form their own magnetic field that
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Structural Health Monitoring 19(2)
Figure 10. (Left) Eddy currents are generated in the pipeline wall due to magnetic field produced by coil. Eddy currents create a
counteracting magnetic field. (Right) Distortion in eddy current due to wall defect alters/reduces counteracting magnetic field, thus
measurably changing impedance in coil. Note: large arrows show strength of the magnetic fields.
opposes the original magnetic field. Defects in the
material, such as cracking or corrosion in the pipeline,
cause disruptions in the eddy current (Figure 10).
Eddy currents are another common tool in the
arsenal of non-destructive testing (NDT) and are useful
for crack detection and material thickness measurements. An early example of eddy current usage for
inspection was reported by Fearon69 in 1959 for the
detection of casing joints in oil wellbore holes. The
abrupt change of steel composition between the casing
and the casing joint causes a corresponding change in
the amount of eddy current produced.
A drawback of the eddy current is that the depth of
penetration is dependent on the frequency of the AC
current in the coil. The lower the frequency, the deeper
the penetration. Thus with operations normally at
higher frequencies, the eddy current method is limited
to skin-level defects. While low-frequency excitation
can provide additional depth, the energy required to
maintain the excitation may be prohibitive. In order to
reach greater depths without expending too much
energy, the pulsed eddy current (PEC) method can be
used instead. In PEC, the coil is electrified using a current following a pulse or step function, thus effectively
exciting multiple frequencies simultaneously. As the
pulse involves a much lower amount of energy compared to the traditional eddy current, higher voltages
can be applied to the coil. PEC allows the interrogation
of multiple depth layers at the same time.70,71
With the introduction of strong permanent magnets,
eddy currents can be generated instead by relative
motion between a constant magnetic field (e.g. from a
permanent magnet) and the pipeline surface, in a
process generally called movement-induced eddy current testing (MECT).72,73 Furthermore, the use of
stronger magnetic sources has also allowed generation
of stronger currents and thus increased the potential for
use in internal pipeline inspection. As reported by
Nestleroth and Davis,74 a magnet can be mounted onto
a rotor and rotated to generate eddy currents (Figure
11). A potential future direction of eddy current testing
in both onshore and offshore pipelines is the use of
Lorentz force eddy current testing, which is a relatively
new subset of MECT. Lorentz forces are a type of force
that pushes against a conductor as the conductor moves
relative to a magnetic field. In the case of pipeline
inspection, a force is generated against the conductive
metal of the pipe wall, but at the same time according
to Newton’s third law, an equal and opposite force is
generated against the magnet. By measuring the push
back force on the magnet, defects can be detected in a
pipeline. The advantage of Lorentz force eddy current
testing is the potential for detection of defects that are
deeper than traditional eddy current testing is capable
of detecting.75,76
A recent alternative method introduces a magnetic
field (in a similar manner as MFL) that can increase the
effective measurement depth of eddy current inspection.
Magnetization of the ferromagnetic pipeline material
decreases the permeability of the pipe wall and thus
increases the penetration depth of the eddy current.
Magnetic eddy current (MEC) inspection uses such a
principle to increase the effectiveness of eddy current
inspection. While the appearance of MEC may bear
similarity with MFL, less power is needed for the magnetic field (about 10 kA/m for MFL vs 3 kA/m for
Ho et al.
617
Figure 11. (Left) In-pipe inspection tool using eddy current. The rotation of the magnets generate eddy currents in the pipe that
can be measured. (Right) Damage or change of the pipeline wall material will be reflected in the properties of the eddy current
compared to other areas of the pipe.74
MEC). The synergy with the eddy current system means
that greater distances can be inspected for a lower
energy cost.77,78
Acoustics
Ultrasound inspection. In the context of subsea pipeline
inspection, ultrasound refers to the use of elastic waves
to detect and quantify damage. In order to detect small
cracks (e.g. on the order of millimeters), the frequency
to the ultrasound waves must be designed so that the
wavelength has similar dimensions of the crack size.
Since wavelength is inversely proportional to frequency, the range of ultrasound frequencies for NDT
in solids may range between 0.5 and 25 MHz. The propagation mode of ultrasound in solids is characterized
by longitudinal waves (i.e. compression waves, pressure
waves), in which the energy of the wave travels in the
same direction as the wave propagation, and shear
waves (i.e. transverse waves), in which the energy travels perpendicular to the direction of wave propagation. For steel pipelines, the speed of the ultrasonic
longitudinal waves may reach around 5900 m/s and
shear waves around 3250 m/s, depending on the environmental conditions (i.e. temperature, pressure, stress)
and the specific alloy used. Ultrasound waves may convert between longitudinal and shear modes when
impinging upon an interface (e.g. boundary between
pipe surface and surrounding water), but for short distances such as across the pipe wall, consideration of
only one mode (typically longitudinal) is adequate. As
seen in section ‘‘Electrical/field signature mapping/
potential drop mapping,’’ these two modes can interact
to generate a complex family of wave modes that are of
interest when a long distance is considered.
Typically, ultrasound is generated through the
use of piezoelectric materials. Piezoelectric materials
produce an electrical charge when strained and conversely will deform when a voltage is applied. Thus, if an
AC is applied to the piezoelectric material, the material
will contract and expand at the same frequency as the
current. With high enough frequency, the vibratory
motions of the material can generate acoustic (e.g.
ultrasound) waves. On the other hand, the piezoelectric
material can generate an AC upon cyclic strains (e.g.
from vibrations). Therefore, piezoelectric materials can
act as a generator and receiver of vibration signals,
including for ultrasound. In terms of pipeline inspection applications, ultrasonic-based NDT is involved at
all stages of the pipeline lifetime. Inspection comes into
play initially at the manufacturing stage in order to
identify potential sources of problems prior to deployment in field. While defects in the steel used to fabricate
the pipes are rare, the fabrication materials are still
checked using ultrasound before they are rolled and
welded. More commonly, defects are found in the welding work and are found using systematic inspection
through ultrasonic sensor arrays.79
Non-destructive ultrasound operates on the basis of
transmitting an ultrasonic wave inside the material and
listening for the echoes that are generated when the
wave impinges upon physical boundaries, such as the
interface between two different materials, or a crack in
a homogeneous medium. As shown in Figure 12, for a
healthy pipe wall, an ultrasound pulse can be generated
and an echo should be received within a certain time,
depending on a set of known conditions (e.g. pipe wall
material and thickness, temperature, and wave properties). For example, research and engineering efforts
have recently aimed to achieve online monitoring of
pipeline wall thickness, and thus corrosion and erosion
using ultrasound transducers that can be permanently
installed. With an array of ultrasonic transducers, a
map of a section of pipeline wall can be monitored.80,81
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Structural Health Monitoring 19(2)
Figure 12. (Left) Ultrasound transmission and reflection under different circumstances. A: Healthy pipe wall with far wall echo
detected at Dt1. B: Crack causes an early reflection followed by the expected far wall echo. C: Wall thinning due to corrosion/
erosion causes a premature reflection of the far wall, resulting in Dt2. (Right) Typical schematic of an ultrasound transducer.
Requirements for differently shaped ultrasonic waves can be produced by adding different or additional piezoelectric elements.
Figure 13. Schematic illustrating the use of time-delayed excitation of ultrasonic elements in an array to steer an ultrasonic
wavefront toward different directions.
Due to accessibility, however, offshore risers are more
feasible for such permanent installation compared to
pipelines that are placed in deepwaters.
Ultrasonic sensors are typically used in several configurations. As a single crystal, the sensor can be used
to emit an unfocused, divergent beam of ultrasound
along a straight trajectory. With multiple crystals, the
sensors can form a sensing array that can reconstruct a
cross-sectional image of the monitored structure.
Furthermore, by adjusting the time delay (i.e. phase) of
when each crystal emits the ultrasound wave, the overall wavefront can be steered (Figure 13) in order to
cover a larger area and detect a wider range of defect
orientations.79
Another widely used technique for ultrasound-based
sensing is time of flight diffraction (TOFD). In TOFD,
two ultrasound arrays are used separately as a transmitter and receiver. Instead of measuring only the
reflection of the ultrasound waves, the TOFD technique also measures the effects of wave diffraction due
to the edges/tips of defects in the pipe material (Figure
14). A wide angle beam is projected by the transmitter
across the width of the pipe wall, and the receiver
receives four major signals. The expected signals come
from lateral waves, which travel along the surface, and
from the reflection of the wave from the opposing surface of the pipe wall. If a defect is present between the
transmitter and receiver, then additional waves will
arrive between the lateral and backwall reflection arrival times.79 TOFD-based inspection devices for pipelines have been made available to inspect welding
(Figure 15, left) as well as subsea pipeline inspection
(Figure 15, right).
GWT. While the ultrasonic inspection techniques
described in section ‘‘Ultrasound inspection’’ offers
excellent resolution in spot checking pipelines for
defects, the use of these techniques for inspecting an
entire pipeline will be excessively time consuming and
will not be cost effective. In cases where removal of
Ho et al.
619
Figure 14. Diagram of TOFD operational principles.
Figure 15. Photo of ROV applying TOFD onto subsea pipeline,
courtesy of Sonomatic.82
pipeline coating is required for inspection, point by
point ultrasonic inspection becomes an even more formidable problem. On the other hand, GWT or sometimes called guided ultrasonic wave testing (GUWT) or
long range ultrasound testing (LRUT) can provide a
much longer range (up to 100 m) inspection albeit at a
lower resolution.83 Access to only a few points along
the pipeline is required without the need to remove
coatings for most of the pipeline. The trade off in range
and resolution is mainly due to the use of lower frequency waves (10–100 kHz) for GWT compared to the
MHz range of ultrasonic inspection. Lower frequency
(thus longer wavelength) waves can travel further than
high-frequency waves, but are unable to effectively
interact with small defects. Furthermore, the direction
of the waves in GWT is also perpendicular to those
used in ultrasonic inspection and will thus travel along
the length of the pipeline. Defects such as pipe wall
thinning (e.g. due to corrosion), weld imperfections,
cracks, and notches cause anomalous reflections with
an amplitude that is proportional to the change in the
cross-sectional area of the pipe at the defect. The presence of such anomalies can be followed up with a more
precise ultrasonic inspection. Therefore, GWT is often
used for initial screening of a pipeline to broadly check
for potential abnormalities, which are followed up by
traditional ultrasonic inspection.
Guided waves are elastic waves that travel within a
finite body. Elastic waves can be a combination of the
fundamental longitudinal and shear waves, which can
combine to form more complex types of waves (e.g.
Rayleigh waves, Lamb waves, and Love waves).84 The
propagation of the waves is guided by the geometry
and boundary conditions of the body, hence the name
‘‘guided wave.’’ Depending on the frequency characteristics of the wave, different resonant modes in the wave
guide can be excited. Pipelines, which can be considered
as hollow cylindrical waveguides,85 are dominated by
longitudinal, torsional, and flexural wave modes. There
are an infinite number of modes as characterized by the
mode order and number. In particular, a popular convention86 to distinguishing among longitudinal, torsional, and flexural modes is to label the modes as L(n,
m), T(n, m), and F(n, m), respectively. In the convention, n refers to the harmonic order of the mode (affects
the symmetry of the mode around the axial axis of the
pipe), and m is an index for identifying particular
modes for a given type of mode. It should be noted that
modes at n = 0 are axisymmetric. As seen in the example dispersion plot (Figure 16), one frequency can lead
to the excitation of multiple modes. Furthermore, propagating waves can experience dispersion, wherein the
velocity at which a mode will travel will vary with the
frequency of the wave. For simplicity in signal processing, it is desirable to excite only one mode; however, as
the probing guided wave signal is typically in the form
of a pulse, multiple excitation frequencies (i.e. ‘‘group’’
of frequencies) are inevitably involved. The signals
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Structural Health Monitoring 19(2)
Figure 16. (Left) Example of a dispersion plot for a steel pipe. The curves will be dependent on pipeline properties.87 (Middle)
Two-dimensional representation of modes L(0, 1), L(0, 2), L(0, 3), T(0, 1), and T(0, 2). (Right) Propagation of L(0, 1) and L(0, 2) along
a pipe structure.88
from the desired mode may be drowned out by the
coherent noise, which are signals from undesired modes
excited by the pulse. In addition, if the probing pulse
experiences too much dispersion, the shape of the pulse
may be distorted over the course of propagation so that
the signal to coherent noise ratio may be too low for
measurement.
Figure 16 illustrates the two-dimensional (2D) projection of several propagation modes present in pipe
geometries and an illustration of the propagation of a
guided wave along a pipe. As can be seen in dispersion
plot, L(0, 2) and T(0, 1) experiences the least dispersion
across the frequency spectrum of interest. L(0, 2) is relatively stable after a cut-off frequency (about 40 kHz
in the example), while T(0, 1) does not experience any
dispersion. For pipe systems, the T(0, 1) mode is generally preferred due to a combination of the simplicity
and lightness of the transducer system and the lack of
dispersion of the mode at all frequencies. Furthermore,
when the pipe is filled with liquid, the T(0, 1) mode
does not experience any interference. In contrast, the
L(0, 2) mode may suffer from reverberations when
liquid is present. However, there are some cases in
which L(0, 2) is preferable, such as for the detection of
circumferential cracks.87,89,90 Other modes have been
investigated for use in inspection.91–95 For example,
recent work has demonstrated the enhanced detection
circular and crack-like defects by analyzing the scatter
of higher order torsional and flexural modes.96
Guided waves for pipeline inspection are generated
in a manner similar to the ones used for ultrasonic
inspection. In one way, an array of angled piezoelectric
transducers similar to the one shown in Figure 14 is
wrapped around the circumference of the pipeline.97
Another way is to use electromagnetic acoustic transducers (EMAT), which can excite guided waves
through either the Lorentz or magnetostrictive principles.83,98 EMATs do not require much surface
preparation as they are non-contact and are not
affected by non-metallic debris on the surface. On the
other hand, EMATs can be affected by any residual
magnetic field in the pipeline (e.g. left over from MFL
inspections) and require more power than piezo-based
transducers. The unintended attraction of loose ferromagnetic particles may be a concern.99 One of the key
advantages of piezo-based transducers is capability to
generate stronger signals relative to EMATs, thus
enabling a more favorable signal to noise ratio. An
example of a transducer array for subsea pipeline GWT
is shown in Figure 18. The orientation, angle (for piezoelectric transducers), and excitation of the transducers
can be adjusted to target the desired modes. An added
benefit of using an array of equally distributed transducers, or the use of multiple rings of transducers is the
ability to suppress certain undesired modes through
destructive interference. Multiple rings are further used
to achieve directionality; to discern from which direction the waves are being received. Different sizes of
transducers can also be used for the purposes of mode
selection. Further details on practical implementations
and their effects on mode selection are available in
Cawley et al.83
Mentioned briefly at the beginning of this section,
GWT works by using a transducer array to transmit a
guided wave through the length of the pipeline. In the
pulse-echo approach, when the wave impinges upon a
defect, a portion of the wave is reflected back toward
the transducer, and the reflection is analyzed for defects
(Figure 17). In the pitch-catch approach, two transducer arrays are used. One array generates the guided
wave, while the second array located a distance away
receives the transmission.101 In cases where only one
point of the pipeline is available, the pulse echo
approach should be used. However, the pitch-catch
approach, which can offer a different perspective on
the pipe defects, may allow the detection of additional
Ho et al.
621
Figure 17. (Left) Example of a diver deployed subsea transducer ring for guided wave testing, courtesy of Guided Ultrasonics
Ltd.100 (Right) Pulse-echo approach for guided wave testing in a pipeline. Defects and certain pipe features (e.g. welds) show up as
reflections. The hard discontinuity from flanges cause a total reflection of waves and thus are limiters to the range of guided wave
testing.
defects not seen in the pulse-echo approach. Thus for
the pulse-echo approach, the transducer design must be
able to perform the task of transmission and reception
in the same array. On the other hand, the increased
costs and complexity associated with the pitch-catch
approach makes the pulse-echo approach a more predominantly used method. Another driver for transducer design is the inspection range. An obstacle to
improving the practical range of GWT is wave attenuation due to leakage (i.e. ultrasonic leakage) of energy
into the boundaries. Viscous coatings such as bitumen
will dampen the wave energy and limit the range of
GWT. In severe cases, the inspection range has been
reported to be reduced to 2 m.102 Subsea pipelines are
often protected by multiple layers of coating, concrete,
or even another pipe (pipe-in-pipe). A future direction
for subsea pipeline GWT is to improve signal transduction and interpretation for cases in which the material
filling the annulus in a pipe-in-pipe situation may make
sensing difficult. Ongoing research in understanding
guided wave physics,103–108 including for practical
applications in wellbore strings109 hold promise in
improving GWT performance in coated pipelines.
Much of the ongoing research aims to find the appropriate modes that can minimize the attenuation/leakage
of guided wave energy and thus improve testing performance. Key information such as damaged or debonded
coatings can be extracted by further analyzing the complex wave physics involved in multi-layer, concentric
pipe structures.110–115 The geometry of the pipe can
also limit the range of GWT. Sharp bends in the pipeline can severely distort signals; the selected mode can
be converted to other propagation modes due to the
change in geometry. On the other hand, the presence of
converted modes may also be used as an indicator for
undesired bending in the pipeline.116,117 Flanges will
completely reflect the waves, thus necessitating separate
tests between flanged pipeline segments. Welds and
clamps also cause reflections that attenuate the energy
of guided waves and thus limit the inspection range.
One way to improve the range is through focusing of
guided waves toward a particular location. Focusing
can be accomplished through phased array focusing,
which involves precisely timing the excitation of transducers so that the individual guided waves constructively interfere at a targeted location. With the
increased energy, the range of the transducer array and
the inspection sensitivity at the focused location can be
increased.118,119 In addition to the hardware-based
challenges of GWT, the presence of dispersion, scattering, and multiple modes can make data interpretation a
difficult task. There is ongoing research in classification120 and visualization/tomography121–123 of defects
based on GWT data. Figure 18 shows an example of
GWT-based tomography to visualize defects in a pipe
bend.123 For long-term monitoring, where the transducer array is permanently installed onto the pipeline, the
use of a baseline (i.e. benchmark) is beneficial for
detecting changes in the pipeline over time. The baseline signal can be effectively subtracted from the current signal to quantify changes. In this regard, indexbased techniques have been developed to further provide insight into the pipeline status.124
Aside from being directly used for inspection and
monitoring tasks, an emerging function of guided ultrasonic waves is communication. Guided waves can be
modulated using schemes such as pulse position modulation (PPM) to encode information.125,126 Thus, a
transducer can transmit a modulated guided wave
through the pipeline to be received by another transducer further along the pipeline. Through a series of transmissions, information could theoretically be carried
from a subsea station (e.g. a Christmas tree) to the topside through the pipeline. Changes to the baseline of
the transmission signal could also serve as a warning
sign for damage in the pipeline. Such a communication
method can allow a network of sensors to be permanently installed along a pipeline as long as there is
power and a way to send and receive guided waves.
The use of guided wave communication may also
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Structural Health Monitoring 19(2)
Figure 18. (Left) Lab experiment using guided wave testing to detect a defect in a pipe bend, which is traditionally difficult for
guided wave testing. (Right) Use of experimentally obtained signals to visualize the defect in the pipe bend.123
Figure 19. (a) Jumper pipepline about to be submerged in water at the Neutral Buoyancy Lab; (b) pipeline submerged in 40 ft of
water; (c) impact events generated by divers; (d) overall set up of the experiment, with a topside motor causing pipeline vibrations;
(e) close up of underwater pipeline with marked impact points.136
provide a solution to the constant compromise between
range and bandwidth among existing underwater communication technologies (i.e. optical, acoustic, radio
frequency, magnetic induction).127 Recent work in
guided wave communications in different media is promising,128–130 and practical application to subsea pipelines is foreseeable in the near future.
Passive sensing of ultrasonic guided waves due to
external sources can also be used to detect and localize
impacts and leakages in subsea pipelines. Impacts due
to topside debris have become a major source of subsea
pipeline failure, and detection of impacts has increasingly gained importance in the industry.131 Dynamic
events such as the impact of an object on a structure
(e.g. pipeline) can generate intense stress waves in the
form of ultrasonic-guided waves that propagate along
the surface (i.e. Lamb waves) throughout the structure.
If the time needed for the wave to travel to a sensor
and the locations of sensors are known, then the impact
location can be estimated. However, there are quite a
few practical issues to be solved despite the simple concept. While studies have been done to characterize
these waves132 and also to utilize the measured properties of the waves to estimate the impact location, there
were still signal processing challenges in accurately
determining the exact time at which the waves reached
sensors.133–135 Recently, Zhu et al.136–138 developed an
algorithm capable of overcoming most of the signal
processing obstacles and when used in a full scale
experiment, it was able to locate impacts on a 12-m
underwater pipeline to within 0.2 m error (Figure 19).
It should be noted that in the above, AE (section
Ho et al.
Figure 20. Hydrophone arrays mounted in various places can
be used to detect pipe and sea floor seepage based on the
acoustic emissions produced by bubbles.147
‘‘AE’’) can occur due to impact-induced micro-damages
to the structure. However, in the above literature, the
signal used to isolate the impact point are the guided
stress waves generated by the impact, which are generally much stronger than AE signals, especially when
the structural material is minimally damaged by the
impact event. A future direction in this line of work is
to marinize the piezoelectric transducer for deepwater
usage and to improve the detection algorithm, such as
with machine learning. A related branch of research
and development is the active use of guided waves in a
local area to detect defects. A specially designed guided
wave generated by a piezoelectric transducer mounted
onto the pipeline structure is modulated by the pipeline
material and components, and anomalies can be
detected if they are present. Compared to the long
range GWT, currently reported techniques are locally
effective and are more focused on specific geometries.
Applications include the detection of bolt loosening in
the pipeline flange,139,140 loose threaded connections,141
and corrosion pits.142 With further development, these
techniques may foreseeably be used by subsea robotics
for automated inspection.
AE. AE waves are transient elastic waves created by
release of localized stress energy within a structure due
to several mechanical events, such as material failure,
friction, cavitation, and impact. By listening to these
AE wave patterns with an array of dispersed sensors
and by characterizing the wave pattern, the occurrence
and severity of these events can be identified.
Subsea pipelines in particular experience stresses
from a wide variety of sources. Among the largest
sources of stresses is the pipe-laying process. Pipes will
experience high tension, low pressure near the surface,
and low tension, high pressure on the sea floor. As suggested by Shehadeh et al.,139 monitoring the AE, and
623
thus the pipe stress, can be a method for real-time monitoring of the laying operation. Their laboratory stage
demonstration showed the division of three stages of
buckling of a pipeline segment. AE signal parameters
such as amplitude and AE hit counts demarcated the
different buckling stages, with the highest activity associated with the buckling stage, followed by the quieter
collapse stage.244
For subsea pipeline, a leakage event causes friction
between the escaping gases and the perforated pipe
wall, producing acoustic waves that propagate from the
leakage point. Using passive acoustic sensors, the AE
can be measured, indicating a potential leak. The acoustic characteristics are correlated with leakage flow rate,
distance from leakage, and so on and can be used to
localize the leakage point, such as through analyzing
sound pressure intensity as well as using the time at
which the negative pressure wave (NPW) arrives at a
set of AE sensors along the pipeline.143–146 While such
leakage detection research has not yet been deployed in
subsea conditions, it is foreseeable that additional marinization redesigning of sensor and instrumentation
components will be able to bridge the gap from lab testing to field implementation.
Hydrophone arrays can also pick up AEs resulting
from the release of bubbles from pipeline leakages147,148
(Figure 20). Furthermore, with enhanced sensitivity
and coupling to the pipeline, sound waves emitted by
anomalous events, such as leakage in the subsea pipeline controls (e.g. valves and flanges), or severe obstruction of the pipe lumen can be detected within several
kilometers.149
It has been also shown that passive AE listening
through hydrophone arrays can be complemented with
active methods. For example, the active listening, in
which an AE pulse is transmitted toward a target and a
sensor listens for a response, has been used to detect
and localize leakages. In an experiment by Wendelboe
et al.,150 a leak was detected and localized using a combination of passive and active sonar (PS and AS).
Through an array of AE sensors that forms a certain
sensing aperture (field of view), the bearing, or direction, of a potential leak (represented as an acoustic
source), could be determined. After determining the
bearing of the potential leak, the AE array can act as a
sonar that generates acoustic waves and listens for back
scatter, During this active sensing portion, the time
between sending an acoustic wave and reception of
backscatter can be used to estimate the distance
between the sonar and the leak (Figure 21). Thus
through PS and AS, the location of a potential leak can
be determined. This method can be applied to detect
leaks from both reservoirs and artificial subsea structures. However, additional work needs to be done to
accurately filter out irrelevant environmental noise.150
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Structural Health Monitoring 19(2)
Figure 21. (Left) Experimental setup with a sonar array facing a leak. (Center) Sonar data indicating the presence of a leak. The
vertical red line suggest that the leak is toward the direction faced by beam number 150. (Right) Data showing the estimated
location of the leak relative to the position of the sonar.
Source: Reproduced from Wendelboe et al.150 with permission of AIP Publishing.
PS: passive sensing; PSNL: passive sensing when there is no leak; NAS: normalized active sensing.150
AS is also used for mapping of the seafloor and the
evolution of pipe buckling and will be described in
detail in the following section.
Sonar mapping. Sonar refers broadly to the use of sound
waves underwater to detect objects, typically for navigation and mapping. A variety of marine mammals,
such as whales, use sonar to detect prey and to communicate. Sonar can be generally divided into passive and
active types. During PS, a device (i.e. hydrophone) listens for sounds generated in the subsea environment,
such as from submarine vessels or marine animals. In
AS, a transducer generates an acoustic pulse, or a
‘‘ping,’’ and listens for the echo of the pulse due to
reflection from objects in the subsea environment. The
time it takes for the pulse to return provides an estimate of the distance between the transducer and the
targets (e.g. sea floor). The amplitude of the reflection
(i.e. backscatter) is also influenced by the material
properties of the target. Typically cohesive stiff material such as steel in pipelines produces high backscatter
(‘‘bright’’) compared to sand, which has grainy texture
and thus low backscatter (‘‘dark’’).151
In regards to subsea pipeline inspection, AS techniques are used. AS techniques that have been used for
offshore pipeline inspection include multibeam bathymetry and side scan sonar (SSS). Both techniques can
be used to scan the sea floor and obtain information
about the location and shape of pipelines. In multibeam bathymetry, multiple sonars mounted on a ship
hull are used simultaneously to ping a collectively wide
swath of the sea floor. Through analyzing the return
time of the sonar pulse, the depth of the sea floor and
the positions of anomalies, such as pipelines, can be
estimated. However, the backscatter is not considered
in this technique and thus cannot provide information
about the composition of the seafloor. The use of multiple sonars overcomes the disadvantages of using one
sonar and one ping at a time to map the seafloor. On
the other hand, depending on the size of the sonar
array, computational costs can become increasingly significant. Thus the use of multibeam bathymetry, while
costing more than the use of a single sonar, may save
on the costs of operating a ship for a longer period of
time.151 Similar to the AS mentioned in the previous
section, multibeam bathymetry has recently been investigated for use in leakage detection while an underwater
vehicle performs a routine pipeline survey.152
In SSS, an underwater vehicle towed by a ship carries sonar transducers on its starboard and port sides,
and as the vehicle progresses along a predetermined
path, an array of transducers pings the seafloor. By
adjusting the ping angle through the use of a line
array of transducers, a swath of seafloor can be monitored at once. Since the angle cannot be extended to be
directly below the vehicle, SSS scans have a darkened
blind spot that runs along the middle of the image153
(Figure 22). From SSS scans, certain problems with
pipes can be detected, such as free spanning, which can
be determined by analyzing the acoustic shadow cast by
the pipeline (Figure 23, left). Major cracks in the concrete coating around the pipeline may appear as anomalous shadows on the pipeline (Figure 23, right).
Furthermore, pipeline movements, or ‘‘pipe walking’’
may be deduced by observing for marks on the seafloor
near the pipeline. Anchor scars left by ship anchors
dragging along the seafloor may hint at possible damage, especially if the scars cross the pipeline. Difficulties
arising from the use of SSS focus on data processing in
order to integrate multiple sonar scans to form a coherent and accurate picture of the seafloor. SSS also
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Figure 22. (Left) Diagram of how a side scan sonar works. Objects that have high backscatter (i.e. boulders, pipelines, artificial
objects) appear brighter, whereas objects that have low backscatter appear more gray.154 (Right) Side scan sonar image of an
exposed subsea pipeline.155
assumes that the seafloor is flat and thus may be less
accurate for uneven seafloors.151 Recent efforts include
development of geometric and probabilistic approaches
to mitigate error and boost image resolution beyond
sensor capabilities.158 Information from the sonar has
also been used to create three-dimensional (3D) mosaics
of the seafloor, emphasizing the appearance of manmade objects such as sunken ships and pipelines.159,160
In addition to looking at the amplitude of the
reflected waves, the frequency of the pulses can also be
altered to gain even more information. In wideband
sonar (WBS), the sonar emits a pulse containing a
range of frequencies, and each frequency component
backscatters differently depending on the material
reflecting the pulse. Advantages of WBS include higher
resolution and wide range for customization and optimization according to the situation.161 Advances to this
method are partially bioinspired through the observation of dolphins, which also use frequency-rich pulses
to obtain information about the environment in order
to navigate.162,163 Using the bioinspired approach,
WBS has been recently used to not only inspect the
positioning of subsea pipelines, but also provide information on flow assurance (i.e. whether flow is being
obstructed by a foreign body).164
Radiography
Radiography has been used in fields outside of subsea
engineering, most notably in medicine. Electromagnetic
radiation, such as X-rays, is capable of penetrating
through an object and attenuate depending on its interaction with the atomic matter within the object.
Materials with higher atomic number, such as calcium
in bones, more readily absorb radiation compared to
water and air. The receiver, typically in the form of a
film at the other side of the object, accepts the modified
rays and darkens in areas where the rays were stronger.
Thus, bone appears light in X-ray images while soft tissue, blood, and air appear progressively darker.
Radiography therefore provides a unique, internal perspective of an object at a level of depth and breadth
unmatched by other inspection technologies.
Using the same concept, operators have used radiography to look inside a section of pipeline to detect
cracks and corrosion or welding abnormalities.165 As
shown in Figure 24, radiography of a pipeline section
can be carried out in one of two configurations. Figure
24 (left) shows the more convenient configuration,
where a radiation source is positioned on one side of
the pipe and a sensitive film or plate, typically a phosphor plate, is placed on the opposite end. The radiation
passes through both walls (‘‘double wall’’) before landing on the plate, with anomalies in the wall thickness
causing anomalous spots on the captured image
(Figure 25). The double wall method requires multiple
exposures to obtain the full picture of the pipe. The
double wall method is further categorized into double
wall single image (DWSI) and double wall double
image (DWDI). The other configuration, used more
typically for subsea pipelines or in cases where the pipe
bore is accessible, is to have the radiation source centered in the axis of the pipe and capture the radiation
by mounting a film that surrounds the circumference of
the pipe. The radiation source can be delivered using a
pipeline crawler (section Pipeline Crawlers). This
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Structural Health Monitoring 19(2)
Figure 23. (Left) Side scan sonar image showing cracked and missing concrete for a subsea pipeline, courtesy of JW Fishers.156
(Right) Free span detected as separation between the pipeline acoustic image and its acoustic shadow, courtesy of Terra Remote
Sensing.157 Dark areas in the figures are acoustic shadows (i.e. where there were no acoustic reflections).
Figure 24. Configurations for pipeline radiographic inspection. (Left) Source placed on one side, and receiver film on the other
(‘‘double wall, single image’’). If the radiation source is sufficiently far away, then two walls will be imaged (‘‘double wall, double
image’’). (Right) Source is inside the pipe while the film wraps around the circumference (‘‘single wall’’); more typical for large
diameter or subsea pipes.
Figure 25. Simplified diagram showing the use of radiography to detect defects in a pipeline. Anomalies such as corrosion and
cracks will create a noticeable difference in the baseline noise level of the detected radiation particles. With image processing, this
method can be used to automatically create defect maps of a pipeline.
Ho et al.
Figure 26. Depiction of a subsea pipeline radiography
module.173 The source and detector may be rotated around the
pipeline to get multiple angles of exposure.
method, called the single wall single image (SWSI)
method benefits from only passing the radiation
through the wall once, but requires sending a radiation
source into the pipeline.166
Once the pipewall-modulated radiation is received
by the film/plate, the image can be extracted for analysis. Currently, there are two popular methods of extraction: computed radiography and digital radiography.
In computed radiography, the film/plate contains phosphor, which is sensitive to the strength of the received
radiation, and carries the image of the pipe section in
the form of energized phosphor crystals. A laser beam
is then used to release the energy of the crystals, which
results in the emission of light. The light is recorded
and stored into a digital image.167 Digital radiography,
on the other hand, is an improvement upon computed
radiography especially in regard to its rapid readout.
Digital radiography makes use of a flat plate detector
(FPD) that can instantly convert incident radiation into
electrical charge which can be immediately read by a
computer. Conversion is done in one of two available
methods. In one method (i.e. ‘‘indirect conversion’’),
the FPD contains a cesium iodide scintillator, which in
the presence of radiation produces light through fluorescence. The light is captured by a dense matrix of
amorphous silicon photodiodes whose electrical output
can be amplified and measured to create a digital
image. In the alternative method (i.e. ‘‘direct conversion’’), photoconductive amorphous selenium is used in
conjunction with a micro electrode plate. Use of photoconductors eliminates the need for scintillators and
thus reduces scatter of light. As a result, higher sharpness and resolution can be achieved.168,169
Another aspect to consider for radiography is the
radiation source. For pipelines, popular choices include
gamma radiation and X-rays. Gamma radiation can be
generated from isotopes such as Iridium 192, Cobalt
60, Ytterbium 169, Thulium 170, Selenium 75, and
Cesium 137. The choice of radiation depends mainly
627
on the thickness of the pipewall, with Cobalt 60 providing the highest penetration (25–200 mm).170 A potential drawback is that isotopes continuously generate
radiation and require additional safety handling. The
amount of radiation is also difficult to control, thus
necessitating the use of different isotopes for optimal
use in different wall thicknesses. X-rays, on the other
hand, are controlled by the amount of electrical power
input. Controllability of the radiation in general makes
handling safer and optimization easier. Betatrons and
linear accelerators are the main options of hardware
for generating X-rays with greater penetration abilities.
On the other hand, betatrons and linear accelerators
require high power consumption and will generate
heat.166
For onshore pipelines, personnel can be sent directly
to perform radiography, but for subsea pipelines, the
apparatus required for radiography can be delivered
through robotic vehicles (see section ‘‘Inline inspection’’). Due to the additional effects of water and the
need to send an unmanned vehicle to potentially very
deep waters, the challenge in offshore pipeline radiography is much greater than for onshore pipelines.171,172
Oceaneering’s subsea radiography solution (Figure 26)
is one of the few examples of current industry solutions
for using radiographic techniques to detect subsea pipeline defects without needing access to the pipeline bore.
Current research into radiographic techniques for subsea pipelines includes development of simulation
packages to help predict and improve radiography in
subsea conditions. A recent development used Monte
Carlo–based calculations to simulate the scatter of
radiation in similar situations as those encountered in
the ocean.173 Efforts are also being spent to refine the
image processing portion so that less components and
less shots are needed, which will help reduce the difficulty of subsea radiographic measurements.174,175
Inline inspection
Intelligent/intelligence pigging. Over time, debris and precipitates such as wax, hydrates, and asphaltenes from the
production fluid build up inside the pipeline. The buildup decreases the cross-sectional area and thus decreases
flow rate, and in severe cases, completely shuts off flow
when the deposits block the whole cross section. To
prevent and to combat such events, inline devices called
‘‘pigs’’ are launched into the pipe at high speeds. The
pig launcher applies high hydraulic pressure behind the
pig, thus propelling the pig through the pipeline. Such a
process is called ‘‘pigging.’’
Historically, the primary function of the pig is to
clean the flowline of anything that may impede flow.
Pigs began as bundles of rags and leather to scrape and
absorb deposits, and have now evolved to include a
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Structural Health Monitoring 19(2)
Table 1. Types of intelligent pigs used for inline inspection.
Intelligent pig type
Function
Ultrasound
Magnetic flux leakage
Eddy current
Radiation
Metal loss, corrosion, and crack detection via methods described in earlier sections.
Caliper/geometry
Imaging (Optopig)
Detection of pipeline burial and coating condition. Intensity of gamma ray radiation is
correlated to burial and concrete coating thickness.179
Measure the shape of the internal surface. Spring loaded sensing fingers around the
circumference of the pig, coupled with odometer reveals pipe geometric anomalies and
their location along the pipeline.180
Laser displacement scanning to measure the geometry of the pipe cross section in more
detail. Small cavities in the metal due to events such as corrosion can be detected using
this technique.181,182
family of different pig types for accomplishing different
objectives. Gauging pigs and intelligent pigs, in particular, are designed to return information about the state
of the pipeline. Gauging pigs include a flat sheet of soft
metal that can be damaged by any stiff intrusions in
the pipeline. The nature of the damage can suggest the
type and location of the intrusion in the pipeline.176,177
Following the deployment of cleaning and gauging
pigs, the more sophisticated intelligent pig can be
launched into the pipeline to obtain more detailed
information. For offshore pipelines, especially in deep
water, the use of intelligent pigs to inspect pipelines is
crucial as many times the pipe may be coated by concrete and multiple layers of protection that may preclude the use of most externally operated inspection
techniques. The intelligent pig may consist of multiple
linked modules each carrying particular instruments
designed to measure specific parameters of the pipeline.
Intelligent pigs can carry NDT instruments mentioned
in prior sections, such as eddy current sensors, ultrasound, and MFL sensors. Intelligent pigs can further
provide information about its travel path (external
tracking may be prevented due to excessive water depth
and distance) within the pipeline through the installation of accessory instrumentation such as odometers
and gyroscopes. Pipes may also be outfitted with magnetic markers that help determine pig location.
However, in cases where the markers may not be outfitted, there may be difficulty in exactly tracking the
defects detected by the pig. In such cases, the girth
welds between each pipeline segment may serve as an
alternative marker to track pig movement.178 In order
to provide flexibility in deployment to different types
of pipelines, pigs may be bidirectional and can function
in either direction. Table 1 summarizes the major types
of intelligent pigs currently available for use. Example
figures of intelligent pigs are shown in Figure 27. Use
of pigs for subsea pipelines is typically more
complicated than for onshore pipelines. There is an
increased risk of damage to the environment if contents
leak from the pipeline (e.g. when gas bleeding is needed
prior to pigging), and if sealing is inadequate, large
volumes of water may enter the pipeline. The typically
increased wall thickness and length also imposes additional challenges for pig-based inspection.184 Pig tracking also becomes more difficult with increase in water
depth and its attenuating effects on most forms of
communication.
Pipeline crawlers. In certain situations, the pipeline may
be unpiggable due to a number of factors, such as
excessively small pipeline diameters, tight bends, Yconnections, or simply that there are no available pig
launchers onsite.185 Thus for cases where a pipeline is
deemed unpiggable, an external pipeline crawler may
be used.
Like intelligent pigs, external pipeline crawlers can
carry a range of inspection tools that can determine the
health status of the pipeline. Different models of pipeline crawlers may scan the pipeline via axial measurements (thus requiring multiple passes) or circumferential
measurements. However, while pigs may be propelled
through the pipeline through a strong hydraulic pressure
differential within the pipeline, crawlers will need alternative methods (e.g. motors, tugging by ROV or diver)
of travel along the pipe, including risers (Figure 28).
External crawlers have the added challenge of sometimes
needing to inspect through a thick layer of concrete coating in addition to the thin protective coating of subsea
pipelines. Depending on the state of the pipeline and the
specific flow assurance problem to be corrected, expensive
pipeline modifications may be required (e.g. removal of
marine growth and removal of concrete coating). A number of service companies, such as Innospection,
Oceaneering, and the Subea Integrity Group have
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629
Figure 27. (Left) Single pig segment containing caliper instrumentation.183 (Right) Intelligent pig with MFL sensors.34
developed crawlers suited for a wide range of situations
regarding unpiggable or unknown pipelines.185
Robotic vehicles
Similar to most industries, when a task becomes too
expensive or too dangerous for a human to accomplish,
robotic substitutes are used instead. The subsea environment is especially inaccessible to humans even with
proper tools and thus a variety of unmanned robotic
vehicles have been developed for the inspection and
maintenance of subsea pipelines.188
ROVs. The remotely operated underwater vehicle
(ROV) is a versatile, manually controlled robot used in
the offshore industry for subsea environments.189–192
Typically, the ROV consists of a top block made of
buoyant materials such as syntactic foam, which is
attached to a lower aluminum chassis that houses various controls and propulsion systems. The ROV can be
equipped with a number of tools, such as video cameras, chemical samplers, and lighting systems, to carry
out a wide range of tasks. ROVs have been used in subsea pipeline maintenance,193 rescue operations,194 and
scientific oceanic exploration.195 ROVs are tethered for
power and controls and thus may be launched from a
manned submersible or from the topside (Figure 29)
depending on the desired depth. Sea currents and other
weather disturbances may cause tugging on the tether
and make ROV positioning difficult. Typically, ROVs
are rated for 4000 m of salt water (msw). For pipeline
inspection, ROVs are often equipped with a range of
sensors described in the other sections of this review
(e.g. acoustic, temperature, and radiographic) for leakage detection and side scan sonars for more global
inspection of pipelines. Furthermore, unlike inline
inspection with pigging, ROVs are not limited by pipeline geometry.
AUVs. A more recent advancement upon the ROV for
pipeline inspection is the automated underwater vehicle
(AUV). As opposed to the manually controlled ROV,
the AUV can operate independently without human
intervention. While a majority of AUVs are used for
mapping and searching tasks (e.g. bathymetric AUVs),
inspection-class AUVs, which have additional components that enable hovering over a structure, are used
more primarily in the offshore oil and gas industry for
subsea structure inspection. AUVs do not require
tethering to a nearby vessel, and therefore the costs of
traditional subsea pipeline inspection which require
additional vessels and man hours (e.g. through ROVs)
can be significantly driven down. Since there are no
human operators, the challenge in the development of
AUVs is developing robust algorithms that allow the
vehicle to identify and track pipelines while at the same
time catching anomalies that may point to damage.197
The AUV must be able to recognize the presence of
damage, such as leakage, and provide an estimation of
the AUV location where the damage was detected.198
Advancement in AUV inspection capabilities has
allowed AUVs to begin taking over tasks normally
reserved for divers or ROVs, such as pipeline corrosion
inspection.199 Some examples of commercially available
AUVs for subsea inspection include the Subsea 7
Autonomous Inspection Vehicle (AIV),200 the
Lockheed Martin Marlin AUV,201 the Kongsberg and
Hydroid AUVs (e.g. Hugin, Munin and Reemus models),202 among many others.
Development of AUVs is still ongoing, with research
efforts trying to leverage the fact that AUVs do not require
a human operator. While still in the laboratory phase,
some researchers are developing AUVs (i.e. FlatFish
AUV; Figure 30203) for long-term subsea operation, or, in
other words, subsea residency. Such long-term AUVs will
reside in a dedicated docking station and will be available
24/7 for inspection tasks. The docking station will allow
the recharging of the AUV while at the same time download data acquired by the AUV.
Without direct human control as in the case of
ROVs, an AI will be needed to guide the AUV on most
tasks, such as navigation. As the subsea environment
can be unpredictable, accommodating the AI for all
scenarios can be a daunting task. Thus, there is still
ongoing research in improving the automatic operation
of AUVs in subsea conditions, and better poise them
for mission success in the face of uncertainty.204 The
introduction of AUVs has also allowed the entry of
new inspection and monitoring methods. Through
improvements to the AUV AI, the AUV can be used to
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Structural Health Monitoring 19(2)
Figure 28. Example of subsea pipeline crawlers. (Left) Innospection MEC Pipe Crawler on a 13-in riser.186 (Center and Right)
Innospection MEC Combi Crawler before and during deployment.187 An ultrasonic probe is carried on the crawler. These particular
examples show crawlers that are self-driven and are tethered to a power source. Courtesy of Innospection.
advance underwater acoustic networks.205 If subsea
sensor nodes that constantly monitor pipeline conditions can transmit data acoustically to AUVs, then the
AUV will be a key part in the formation of a robust
cyber-physical system that help unify sensor data from
multiple subsea sensors.
FOS
One of the most promising set of sensor technologies
for both onshore and offshore pipeline monitoring are
FOS. FOS at the most basic level are strands of silica
glass (although plastic-based FOS are emerging206) that
carry light through total internal reflection. The fiber
optic cables used for FOS were first intended for communications, and the benefits of low attenuation over
long distance and immunity to electromagnetic interference were inherited for the benefit of sensing applications. For communications, each property of light,
such as intensity, wavelength, phase, and polarity, can
be used to encode information. In the case of FOS, one
or more of such properties are modulated by the environment and the change in the properties are used to
obtain information about the environment. The flexibility in which FOS can utilize the properties of light
has led to the development of many different types of
sensors, many of which are beyond the scope of this
review. For the purposes of subsea pipeline monitoring,
current FOS can be broadly classified as point (i.e.
quasi-distributed) or distributed sensors (i.e. distributed). As the name implies, quasi-distributed sensors
measure only at a single point typically with high resolution, high accuracy, and high precision. Distributed
FOS, on the other hand, utilize the entire fiber optic
cable as a continuous series of sensors. Compared to
quasi-distributed sensors, distributed FOS can more
easily cover a broad range of area at the cost of resolution, precision, and affordability.
Among quasi-distributed FOS for subsea pipeline
monitoring, fiber Bragg grating (FBG) sensors are
possibly the most prominent and well known. FBGs
are wavelength modulated FOS composed of partially
reflective gratings inscribed into the core of the fiber
optic cable (Figure 31). The gratings are composed of a
series of periodic sections of glass that have a different
refractive index compared to the core and can be
inscribed using laser interference patterns of phase
masks. The gratings reflect a portion of the light with
the wavelength matching the period of the grating (i.e.
central wavelength), and the period is linearly affected
by strain, temperature, and pressure.207
Leveraging their linear strain sensitivity, FBGs have
been investigated for detection of mechanical changes
to the pipeline state such as bending, impact, fatigue,
and in cases of subsea pipelines and risers, VIV.208–211
With increasing recognition of the advantages of FBG
sensors, researchers have begun to develop methods of
encapsulation for deployment in harsh subsea environments. Figure 32 shows a design of a polyurethane
clamp that allows FBGs to be retrofitted onto existing
subsea pipelines. The clamp is coupled to the pipeline
surface through a layer of marine epoxy. With the
FBGs mounted on metallic strips embedded into the
interior surface of the clamp and in contact with the
pipe, rigid strain transfer can be made possible.214,215
Through mechanical changes in the pipeline, certain
conditions that may affect flow assurance may be
inferred non-intrusively. In subsea pipelines, deposit
build up (e.g. hydrates, paraffin, and asphaltene) and
slugging can pose as significant flow assurance risk due
to the high difficulty of correcting any problems submerged deep in the ocean. Furthermore, when a problem becomes too severe, the pipeline will be taken out
of operation and thus can incur staggering economic
costs as long as the pipeline is not operational.
However, with real-time monitoring made possible by
FOS, less invasive remedial actions can be taken before
pipeline replacements are needed. So far, measurement
of strain distribution and evolution over time, along
with measurement of heat flux have allowed
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631
Figure 29. (Left) Diagram of an ROV deployment process; multiple components are required onboard the vessel in order to
operate an ROV.196 (Right) Depiction of ROV inspection of subsea pipeline using sonar.
Figure 30. The FlatFish AUV for long-term subsea operation FlatFish AUV.203
researchers to detect gas hydrates, paraffin deposition,
and slug formation.216 Combined with models of pipeline behavior, flow assurance problems may be predicted with higher accuracy.
Since the hoop strain of a pipeline is directly proportional to its internal pressure, FBGs have been used to
detect and localize leakage based on the NPW. As with
conventional NPW-based leakage detection methods,
FBGs can measure the time of arrival of the NPW in
order to estimate the location of the leakage. However,
one of the drawbacks of traditional NPW techniques is
insensitivity to low flow rate leakages due to the
attenuation of the wave prior to reaching the sensor
location. To overcome this obstacle, FBGs can be easily installed in periodic distances along the pipeline and
capture the hoop strain loss profile due to the NPW
before the NPW attenuates below sensor detection
thresholds217 (Figure 33, top). Through the use of
strain amplifying enclosures, the inherent high sensitivity of FBGs can be enhanced to measure low strain
changes that may be caused by leakages218 (Figure 33,
bottom).
With further assistance from support vector machine
(SVM) classifiers, this FBG-based leakage method can
be further refined to better distinguish between random
noise and real leakage events.219 Another advantage of
FBG is its versatility in targeting different measurands
simply through the design of the FBG enclosure. An
example is a FBG chemical leakage detector that functions by incorporating a hydrocarbon-sensitive polymer
into the sensor packaging. Once the polymer comes in
contact with certain hydrocarbons, the polymer will
swell and strain the FBG, thus indicating the presence
of a leak.220 Long period gratings (LPGs) are a subtype
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Structural Health Monitoring 19(2)
Figure 31. Diagram of fiber Bragg grating operation. Broadband light is injected into the fiber and travels to the gratings where a
narrow band of light centered around the central wavelength is reflected. The shift of the Bragg wavelength is linearly and directly
related to the strain (è), temperature (T), or pressure (P).
of FBG and have shown ability to measure presence of
hydrocarbons through direct exposure of chemicals to
the gratings.221 In a recent study, a cobalt-doped FBG
fiber treated with laser heating indicated that the bare
FBG is sensitive to different types of gases.222
In addition to FBGs, intrinsic, fiber-based interferometric sensors have also been reported for pipeline
monitoring. An advantage that interferometers possess
over FBGs is the inherent potential to reach higher
sampling frequencies due to the lack of need for a spectral filter required for FBGs to calibrate between the
reflected wavelength and the sensor signal. Thus, the
higher sampling frequency allows interferometric sensors to measure acoustic signals such as those discussed
previously for piezoelectric sensors. As such, MachZehnder-based and Sagnac-based fiber interferometers
have been reported for leakage detection through the
measurement of acoustic signals and processing of the
measurements through wavelet analysis.223 On the
other hand, unlike FBGs, fiber-based interferometers
cannot be multiplexed and may require more strategic
placement of sensors on the pipeline. Extrinsic fiberbased sensors for SHM has also been reported. The
laser beam delivered by the fiber under the right circumstances can generate ultrasonic waves in the structure, and the propagated waves,224 also sensed by fiber
optics, can be used to determine damage. Such a monitoring technique has been demonstrated on pipelines,225
including for those found in nuclear power plants,226
and with modification may have potential for subsea
pipeline usage.
While fiber optic point sensors offer unique advantages, such as high resolution, sensitivity and versatility,
distributed FOS have enjoyed at least the same amount
of prominence in fiber optic-based applications in pipeline monitoring. Distributed FOS are so-called fully
distributed because the entire fiber length is sensitive to
changes, and in effect is almost equivalent to having
thousands of point sensors in one line. Distributed FOS
utilize optical time domain reflectometry (OTDR) to
measure the backscattered light all along the fiber
(Figure 34). Distributed fiber optic sensing currently
relies on three types of light backscattering: Brillouin,
Raman, and Rayleigh, each of which are useful for
detecting strain and temperature.
More specifically, Brillouin optical time domain
reflectometry (BOTDR) is used for strain measurements from Brillouin backscattering, and Raman optical time domain reflectometry (ROTDR) is used for
temperature measurements from Raman backscattering. In either case, light is injected at one end of the
fiber and the interrogator waits for and accumulates
the backscatter signals from the fiber, which often takes
time due to the low intensity of the backscatter.
However, with the use of a Brillouin optical time
domain analyzer (BOTDA), in which additional light is
injected at the other end for additional stimulation, the
sampling rate can be greatly increased. Most applications will benefit from BOTDA as long as both ends of
the fiber can be connected to the interrogator. Certain
interrogators carry both BOTDR and BOTDA, and
thus if one end of the fiber is damaged, the interrogator
can switch from BOTDA to BOTDR without a complete compromise of the sensing fiber.227 The strain
measurements obtained from distributed sensing (i.e.
distributed strain sensing (DSS)) has been used to
gather high volumes of data about subsea pipeline
health. In a recent report, through the installation of
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633
Figure 32. (Left) Design of subsea pipeline clamp containing FBG sensors.212 (Right) Photo of FBG clamp installed on a subsea
pipeline.213
Figure 33. (Top) Potential arrangement of FBG sensors (represented by Si and Li) to measure hoop strain è on a pipeline. The
distribution of strain can help locate leakage points if the upstream and downstream sensors fail to detect the initial NPW.217
(Bottom) Encapsulation to enhance and protect FBG sensors for leakage detection.218
three fibers distributed equally around the circumference of the pipeline, buckling and upheaval, along with
the effects of the hydrostatic pressure from the water
column onto the pipe shape, can be detected and
estimated.228 Pipeline corrosion and leakage can also
be monitored using DSS229. On the other hand, distributed fiber sensors dedicated to distributed temperature
sensing (DTS) have been used to detect thermal
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Structural Health Monitoring 19(2)
Figure 34. Spectra for Rayleigh, Brillouin, and Raman backscatter. The intensity of Raman backscatter is sensitive to temperature,
while the wavelength of Brillouin backscatter is sensitive to strain. The intensity of Rayleigh backscatter is sensitive to both
temperature and strain.
Figure 35. Example of distributed temperature sensing to detect free spanning and scouring in buried subsea pipelines. (Left)
Experimental setup with a thermal cable aligned with a fiber optic cable along a submerged, buried pipeline.234 (Center) Pipeline
before and after burial, with center portion exposed to simulate free spanning.235 (Right) Temperature profile over time as thermal
cable generates heat. The buried lengths heat up faster than the exposed length, thus indicating locations where free spanning or
scouring has occurred.235
anomalies associated with rapidly escaping gases during leakage, as briefly mentioned in a previous section.230,231 DTS has also been used to detect scouring
of pipelines by measuring the rate of heat injection into
an adjacent thermal wire. Parts exposed to water will
heat up much slower and thus indicate exposure of the
pipeline and potential free spanning232,233 (Figure 35).
The heating data has also been used to train a variety
of machine learning algorithms to automatically identify anomalous temperature profiles.232–234
Distributed sensing, especially DTS, is a proven
solution to onshore and offshore pipeline monitoring
and is now offered by most major oil and gas service
and technology companies, such as Schlumberger,
Baker Hughes, and Halliburton.236–238 Other types of
distributed FOS include recent development that incorporates quantum dots that functionalize selected parts
of the fiber cable to be sensitive to temperature.239
Certain systems have integrated modules that allow
measurement of both strain and temperature (distributed strain and temperature sensor (DSTS or DTSS)).
Compared to Brillouin and Raman scattering,
Rayleigh scattering has higher intensity and can be
measured much faster than the other two types of
backscatter. Thus, Rayleigh backscattering can be measured at high sampling frequencies (.100 kHz) and
can be used to measure vibrations and acoustic events.
In distributed acoustic sensing (DAS), the entire fiber
can be used as a continuous array of acoustic sensors.
The ability to measure acoustics along the length of a
pipeline (currently able to extend up to 80 + km, albeit
at lower sampling frequencies and spatial resolution240)
allows the operator to rapidly detect leakage, third
party intrusions, and other types of disturbances (e.g.
pedestrians, vehicles, and land motion). Thus, for
onshore pipelines, DAS is emerging as a top tool for
pipeline security purposes. The flow regime and the
passage of inline inspection tools inside the pipeline can
Ho et al.
635
Figure 36. DAS combined with DTS to detect the acoustic and temperature signatures of oil plumes due to seepage whether
through natural processes or potentially from a pipeline.242
also be determined based on the acoustic signature.240,241 Combination with other sensing modalities
allow a synergistic evaluation of the pipeline conditions. For example, DAS and DTS data fusion has
allowed the detection of oil plumes that may originate
naturally from reservoirs or from pipeline leakages242
(Figure 36).
On the other hand, according to the lack of reports
in the literature, the application of DAS for direct subsea pipeline monitoring has not yet reached a mature,
commercial stage. Alternatively, due to the ability of
DAS to capture acoustic signals over a large area, DAS
may be suitable for subsea communications in which
fiber optic cables can form passive acoustic sensors that
can listen to acoustic signals generated by sensors along
a subsea pipeline.
Synergy of sensor technologies
The subsea environment is a highly complex environment with ever changing conditions. Combined with
the inherent maintenance requirements of man-made
pipelines, the task of pipeline inspection and monitoring can be a very daunting task requiring the wise use
of multiple tools, often at the same time, in order to
achieve the optimal result. Each sensing technology
mentioned previously have their own advantages and
disadvantages, and each can be suitable for specific
situations (Table 2).
Conclusion
As revealed by the literature review, there is a vast ecosystem of inspection and monitoring technologies that
are already available due to the critical importance of
rapidly detecting and correcting pipeline damage before
loss of life and property can occur due to pipeline failure. Some of the most commonly used inspection methods include MFL, eddy current, ultrasound, and
radiography, all of which were introduced decades ago
and have now reached maturation. Incidentally, there
is a general resistance in the oil and gas industry to testing and early adoption of new technologies despite the
development of radically new and promising inspection
and monitoring methods (e.g. DAS). Such resistance
may be attributed to several factors, including the fear
of being the first user to experience a failure in using
the new technology, inadequate history of the sensor in
practical use, and the extra work that may be needed to
ensure compliance of the new technology to strict regulations. Cost is also a major factor in the adoption of
new and unproven technologies in the oil and gas
industry. While numerous new inspection and monitoring technologies are continuously developed and
demonstrated in laboratory settings, the process of
adapting or using the technologies for harsh environments (e.g. subsea) is often not cost-effective and can
deter adaption of the technologies into the industry.
Adoption of new technologies can disrupt operations
and thus incur opportunity costs from stoppage of production and the resulting loss of revenue. On the other
hand, the demonstrated success and cost effectiveness
of the sensors other fields (e.g. FOS in aerospace and
civil SHM) may encourage more users to adopt the
new inspection/monitoring methods. Increased awareness and understanding of new technology on the part
of governmental regulatory agencies will also foster
further cooperation between the government and
industry in promoting the use of newer and better sensing systems.
Can inspect both internal and external defects; can be used for most types of
materials associated with subsea pipelines; no need for direct access to pipe;
minimal preparation of pipeline; can clearly distinguish different layers of pipeline
layers.
Can provide global information about pipeline (e.g. shape, location); can detect
scouring and free spanning; may be able to predict potential future threats from
pipeline movement or from changes in environment; inexpensive for certain
applications; may be able to discern different materials based on backscatter.
Highly accurate; capable of low loss over long distances; small and non-intrusive;
sensors are inexpensive; immune to electromagnetic interference; highly flexible
functionality depending on packaging and sensing principle; can possibly detect the
widest range of defects types depending on sensor design; thousands of sensing
points can be integrated into a single cable.
Very fragile; interrogation systems are expensive; requires permanent installation;
in certain cases, requires installation prior/concurrent to pipeline deployment;
significant signal processing may be required; depending on sensing principle and
requirements, close contact with pipeline is needed; damage at one point of the
fiber will disable the rest of the sensor line (with exception to BOTDA, which can
be switched to BOTDR if one end of the line is damaged).
Not useful for local defect monitoring; side scan sonar will have a relatively large
blind spot; use of a ship may be required; high computational power needed for
sophisticated sonar scanning.
Can only determine instantaneous assessment of damage and cannot provide
information on previously accrued damage (prior to installation); array of
transducers needed for certain advanced functions such as leakage localization;
arrayed deployment still under research for subsea application; susceptible to
unrelated environmental noise.
Hazardous to nearby humans and fauna; slower than other methods; highly
dependent on user experience; requires two sides of access; defects aligned along
radiation beam may not be detected.
Range can be limited by bends and discontinuities (e.g. flanges, valves) in the
pipeline; viscoelastic coatings (e.g. bitumen) can attenuate guided waves; ambient
noise causing vibrations in the pipe can increase noise in signal; certain propagation
modes are undesirable and increase level of coherent noise.
Requires couplant; surface cleaning may be required; highly dependent on user
experience; physical material properties (e.g. large grain size) may affect wave
attenuation; difficult to use on rough, irregular surfaces; defects aligned along
ultrasonic beam may not be detected.
Mainly sensitive to surface and near-surface defects; highly vulnerable to magnetic
permeability in pipeline material; operator experience and some data processing
required; sensitive to lift-off.
Requires steady contact with pipeline, sometimes requiring welding to fix the
electrodes; may be tedious to set up depending on situation; requires direct
contact with metal of pipeline; dependent on operator experience.
Sensitive to movement speed (e.g. on pig); pipewall requires complete saturation;
more sensitive to near-surface defects; typically not suited for detecting axially
oriented defects; impurities in pipewall material may cause false negatives,
dependent on operator experience; data can be mostly ‘‘qualitative.’’
Disadvantages
MEC: movement-induced eddy current; PEC: pulsed eddy current; BOTDA: Brillouin optical time domain analyzer; BOTDR: Brillouin optical time domain reflectometry.
Fiber optics
Sonar
Radiography
Acoustic
emission/
hydrophone
Ultrasonicguided
wave
testing
Ultrasound
pulse-echo
Highly sensitive to surface defects; with proper set up (e.g. with MEC), can detect
through multiple layers; non-contact; no surface preparation needed; no need for
removal of most coatings or pipeline protection; with PEC, useful for determining
wall thickness; highly mature technology.
Can inspect both internal and external defects; high resolution and accuracy—can
provide detailed information about defect volume and shape; superior penetration
and overall flaw detection ability compared to most other techniques; suitable for
wall thickness measurements; can be used for detailed, non-radioactive imaging of
pipewall; highly mature technology.
Can inspect a long section of pipeline for wall thinning and certain sizes of defects;
can be useful for inspection of the interface between pipe and coating; can be used
to inspect inaccessible areas of the pipeline; in passive sensing schemes, guided
waves generated by external forces can be used for tasks such as impact
monitoring; multiple selection of modes available for different types of defects or
inspection tasks.
Sensitive to acoustics generated by certain pipeline conditions (e.g. leakage,
impacts); with an array, can be used to locate leakage and impact; integration with
active sonar allows detection of wider range of events (e.g. leakage at long
distance).
High sensitivity; minimal data processing needed, able to detect both internal and
external defects, including many types of corrosion; minimally affected by
environmental factors; highly mature technology; not affected by non-ferrous
coatings; non-contact; no need for removal of most coatings or pipeline
protection.
Intuitive data, requiring minimal data processing; non-intrusive to pipeline internals;
able to detect wide range of corrosion and other defects; simple installation for
certain configurations; can be set up for online monitoring (requires permanent
installation and cover from water).
Magnetic
flux leakage
Electrical/field
signature
mapping/
potential drop
mapping
Eddy current
Advantages
Technology
Table 2. Some of the advantages and disadvantages of the major sensing technologies discussed in this review.
636
Structural Health Monitoring 19(2)
Ho et al.
With respect to the advancement of inspection and
monitoring technologies for subsea pipelines, there is
a desire to detect pipeline anomalies with maximum
detail and low cost. Common inspection tools such as
MFL, eddy current, and ultrasound, while mature,
are still receiving incremental improvements in measurement range, accuracy, speed, and portability. In
order to reduce costs and improve usability, increasing amounts of automation are being developed. The
use of ROVs, AUVs, pipe crawlers, and intelligent
pigs allow safe inspection of hard to reach places and
often provide higher accuracy reports of pipe health
status compared to human divers. The upfront costs
of using robotics for inspection is small compared to
the potential costs of affecting a costly repair and
cleanup of a failed pipeline that may have been otherwise missed by a human inspector. On the other hand,
monitoring systems that are permanently installed
along the pipeline can gather continuous data.
Monitoring systems, which may not always have the
detail and resolution provided by inspection technologies, can be more effective than periodic inspection
with respect to providing a constant surveillance for
potential damage. Fiber optic sensors in particular
are receiving greater and greater attention in the
industry for use across a wide variety of applications,
including subsea pipelines. Fiber optic sensing can be
used rapidly and accurately to detect a broad range of
pipeline conditions. However, the need to permanently and safely install long lengths of fiber optics
presents a different set of challenges compared to
inspection. In some cases, the challenge may outweigh
the benefits. Furthermore, the current high cost of the
fiber optic interrogators may limit usage to key pipelines or critical portions of pipelines only.
A similar development present in the advancement
of all sensing technologies is the increasing amounts of
data produced by the sensors. For example, an intelligent pig carrying multiple modules of inspection tools
or a distributed fiber optic line can produce extreme
amounts of data that require special processing methods in order to extract key information. Thus, another
emerging topic not covered in this review is Big Data
and the associated algorithms, including machine learning, used to make sense of all the great volumes of
information generated by sensors. The methods used to
contend with the big data for subsea pipelines covers a
vast breadth of topics and warrants a separate, dedicated review. With continuous, parallel advancements
in sensor designs and data processing methods, we are
witnessing an ongoing and far reaching wave of innovation in SHM technology that will transform the subsea pipeline industry and beyond.
637
Declaration of conflicting interests
The author(s) declared no potential conflicts of interest with
respect to the research, authorship, and/or publication of this
article.
Funding
The author(s) received no financial support for the research,
authorship, and/or publication of this article.
ORCID iD
Michael Ho
https://orcid.org/0000-0003-4097-9906
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