1. Advances in Pipeline Inspection Technologies
John Grover, General Manager, Asia Pacific Region, GE Oil and Gas, PII Pipeline Solutions
Introduction
Pipelines are designed to ensure safe operation while achieving a long and profitable
life. However whilst in service, a pipeline will be exposed to operating conditions that
may not have been anticipated in design, and often impact on the risk of failure of
the pipeline. Pipelines will deteriorate in service due to corrosion and fatigue.
Operating conditions may vary due to change in product composition or tie-ins to
new wells. A pipeline may be exposed to more severe operational loading - increased
internal pressure and/or temperature, stress/strain induced by bending, external
impact, etc. A whole host of scenarios can occur which alter dramatically the
potential safe operation of a pipeline.
In order to minimise the potential risk of pipeline failure and the potential economic
and environmental consequences, operators have traditionally implemented a
programme of Inspection and Maintenance. Such a programme would limit the risk
of internal corrosion and involve; on-line product monitoring, internal inspection
using intelligent pigs to detect and monitor corrosion, combined with use of internal
inhibitors to control internal corrosion.
Clearly any potential risk to pipeline integrity can be prevented, however the
associated design, construction and maintenance cost may become unacceptable.
Early programmes of activity revolved around simple inspection, maintenance and
repair (IMR) programmes. More sophisticated operators looked to Risk Based
Inspection (RBI) methodology to focus on areas of higher risk and reduce overall
pipeline integrity programmes. These techniques and programmes were affordable
and could be implemented over time. However they did not achieve complete
integrity management.
In response to the increasingly demanding needs of pipeline operators across the
world a new class of solution is emerging. PII Pipeline Solutions have pioneered the
development of a fully integrated approach … Total Pipeline Integrity (TPI) solutions.
TPI combines affordability combined with technology, methodology and expertise to
provide a long-term solution for operators.
This paper discusses the concept and development of TPI through three
perspectives. Firstly we will look at the historical developments in pipeline inspection
technology. Secondly we will assess the variety of inspection tools available and
latest developments in pipeline integrity. Finally through a series of short case
histories, applications of TPI in the rehabilitation of pipelines will illustrate how TPI
and inspection advances have enabled pipeline operators to take practical steps in
developing individual integrity management programmes.
The concept of Total Pipeline Integrity covers all stages in the life of a pipeline, from
design through build, commissioning, operation, repair and eventual abandonment.

2. A Brief History of Pipeline Inspection
In order to appreciate the investment, both financial and technical, put into the
development of inspection systems, it is necessary to look at the major events that
have occurred since the original project began. From these early investments and
expertise PII has emerged as technology leader in pipeline inspection.
In 1974 that British Gas first identified the need for an alternative to the hydrostatic
pressure test as a means for periodic revalidation of high-pressure gas pipelines. On
line inspection was seen as the most cost effective method of monitoring pipeline
integrity and in the absence of adequate commercially available services, a major
programme of research and development was undertaken to seek engineering
solutions to some specific inspection problems associated with onshore and offshore
pipeline.
1970s
In identifying the need for a periodic revalidation of the British Gas pipeline network
using on line inspection techniques, a project team was established at the
Engineering Research Station, part of the British Gas Research & Technology
Division. The basic requirements of an on-line inspection system intended for the
revalidation of pipelines were formulated as follows:
1. Avoid interference with pipeline operation.
2. Detect all significant defects.
3. Accurately locate the defects.
4. Accurately determine the defect size.
5. Discriminate between spurious and true defects.
Even today these basic requirements are still vitally important in producing a cost
effective means of providing pipeline inspections.
The first magnetic flux inspection system, a 24" (600mm) diameter, successfully ran
in an onshore pipeline in 1977.
1980s
Further systems were designed and manufactured in 12" (300mm) 30" (750mm),
and 36" (900mm) diameters. Inspection vehicles began running on a regular basis
within the British Gas pipeline network enabling corrosion assessments to be carried
out on a line-by-line basis. Running such devices through the system then became a
routine operation and a run prioritisation system was produced to determine the
frequency of inspections based in a number of factors ranging from construction
details, coating problems to corrosion findings.
1981
First commercial run of an inspection vehicle for a non-BG pipeline operator took
place in a 24" (600mm) system inspected a 110 km long gas line for Gasunie in
Holland. This was a successful operation and provided further stimulus for extending
the range of vehicle sizes available.

3. 1982
Inspection vehicles in sizes 14" (350mm), 16" (400mm), 18" (450mm) and 42"
(1050mm) were introduced into service early.
1983
The first vehicle to identify stress corrosion cracking in pipelines was produced. This
vehicle system employed elastic waves of ultrasonic frequency and the inspection
technology was produced in 36 " (900mm) diameter.
1987
Further research work had been undertaken to produce another pig based inspection
system for use in offshore pipelines. The Burial and Coating vehicle was based on a
neutron interrogation method, which provides the penetrating power to look through
the pipe wall into the weight coating and sub-sea surroundings. The vehicle was
produced in 36" (900mm) diameter and ran in the Morecambe Bay and Rough Field
offshore pipelines. Run experience with the systems showed extremely good
correlation with traditional offshore survey methods.
1989
Magnetic Inspection vehicles covering the range of 6" (150mm) to 48" (1200mm)
were available. Work continued on the inspection of pipelines worldwide.
1994
The new business unit, Pipeline Integrity International was officially launched.
Pipeline Integrity International compromised the core business of pipeline inspection
whilst also providing a further range of pipeline related activities as follows:
1. Pipeline cleaning and conditioning with the acquisition of BG Kershaw.
2. Fitness of purpose work comprising defect assessment and safe operating
strategies. FFP was a forerunner to Total Pipeline Integrity.
3. Pipeline Repair specialising in epoxy sleeve repairs, hot tap and stoppling.
4. Pipeline Consultancy and Maintenance Management.
Pipeline Integrity International could now offer a complete service to the pipeline
operator.
1995
A second generation of electronics, the 020 system was introduced. The new
electronics were more compact, more reliable, less expensive and increased the
potential of the inspection systems in terms of:
1. Improved defect detection and sizing performance capability.
2. Improved inspection range - target for larger diameter vehicle 1,000 km.
3. Improved bore-passing capability.
4. Product bypass to inspect pipelines running at high velocities.
5. Fewer vehicle modules.
1996
The introduction of an internal survey tool based on the magnetic principle. This tool
was able to inspect the inner surface of thickwall pipelines, normally offshore
pipelines, and available in the size range 6" (150mm) to 16" (400mm).

4. 1998
On February 20th
1998, the sale/purchase of PII was agreed by Mercury Asset
Management. In June a new business plan for the company was launched and a
strategic plan for the next five years was agreed. The restructuring of the company
was conducted throughout 1998 and into 1999, to focus the company on customer
needs and provide a market-oriented approach to the business.
Amongst the new products successfully launched in 1998 was the 56” inspection tool
for large diameter pipes.
PII received its first full integrated maintenance contract, awarded in November by
Pemex. TPI was now in the early stages of development with client focussed
complex programmes being developed for long-term pipeline integrity.
1999
Launch of significant new products including the Elastic Wave 24” and Transverse
Field Inspection Tool.
In August 1999, the merger of PII and Pipetronix formed the world’s largest single
pipeline integrity company
2000
The integration of PII and Pipetronix led to the full development of TPI, as now a
single business could offer a complete range of technologies and solutions including
a mixture of MFL and Ultrasound technologies.
TPI was commercially marketed and a number of long-term framework agreements
were agreed with pipeline operators in North America, Latin America and Europe.
2002
PII Pipeline Solutions were acquired by GE Oil and Gas, and became the world’s
largest specialist pipeline integrity company. TPI applications, methodology and
technology is widely available, and pipeline operators work in strategic partnership
with PII to develop pipeline integrity management plans.
Increasing legislative requirements, and a commitment to development of new
products is driving the entire pipeline market towards adopting TPI.
New technology remains at the core of PII activities with the launch of EMATscan in
the second half of 2002.
With this background in mind, it is easy to see how PII Pipeline Solutions has
developed TPI, and how the markets leading pipeline operators are adapting this
flexible solution to create integrity management programmes.

5. Current Techniques
However, the history of a single business does not identify why TPI evolved. By
assessing the range of tools and solutions available, a clearer picture of why TPI is
so important emerges. Latest technology in particular has helped with the
development of sophisticated solutions for pipeline operators.
Amongst the most recent technology developments are:
TFI Technology & TranScan Tools
PII developed TFI technology in 1998 in response to a customer’s problem with
NAEC (Narrow Axial Extended Corrosion) seen on large diameter tape wrapped
pipelines in North America. Illustration 1
Since that time the technology has been refined and incorporated into an expanded
range of TranScan inspection tools.
Conventional MFL technology has poor sensitivity for detecting axial features since
the magnetic flux flows along the major axis of the defect, which therefore presents
little profile to disturb the flow. By directing the magnetic flux around the pipe the
axial defects now present a broad profile to the flux and hence a large disturbance
and signal are generated.
The success of this technology has been above expectations and has flushed out a
range of latent pipeline problems, which were not generally well known. These have
included several instances of quality problems with hook cracks and lack of fusion in
early generations of ERW pipe.

6. Multi-diameter inspection
Much of the worlds pipeline infrastructure is currently classified as unpiggable. For
example, North America has around 1,000,000 km of high-pressure transmission
pipelines. Over 85% of this was constructed before MFL inspection tools were
commercially available, and some 40-50% of the pipeline infrastructure is regarded
as unpiggable due to factors such as diameter changes, reduced bore valves etc. The
challenge for the pipeline integrity industry is to come up with solutions to inspect
these lines at a price, which is commercially attractive compared with the cost of
modifying the lines to make them piggable.
Many older pipelines were built from pipe of varying diameter. For example, it was
often the case that transportation costs for pipeline projects were minimised by
transporting 2 diameters of pipe, one inside the other, for example 24” pipe inside
26” pipe. Standard inspection tools can generally cope with a bore change of 2” or so
(in larger diameters at least), but larger diameter changes used to make these
pipelines ‘unpiggable’ using inspection tools.
In the last 2 years significant investment has gone into developing special inspection
tools to make such lines piggable. Two cases of note are :-
36”/48” MFL Tool for Enbridge
Enbridge operates the world's longest hydrocarbon transmission system. In order to
accommodate future throughput requirements, part of the Enbridge's 1998 Terrace
Expansion Project was designed to connect the 48” pipe sections into a continuous
line with 36” pipe sections.
The ratio of pipeline diameters is the important parameter. Modified standard tools
can be used with small diameter ratios up to 1.15 (e.g. 40-44”, 42-48”). For larger
diameter variation, new pig designs are required. For Enbridge the diameter ratio
was 1.33.
Enbridge challenged two in-line inspection vendors to conduct feasibility studies for
building dual diameter metal loss tools. The initial feasibility discussions on this
project began in January 1998 with PII and the company was eventually selected to
design & manufacture the MFL inspection tool.
PII's task was to design, assemble and test the dual diameter MFL tool and have it
ready to run in three 36/48” sections within a twelve-month timescale. The total
amount of inspection for the dual diameter metal loss MFL tool would be covered
over a 10-year period including the 36” and 48” sections covered in the US.

7. 28”/42” MDPT Tool for Statoil
An even more challenging example of a dual diameter development was the 28/42”
MDPT (Multi Diameter Pipeline Tool) developed for Statoil. The challenge here was to
traverse and inspect around 200m of 28” riser before inspecting 700km of main gas
export line. This presents a very challenging diameter ratio of 1.5.
To accommodate this high diameter ratio, even more ingenious engineering design
was required, effectively producing a tool, which transforms its shape as it moves
between pipe diameters.
SCC Inspection
Cracking, especially in the form of SCC is a major problem for some pipeline
operators. Over the past 10 years or so, in-line inspection for cracking took less
investment than development and improvement of tools to look for metal loss and
third party damage.
The best available tool developed to address the problem of SCC inspection is
without doubt the UltraScan CD tool, Introduced in 1994 its first 1,000 km of field
work was in Europe, Russia and North America, where even in the first 100 field digs
its performance was shown to be excellent. Operation is based on the use of a high-
resolution array of ultrasonic transducers arranged to fire ultrasonic shear waves at
45 degrees to the pipe surface. This dense array of sensors is the key to providing
high resolution with good discrimination during the inspection.
EMATScan
EMAT technology is essentially a means of introducing ultrasound into a pipeline
without the need for liquid coupling. EMAT tools have been tried before for metal
loss inspection, but not with any great degree of success. High power requirements
and low signal levels are some of the difficulties encountered.
One of the very latest developments from PII is a novel form of EMAT tool to inspect
cracking in pipelines. This tool has a target inspection specification similar to the
UltraScan CD tool, but will not need to be run with liquid couplant, making it ideally
suited to operation in gas pipelines.
With all this new technology available to pipeline operators it is essential that
selection and development of appropriate solutions take place. This is where TPI has
evolved from a concept into reality. It takes all the best of breed product technology
The CD tool can reliably detect
cracks 1mm deep x 30mm long
which enables it to find SCC long
before it becomes critical to the
pipeline. The tool is ideally suited
to liquids pipelines. For gas lines it
can be run in a batch of liquid to
provide the necessary coupling of
the ultrasound to the pipewall.

8. available and combines this with the vast experience available within PII Pipeline
Solutions to create a solutions based integrity management programme.
So, What is TPI?
Having seen the background and emergence of PII as a technical and innovative
leader in pipeline integrity, and also looking at the latest trends in pipeline inspection
technology, it still remains unclear exactly what TPI is, and why it is so successful.
As already stated, pipeline operators have a responsibility of care for an operational
pipeline, which involves many factors including, CP, coating status, internal and
external corrosion, cracking, third party damage, subsidence and many others. For
some operators the different aspects of pipeline activities are divided between
departments such as operations and maintenance and are funded from separate
budgets. Although this can give close accountability, it can also lead to inefficiencies
in use of the overall budget due to artificial divisions.
A key feature of the most efficient pipeline operations is the presence of a good
information bank covering all aspects of the pipeline, which in turn, allows the best
decisions to be made on how to spend the limited budget available.
TPI is simply an integrated approach to pipeline integrity, minimising pipeline spend
whilst maintaining the necessary standards for safety and delivery. Inspection is one
of the critical data inputs for this overall management philosophy.
Making Integrity Management Decisions
The easiest illustration of how pipeline operators can make management decisions
on integrity issues using TPI comes from a series of short case histories, which use
varying levels of TPI solutions.
CASE HISTORY ONE
REHABILITATION OF THE 450KM MOMBASA TO NAIROBI
REFINED PRODUCTS PIPELINE
Background
Kenya Pipeline Company (KPC) operates a strategic 450km, 14-inch diameter
pipeline which transports refined products between Mombassa and Nairobi. The
elevation between Mombassa and Nairobi increases by 1600m and there are 4 pump
stations, which are utilised to maintain the required flow rate. The pipeline was
constructed 20 years ago and had never been successfully inspected by intelligent
pig.
The inspection was conducted in two sections; the first section measuring 230km,
and the second section to the receiving terminal at Nairobi. The intelligent pig
inspections identified:
i) 4,139,480 internal corrosion features,
ii) 17,914 external corrosion features,
iii) 293 pipe manufacturing defects (126 internal and 167 external),
iv) 107 dents (68 plain and 39 with associated metal loss), and
v) 251 welded shell repairs

9. The study, which was created as a result of this inspection, also included:
i) an assessment which confirmed that the reported manufacturing defects
had no effect on the integrity of the pipeline
ii) the development of a strategy to ensure the integrity of the pipeline in
relation to the reported dents and repair shells, and
iii) an assessment, which confirmed that the fatigue live of all the defects
reported and any two-dimensional cracks associated with the ERW seam
weld, was acceptable.
ASSESSMENT APPROACH
Initially, the 4 million features were assessed according to ANSI/ASME B31.G, which
indicated that more than 70,000 features required immediate repair. In this situation,
it was more cost effective to replace the pipeline at an estimated cost of $300
million. (fig 1)
CONCLUSIONS
To enable KPC to ensure the integrity of the pipeline and provide the basis for
extending the life of the pipeline, a TPI study was conducted involving intelligent
inspection, fitness-for-purpose assessment, fatigue assessment and a review of
corrosion prevention measures.
Consequently, an alternative strategy was developed involving:
i) 29 immediate repairs,
ii) 490 scheduled (pipeline and high performance coating repairs)
before conducting a re-inspection in February 2001, and
iii) upgrades to the internal and external corrosion monitoring and
prevention measures.
However, B31.G is known to be
conservative and more accurate
methods are now available. PII
conducted a review of these methods,
and concluded that the detailed
RSTRENG (Remaining Strength)
approach was the most appropriate for
assessing the significance of the
corrosion reported in the KPC pipeline.
The detailed RSTRENG method utilised
the ‘actual area’ of corrosion features
and provided a more accurate
prediction of failure pressure than the
B31.G method, which is based on the
overall dimensions of the feature and
an assumption of its profile.

10. The re-inspection would allow for the determination of:
i) the effectiveness of the remedial actions taken, and
ii) the need for and schedule of additional actions.
The above strategy ($3 million) avoided the need for pipeline replacement
($300 million).

11. CASE HISTORY TWO
REHABILITATION OF A MIDDLE EAST 30 INCH ONSHORE CRUDE OIL PLATFORM
BACKGROUND
A 30-inch Middle East onshore crude oil pipeline entered into service in 1958 and
was inspected by PII 1997. The inspection detected internal and external corrosion,
dents, shell repairs and patches.
Consequently, the pipeline was modified for intelligent pigging (for the first time
since entering service). Since the pipeline was operationally critical, passing through
major roads and populated residential and commercial areas and would be required
to operate at the design pressure without corrosion allowance, high resolution MFL
tools were considered most suitable for the comprehensive inspection of the pipeline.
ASSESSMENT APPROACH
The pipeline had never been inspected with pigs prior to the PII operation. PII
therefore ran a gauge vehicle to ensure that no obstructions were present before
conducting the intelligent pig run. The PII inspection vehicle was subsequently
launched and received 19 hours later with 91.7 km of high-resolution inspection
data.
Analysis of the inspection data resulted in the identification of a total of 173084
metal loss features; the majority (114 086) were characteristic of external corrosion,
56 302 were characteristic of internal corrosion and 2 696 were characteristic of pipe
manufacturing defects.
In addition, 131 dents were detected (56 of which were associated with metal loss,
longitudinal or girth welds), together with 15 shell repairs and 8 patch repairs. Fig 2
& Fig 3
Figure 2 Figure 3
CONCLUSIONS
The KOC pipeline contained 114,086 external metal loss features and 56,302 internal
metal loss features.
i) At the MAOP (530 psig, 36.5 bar), approximately 290 features required
investigation, and
ii) At the design pressure (630 psig, 43.4 bar), approximately 3000 features
required investigation.

12. However, based on the LAPA assessment and incorporating a safety factor of 1.39
on the failure pressure:
i) the external corrosion features are all tolerable for operation at MAOP
(530 psig, 36.5 bar) and only 6 are not tolerable at the design pressure
(630 psig, 43.4 bar), see Fig 5, and
ii) the internal corrosion features are all tolerable for operation at both the
MAOP and the design pressure (see Fig 6).
Figure 5 Figure 6
Utilising the LAPA approach described above whilst also ensuring that the peak depth
of any feature would not exceed 80% wall thickness, PII were able to provide KOC
with future repair listing to ensure safe pipeline operation. The assessment was
based on future external and internal corrosion growth rates estimated in
conjunction with KOC. PII recommended repair schedules based on:
i) continued operation at 530 psig (36.5 bar), and
ii) a linear increase in pressure over a five-year period from 530 psig (36.5
bar) to 630 psig (43.4 bar) between the years 2000 and 2005.
Using TPI as a basis for the new schedule of activity, re-inspection intervals were
recommended at which the scheduled numbers of repairs became unrealistic for
both the above cases. Re-inspection of the pipeline would allow the determination
for actual corrosion growth rates which, combined with a further probabilistic FFP
assessment, would be expected to significantly reduce the number of future pipeline
repairs and provide the basis for defining a long-term safe operating strategy.

13. CASE HISTORY THREE
REHABILITATION OF THE PEMEX E&P SOUTHERN REGIONS PIPELINE
BACKGROUND
Pemex E&P (PEP), Southern Region operates 11,780 km of crude oil and gas
transmission pipelines. PEP Southern Region contracted PII to conduct a pilot study
to allow the economic rehabilitation and future maintenance of six pipelines (one or
two from each of the PEP Southern Region Districts), which have been in service for
2 – 36 years. Fig 7
Figure 7
ASSESSMENT APPROACH
To determine the current condition of the six pipelines, intelligent pig inspections
were conducted. PII’s high-resolution magnetic flux leakage (MFL) inspection tool
was used. Following the inspection, a Fitness-for-Purpose assessment was conducted
to determine the effect of the features reported by the inspections on the future
integrity of the pipelines. Fig 5
A Fitness-For-Purpose assessment related the dimensions of any feature detected by
the inspection to the actual pipeline operating conditions. This allowed the
identification of any features, which require immediate repair. It also allowed the
development of a strategy to ensure the long-term integrity.
The inspections reported internal and external corrosion, manufacturing defects;
dents and girth weld anomalies.
The inspections were conducted typically 18 months before the Fitness-For-Purpose
assessments. The first stage of the Fitness-For-Purpose was to estimate maximum
conceivable corrosion rates following the inspection as the basis for estimating the
current dimensions of the corrosion and the need for immediate repairs.
On this basis of 13 (12 external and 1 internal) corrosion features require immediate
investigation to confirm their current dimensions as the basis for a repair decision.
Fig 6
A study was also conducted to prioritise the future maintenance of the six pipelines.
The aim was to identify the greatest damage / defect risk to a pipeline which allowed
the selection of an appropriate maintenance (monitoring / inspection) method to
reduce the risk. An accepted method of determining which maintenance technique
to use on a pipeline is a ‘Prioritisation Scheme’. These types of schemes are
increasingly being used to guide operators on the optimum of maintenance methods.

14. A Prioritisation Scheme considers the probability and consequences of failure within a
group of pipelines (or sections of a single pipeline) by systematically assessing the
pipelines’ design, operation and failure history and allocating points. High points are
awarded to high risk. A Prioritisation Scheme requires customising to each group of
pipelines (or sections of a pipeline). Its advantages are that it can: -
- Rank all pipelines within a group (or sections of a pipeline) in terms of
probability and the consequences of failure,
- Determine which pipeline (or section of a pipeline) is most in need of
some type of maintenance measure, i.e. identify ‘hot-spots of risk, and
- Identify the most appropriate maintenance measure to use.
The proven scheme (ASPIRE – A system for Pipeline Risk Evaluation) was applied to
the sic pipelines after the inspections. The Scheme: -
 Prioritised the six pipelines in terms of total risk
 Identified that the Cunduancan to Dos Bocas is most at risk from
sabotage/pilferage and increased surveillance is recommended,
 Is consistent with historical data,
 Prioritised the six pipelines in terms of corrosion inspection and is consistent
with the findings of the Fitness-For-Purpose assessment and,
 Is supplied in the form of PC software that allows the scheme to be
continuously updated to take account of maintenance.
The scheme is now being used by Pemex E&P Southern Region to plan its future
maintenance activities.
CONCLUSIONS
The study has provided PEP Southern Region with a cost-effective strategy for the
rehabilitation and future operation of the pipelines.
To ensure the longer term integrity individual re-inspection intervals (5-10 years)
have been defined for each pipeline. Before the re-inspections, 32 coating repairs
and 3 pipeline repairs of internal corrosion are required and the timing has been
defined. Following the re-inspections actual corrosion rates should be determined as
the basis for defining further cost-effective rehabilitation.
Finally, the risk assessment has prioritised the six pipelines for future maintenance
activities.
This project has evolved from rehabilitation into a comprehensive TPI project and
illustrates that pipeline operators now have the flexibility to make integrity decisions
and plan pipeline asset management for the long-term.

15. Final Comments
In each of the three case histories, simple rehabilitation was not the answer. All
pipeline operators took a longer-term view and worked with PII Pipeline Solutions to
determine how TPI could be applied. With varying levels of complexity and cost, the
three pipeline operators now have the long-term integrity and safe operation of their
pipelines under control. Integrity management can be achieved at a variety of levels,
and TPI ensures that a suitable level of integrity management is applied depending
on the needs of the pipeline operator.
Using Total Pipeline Integrity as a framework for assessment, rehabilitation and long-
term integrity is the most successful method of integrity management. Scaled
approaches to the rehabilitation of pipelines is the key to successful long term
integrity, and PII Pipeline Solutions have a track record of delivering a tailored
solution to pipeline operators, as shown through its history, its people, its technology
and more recently through its approach to the market.
Illustrations and References
Illustration 1 – Transcan Tool
Illustration 2 – Enbridge Pipeline System
Illustration 3 – 36/42” Dual Diameter Tool
Illustration 4 – Schematic of Ultrascan CD Tool
Figure 1 – KPC Defect Assessment
Figure 2 – Distribution of external corrosion features detected in the pipeline
Figure 3 – Distribution of internal corrosion features detect in the pipeline
Figure 4 – Pemex – Pipeline Details
Figure 5 – MFL Inspection Tool
Figure 6 – Corrosion Features – Pemex Pipelines