Advances in Pipeline Inspection Technologies

John Grover, General Manager, Asia Pacific Region, GE Oil and Gas, PII Pipeline Solutions

IntroductionPipelines are designed to ensure safe operation while achieving a long and profitablelife. However whilst in service, a pipeline will be exposed to operating conditions thatmay not have been anticipated in design, and often impact on the risk of failure ofthe pipeline. Pipelines will deteriorate in service due to corrosion and fatigue.Operating conditions may vary due to change in product composition or tie-ins tonew wells. A pipeline may be exposed to more severe operational loading - increasedinternal pressure and/or temperature, stress/strain induced by bending, externalimpact, etc. A whole host of scenarios can occur which alter dramatically thepotential safe operation of a pipeline.

In order to minimise the potential risk of pipeline failure and the potential economicand environmental consequences, operators have traditionally implemented aprogramme of Inspection and Maintenance. Such a programme would limit the riskof internal corrosion and involve; on-line product monitoring, internal inspectionusing intelligent pigs to detect and monitor corrosion, combined with use of internalinhibitors to control internal corrosion.

Clearly any potential risk to pipeline integrity can be prevented, however theassociated design, construction and maintenance cost may become unacceptable.Early programmes of activity revolved around simple inspection, maintenance andrepair (IMR) programmes. More sophisticated operators looked to Risk BasedInspection (RBI) methodology to focus on areas of higher risk and reduce overallpipeline integrity programmes. These techniques and programmes were affordableand could be implemented over time. However they did not achieve completeintegrity management.

In response to the increasingly demanding needs of pipeline operators across theworld a new class of solution is emerging. PII Pipeline Solutions have pioneered thedevelopment of a fully integrated approach … Total Pipeline Integrity (TPI) solutions.TPI combines affordability combined with technology, methodology and expertise toprovide a long-term solution for operators.

This paper discusses the concept and development of TPI through threeperspectives. Firstly we will look at the historical developments in pipeline inspectiontechnology. Secondly we will assess the variety of inspection tools available andlatest developments in pipeline integrity. Finally through a series of short casehistories, applications of TPI in the rehabilitation of pipelines will illustrate how TPIand inspection advances have enabled pipeline operators to take practical steps indeveloping individual integrity management programmes.

The concept of Total Pipeline Integrity covers all stages in the life of a pipeline, fromdesign through build, commissioning, operation, repair and eventual abandonment.

A Brief History of Pipeline Inspection

In order to appreciate the investment, both financial and technical, put into thedevelopment of inspection systems, it is necessary to look at the major events thathave occurred since the original project began. From these early investments andexpertise PII has emerged as technology leader in pipeline inspection.

In 1974 that British Gas first identified the need for an alternative to the hydrostaticpressure test as a means for periodic revalidation of high-pressure gas pipelines. Online inspection was seen as the most cost effective method of monitoring pipelineintegrity and in the absence of adequate commercially available services, a majorprogramme of research and development was undertaken to seek engineeringsolutions to some specific inspection problems associated with onshore and offshorepipeline.

1970sIn identifying the need for a periodic revalidation of the British Gas pipeline networkusing on line inspection techniques, a project team was established at theEngineering Research Station, part of the British Gas Research & TechnologyDivision. The basic requirements of an on-line inspection system intended for therevalidation 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 costeffective means of providing pipeline inspections.

The first magnetic flux inspection system, a 24" (600mm) diameter, successfully ranin an onshore pipeline in 1977.

1980sFurther systems were designed and manufactured in 12" (300mm) 30" (750mm),and 36" (900mm) diameters. Inspection vehicles began running on a regular basiswithin the British Gas pipeline network enabling corrosion assessments to be carriedout on a line-by-line basis. Running such devices through the system then became aroutine operation and a run prioritisation system was produced to determine thefrequency of inspections based in a number of factors ranging from constructiondetails, coating problems to corrosion findings.

1981First commercial run of an inspection vehicle for a non-BG pipeline operator tookplace in a 24" (600mm) system inspected a 110 km long gas line for Gasunie inHolland. This was a successful operation and provided further stimulus for extendingthe range of vehicle sizes available.

1982Inspection vehicles in sizes 14" (350mm), 16" (400mm), 18" (450mm) and 42"(1050mm) were introduced into service early.

1983The first vehicle to identify stress corrosion cracking in pipelines was produced. Thisvehicle system employed elastic waves of ultrasonic frequency and the inspectiontechnology was produced in 36 " (900mm) diameter.

1987Further research work had been undertaken to produce another pig based inspectionsystem for use in offshore pipelines. The Burial and Coating vehicle was based on aneutron interrogation method, which provides the penetrating power to look throughthe pipe wall into the weight coating and sub-sea surroundings. The vehicle wasproduced in 36" (900mm) diameter and ran in the Morecambe Bay and Rough Fieldoffshore pipelines. Run experience with the systems showed extremely goodcorrelation with traditional offshore survey methods.

1989Magnetic Inspection vehicles covering the range of 6" (150mm) to 48" (1200mm)were available. Work continued on the inspection of pipelines worldwide.

1994The new business unit, Pipeline Integrity International was officially launched.Pipeline Integrity International compromised the core business of pipeline inspectionwhilst 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 pipelineoperator.

1995A second generation of electronics, the 020 system was introduced. The newelectronics were more compact, more reliable, less expensive and increased thepotential 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.

1996The introduction of an internal survey tool based on the magnetic principle. This toolwas able to inspect the inner surface of thickwall pipelines, normally offshorepipelines, and available in the size range 6" (150mm) to 16" (400mm).

1998On February 20th 1998, the sale/purchase of PII was agreed by Mercury AssetManagement. In June a new business plan for the company was launched and astrategic plan for the next five years was agreed. The restructuring of the companywas conducted throughout 1998 and into 1999, to focus the company on customerneeds and provide a market-oriented approach to the business.

Amongst the new products successfully launched in 1998 was the 56” inspection toolfor large diameter pipes.

PII received its first full integrated maintenance contract, awarded in November byPemex. TPI was now in the early stages of development with client focussedcomplex programmes being developed for long-term pipeline integrity.

1999Launch of significant new products including the Elastic Wave 24” and TransverseField Inspection Tool.

In August 1999, the merger of PII and Pipetronix formed the world’s largest singlepipeline integrity company

2000The integration of PII and Pipetronix led to the full development of TPI, as now asingle business could offer a complete range of technologies and solutions includinga mixture of MFL and Ultrasound technologies.

TPI was commercially marketed and a number of long-term framework agreementswere agreed with pipeline operators in North America, Latin America and Europe.

2002PII Pipeline Solutions were acquired by GE Oil and Gas, and became the world’slargest specialist pipeline integrity company. TPI applications, methodology andtechnology is widely available, and pipeline operators work in strategic partnershipwith PII to develop pipeline integrity management plans.

Increasing legislative requirements, and a commitment to development of newproducts is driving the entire pipeline market towards adopting TPI.

New technology remains at the core of PII activities with the launch of EMATscan inthe second half of 2002.

With this background in mind, it is easy to see how PII Pipeline Solutions hasdeveloped TPI, and how the markets leading pipeline operators are adapting thisflexible solution to create integrity management programmes.

Current Techniques

However, the history of a single business does not identify why TPI evolved. Byassessing the range of tools and solutions available, a clearer picture of why TPI isso important emerges. Latest technology in particular has helped with thedevelopment of sophisticated solutions for pipeline operators.

Amongst the most recent technology developments are:

TFI Technology & TranScan ToolsPII developed TFI technology in 1998 in response to a customer’s problem withNAEC (Narrow Axial Extended Corrosion) seen on large diameter tape wrappedpipelines in North America. Illustration 1

Since that time the technology has been refined and incorporated into an expandedrange of TranScan inspection tools.

Conventional MFL technology has poor sensitivity for detecting axial features sincethe magnetic flux flows along the major axis of the defect, which therefore presentslittle profile to disturb the flow. By directing the magnetic flux around the pipe theaxial defects now present a broad profile to the flux and hence a large disturbanceand signal are generated.

The success of this technology has been above expectations and has flushed out arange of latent pipeline problems, which were not generally well known. These haveincluded several instances of quality problems with hook cracks and lack of fusion inearly generations of ERW pipe.

Multi-diameter inspectionMuch of the worlds pipeline infrastructure is currently classified as unpiggable. Forexample, North America has around 1,000,000 km of high-pressure transmissionpipelines. Over 85% of this was constructed before MFL inspection tools werecommercially available, and some 40-50% of the pipeline infrastructure is regardedas unpiggable due to factors such as diameter changes, reduced bore valves etc. Thechallenge for the pipeline integrity industry is to come up with solutions to inspectthese lines at a price, which is commercially attractive compared with the cost ofmodifying the lines to make them piggable.

Many older pipelines were built from pipe of varying diameter. For example, it wasoften the case that transportation costs for pipeline projects were minimised bytransporting 2 diameters of pipe, one inside the other, for example 24” pipe inside26” 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 thesepipelines ‘unpiggable’ using inspection tools.

In the last 2 years significant investment has gone into developing special inspectiontools to make such lines piggable. Two cases of note are :-

36”/48” MFL Tool for EnbridgeEnbridge operates the world's longest hydrocarbon transmission system. In order toaccommodate future throughput requirements, part of the Enbridge's 1998 TerraceExpansion Project was designed to connect the 48” pipe sections into a continuousline with 36” pipe sections.

The ratio of pipeline diameters is the important parameter. Modified standard toolscan be used with small diameter ratios up to 1.15 (e.g. 40-44”, 42-48”). For largerdiameter variation, new pig designs are required. For Enbridge the diameter ratiowas 1.33.

Enbridge challenged two in-line inspection vendors to conduct feasibility studies forbuilding dual diameter metal loss tools. The initial feasibility discussions on thisproject began in January 1998 with PII and the company was eventually selected todesign & manufacture the MFL inspection tool.

PII's task was to design, assemble and test the dual diameter MFL tool and have itready to run in three 36/48” sections within a twelve-month timescale. The totalamount of inspection for the dual diameter metal loss MFL tool would be coveredover a 10-year period including the 36” and 48” sections covered in the US.

28”/42” MDPT Tool for StatoilAn 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 totraverse and inspect around 200m of 28” riser before inspecting 700km of main gasexport line. This presents a very challenging diameter ratio of 1.5.

To accommodate this high diameter ratio, even more ingenious engineering designwas required, effectively producing a tool, which transforms its shape as it movesbetween pipe diameters.

SCC InspectionCracking, especially in the form of SCC is a major problem for some pipelineoperators. Over the past 10 years or so, in-line inspection for cracking took lessinvestment than development and improvement of tools to look for metal loss andthird party damage.

The best available tool developed to address the problem of SCC inspection iswithout doubt the UltraScan CD tool, Introduced in 1994 its first 1,000 km of fieldwork was in Europe, Russia and North America, where even in the first 100 field digsits 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 at45 degrees to the pipe surface. This dense array of sensors is the key to providinghigh resolution with good discrimination during the inspection.

EMATScanEMAT technology is essentially a means of introducing ultrasound into a pipelinewithout the need for liquid coupling. EMAT tools have been tried before for metalloss inspection, but not with any great degree of success. High power requirementsand 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 inspectcracking in pipelines. This tool has a target inspection specification similar to theUltraScan CD tool, but will not need to be run with liquid couplant, making it ideallysuited to operation in gas pipelines.

With all this new technology available to pipeline operators it is essential thatselection and development of appropriate solutions take place. This is where TPI hasevolved from a concept into reality. It takes all the best of breed product technology

The CD tool can reliably detectcracks 1mm deep x 30mm longwhich enables it to find SCC longbefore it becomes critical to thepipeline. The tool is ideally suitedto liquids pipelines. For gas lines itcan be run in a batch of liquid toprovide the necessary coupling ofthe ultrasound to the pipewall.

available and combines this with the vast experience available within PII PipelineSolutions to create a solutions based integrity management programme.

So, What is TPI?Having seen the background and emergence of PII as a technical and innovativeleader in pipeline integrity, and also looking at the latest trends in pipeline inspectiontechnology, 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 operationalpipeline, which involves many factors including, CP, coating status, internal andexternal corrosion, cracking, third party damage, subsidence and many others. Forsome operators the different aspects of pipeline activities are divided betweendepartments such as operations and maintenance and are funded from separatebudgets. Although this can give close accountability, it can also lead to inefficienciesin use of the overall budget due to artificial divisions.

A key feature of the most efficient pipeline operations is the presence of a goodinformation bank covering all aspects of the pipeline, which in turn, allows the bestdecisions to be made on how to spend the limited budget available.

TPI is simply an integrated approach to pipeline integrity, minimising pipeline spendwhilst maintaining the necessary standards for safety and delivery. Inspection is oneof the critical data inputs for this overall management philosophy.

Making Integrity Management DecisionsThe easiest illustration of how pipeline operators can make management decisionson integrity issues using TPI comes from a series of short case histories, which usevarying levels of TPI solutions.

CASE HISTORY ONEREHABILITATION OF THE 450KM MOMBASA TO NAIROBIREFINED PRODUCTS PIPELINE

BackgroundKenya Pipeline Company (KPC) operates a strategic 450km, 14-inch diameterpipeline which transports refined products between Mombassa and Nairobi. Theelevation between Mombassa and Nairobi increases by 1600m and there are 4 pumpstations, which are utilised to maintain the required flow rate. The pipeline wasconstructed 20 years ago and had never been successfully inspected by intelligentpig.

The inspection was conducted in two sections; the first section measuring 230km,and the second section to the receiving terminal at Nairobi. The intelligent piginspections 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), andv) 251 welded shell repairs

The study, which was created as a result of this inspection, also included:

i) an assessment which confirmed that the reported manufacturing defectshad no effect on the integrity of the pipeline

ii) the development of a strategy to ensure the integrity of the pipeline inrelation to the reported dents and repair shells, and

iii) an assessment, which confirmed that the fatigue live of all the defectsreported and any two-dimensional cracks associated with the ERW seamweld, was acceptable.

ASSESSMENT APPROACHInitially, the 4 million features were assessed according to ANSI/ASME B31.G, whichindicated 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 $300million. (fig 1)

CONCLUSIONSTo enable KPC to ensure the integrity of the pipeline and provide the basis forextending the life of the pipeline, a TPI study was conducted involving intelligentinspection, fitness-for-purpose assessment, fatigue assessment and a review ofcorrosion 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, andiii) upgrades to the internal and external corrosion monitoring and

prevention measures.

However, B31.G is known to beconservative and more accuratemethods are now available. PIIconducted a review of these methods,and concluded that the detailedRSTRENG (Remaining Strength)approach was the most appropriate forassessing the significance of thecorrosion reported in the KPC pipeline.

The detailed RSTRENG method utilisedthe ‘actual area’ of corrosion featuresand provided a more accurateprediction of failure pressure than theB31.G method, which is based on theoverall dimensions of the feature andan assumption of its profile.

The re-inspection would allow for the determination of:

i) the effectiveness of the remedial actions taken, andii) the need for and schedule of additional actions.

The above strategy ($3 million) avoided the need for pipeline replacement($300 million).

CASE HISTORY TWOREHABILITATION OF A MIDDLE EAST 30 INCH ONSHORE CRUDE OIL PLATFORM

BACKGROUNDA 30-inch Middle East onshore crude oil pipeline entered into service in 1958 andwas 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 timesince entering service). Since the pipeline was operationally critical, passing throughmajor roads and populated residential and commercial areas and would be requiredto operate at the design pressure without corrosion allowance, high resolution MFLtools were considered most suitable for the comprehensive inspection of the pipeline.

ASSESSMENT APPROACHThe pipeline had never been inspected with pigs prior to the PII operation. PIItherefore ran a gauge vehicle to ensure that no obstructions were present beforeconducting the intelligent pig run. The PII inspection vehicle was subsequentlylaunched and received 19 hours later with 91.7 km of high-resolution inspectiondata.

Analysis of the inspection data resulted in the identification of a total of 173084metal loss features; the majority (114 086) were characteristic of external corrosion,56 302 were characteristic of internal corrosion and 2 696 were characteristic of pipemanufacturing 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

CONCLUSIONSThe KOC pipeline contained 114,086 external metal loss features and 56,302 internalmetal loss features.

i) At the MAOP (530 psig, 36.5 bar), approximately 290 features requiredinvestigation, and

ii) At the design pressure (630 psig, 43.4 bar), approximately 3000 featuresrequired investigation.

However, based on the LAPA assessment and incorporating a safety factor of 1.39on 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 theMAOP and the design pressure (see Fig 6).

Figure 5 Figure 6

Utilising the LAPA approach described above whilst also ensuring that the peak depthof any feature would not exceed 80% wall thickness, PII were able to provide KOCwith future repair listing to ensure safe pipeline operation. The assessment wasbased on future external and internal corrosion growth rates estimated inconjunction with KOC. PII recommended repair schedules based on:

i) continued operation at 530 psig (36.5 bar), andii) 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 wererecommended at which the scheduled numbers of repairs became unrealistic forboth the above cases. Re-inspection of the pipeline would allow the determinationfor actual corrosion growth rates which, combined with a further probabilistic FFPassessment, would be expected to significantly reduce the number of future pipelinerepairs and provide the basis for defining a long-term safe operating strategy.

CASE HISTORY THREEREHABILITATION OF THE PEMEX E&P SOUTHERN REGIONS PIPELINE

BACKGROUNDPemex E&P (PEP), Southern Region operates 11,780 km of crude oil and gastransmission pipelines. PEP Southern Region contracted PII to conduct a pilot studyto allow the economic rehabilitation and future maintenance of six pipelines (one ortwo from each of the PEP Southern Region Districts), which have been in service for2 – 36 years. Fig 7

Figure 7

ASSESSMENT APPROACHTo determine the current condition of the six pipelines, intelligent pig inspectionswere conducted. PII’s high-resolution magnetic flux leakage (MFL) inspection toolwas used. Following the inspection, a Fitness-for-Purpose assessment was conductedto determine the effect of the features reported by the inspections on the futureintegrity of the pipelines. Fig 5

A Fitness-For-Purpose assessment related the dimensions of any feature detected bythe inspection to the actual pipeline operating conditions. This allowed theidentification of any features, which require immediate repair. It also allowed thedevelopment 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-Purposeassessments. The first stage of the Fitness-For-Purpose was to estimate maximumconceivable corrosion rates following the inspection as the basis for estimating thecurrent dimensions of the corrosion and the need for immediate repairs.

On this basis of 13 (12 external and 1 internal) corrosion features require immediateinvestigation 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 allowedthe selection of an appropriate maintenance (monitoring / inspection) method toreduce the risk. An accepted method of determining which maintenance techniqueto use on a pipeline is a ‘Prioritisation Scheme’. These types of schemes areincreasingly being used to guide operators on the optimum of maintenance methods.

A Prioritisation Scheme considers the probability and consequences of failure within agroup of pipelines (or sections of a single pipeline) by systematically assessing thepipelines’ design, operation and failure history and allocating points. High points areawarded to high risk. A Prioritisation Scheme requires customising to each group ofpipelines (or sections of a pipeline). Its advantages are that it can: -

- Rank all pipelines within a group (or sections of a pipeline) in terms ofprobability and the consequences of failure,

- Determine which pipeline (or section of a pipeline) is most in need ofsome 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 tothe 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 futuremaintenance activities.

CONCLUSIONSThe study has provided PEP Southern Region with a cost-effective strategy for therehabilitation 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 repairsand 3 pipeline repairs of internal corrosion are required and the timing has beendefined. Following the re-inspections actual corrosion rates should be determined asthe basis for defining further cost-effective rehabilitation.

Finally, the risk assessment has prioritised the six pipelines for future maintenanceactivities.

This project has evolved from rehabilitation into a comprehensive TPI project andillustrates that pipeline operators now have the flexibility to make integrity decisionsand plan pipeline asset management for the long-term.

Final CommentsIn each of the three case histories, simple rehabilitation was not the answer. Allpipeline operators took a longer-term view and worked with PII Pipeline Solutions todetermine how TPI could be applied. With varying levels of complexity and cost, thethree pipeline operators now have the long-term integrity and safe operation of theirpipelines under control. Integrity management can be achieved at a variety of levels,and TPI ensures that a suitable level of integrity management is applied dependingon 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. Scaledapproaches to the rehabilitation of pipelines is the key to successful long termintegrity, and PII Pipeline Solutions have a track record of delivering a tailoredsolution to pipeline operators, as shown through its history, its people, its technologyand more recently through its approach to the market.

Illustrations and References

Illustration 1 – Transcan ToolIllustration 2 – Enbridge Pipeline SystemIllustration 3 – 36/42” Dual Diameter ToolIllustration 4 – Schematic of Ultrascan CD Tool

Figure 1 – KPC Defect Assessment

Figure 2 – Distribution of external corrosion features detected in the pipelineFigure 3 – Distribution of internal corrosion features detect in the pipelineFigure 4 – Pemex – Pipeline DetailsFigure 5 – MFL Inspection ToolFigure 6 – Corrosion Features – Pemex Pipelines