tr-35100 - in line non destructive inspection of pipelines

Item No. 24211NACE International Publication 35100

This Technical Committee Report has been preparedby NACE International Task Group 039* onIn-Line Nondestructive Inspection of Pipelines

In-Line Nondestructive Inspection of Pipelines

© December 2000, NACE International

This NACE International technical committee report represents a consensus of those individualmembers who have reviewed this document, its scope, and provisions. Its acceptance does not inany respect preclude anyone from manufacturing, marketing, purchasing, or using products,processes, or procedures not included in this report. Nothing contained in this NACE Internationalreport is to be construed as granting any right, by implication or otherwise, to manufacture, sell, oruse in connection with any method, apparatus, or product covered by Letters Patent, or asindemnifying or protecting anyone against liability for infringement of Letters Patent. This reportshould in no way be interpreted as a restriction on the use of better procedures or materials notdiscussed herein. Neither is this report intended to apply in all cases relating to the subject.Unpredictable circumstances may negate the usefulness of this report in specific instances. NACEInternational assumes no responsibility for the interpretation or use of this report by other parties.

Users of this NACE International report are responsible for reviewing appropriate health, safety,environmental, and regulatory documents and for determining their applicability in relation to thisreport prior to its use. This NACE International report may not necessarily address all potential healthand safety problems or environmental hazards associated with the use of materials, equipment,and/or operations detailed or referred to within this report. Users of this NACE International reportare also responsible for establishing appropriate health, safety, and environmental protectionpractices, in consultation with appropriate regulatory authorities if necessary, to achieve compliancewith any existing applicable regulatory requirements prior to the use of this report.

CAUTIONARY NOTICE: The user is cautioned to obtain the latest edition of this report. NACEInternational reports are subject to periodic review, and may be revised or withdrawn at any timewithout prior notice. NACE reports are automatically withdrawn if more than 10 years old.Purchasers of NACE International reports may receive current information on all NACE Internationalpublications by contacting the NACE International Membership Services Department, 1440 SouthCreek Dr., Houston, Texas 77084-4906 (telephone +1[281]228-6200).

Foreword

In-line nondestructive inspection is an important tool in theinvestigation of the condition of a pipeline. It is a significantpart of pipeline integrity management and, as such,establishes a quality integrity management program andpromotes safe, efficient, and cost-effective pipelineoperation. In-line inspection (ILI) tools, popularly called“intelligent” or “smart” pigs, are devices designed to surveythe condition of the pipeline wall without disrupting theoperation of the pipeline. Pigs are inserted into the pipelineand travel through it, driven by the pipeline product. Theiroperation is based on technologies of nondestructiveevaluation (NDE) (a more general term than nondestructivetesting [NDT]).

The purpose of this technical committee report is to analyzeavailable and emerging technologies in the field of in-linepipeline inspection tools and review their status with respectto characteristics, performance, range of application,and limitations. It is intended as a practical referencefor both new and experienced users of ILI technology.

It is aimed at assisting in the provision of an understandingof the practical aspects of using the tools, highlighting theimplications, and helping assess the benefits.

The section titled “Types of In-Line Inspection Tools”provides a brief explanation of available technologies andtools. The procedures and rationale behind decisionsleading to the use of in-line inspection tools and theassociated cost and benefits are discussed in the sectionstitled “Decision Making Process” and “Cost/Benefit.” Theprocedures related to inspections are discussed in“Operational Issues,” and finally, the sections titled “Resultsof ILI” and “Data Management” deal with the outcome anduse of results of in-line inspection. A glossary of termscommonly used in the in-line nondestructive inspection ofpipelines is included in Appendix A. A list of abbreviationsand acronyms commonly used in the industry is given inAppendix B. Appendices C, D, and E provide genericspecifications of tools and lists of activities connected toperforming in-line inspections.

___________________________* Chairman Neb I. Uzelac, PII, Toronto, Ontario, Canada.

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This NACE technical committee report was prepared byTask Group 039 (formerly T-10E-6) on In-LineNondestructive Inspection of Pipelines, which isadministratively sponsored by Specific Technology Group

35 on Pipelines, Tanks, and Well Casings. This report isissued by NACE International under the auspices ofSpecific Technology Group 35.

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Table of Contents

Introduction .................................................................................................................... 3Types of In-Line Inspection Tools ................................................................................... 3

Metal Loss/Gain Detection Tools................................................................................. 3Crack Detection Tools................................................................................................. 4Geometry Tools .......................................................................................................... 6Mapping Tools ............................................................................................................ 6Auxiliary Developments............................................................................................... 6

Decision-Making Process ............................................................................................... 7Motivation ................................................................................................................... 7Goals .......................................................................................................................... 7Risks........................................................................................................................... 8Other .......................................................................................................................... 8

Cost/Benefit ................................................................................................................... 8Operational Issues ......................................................................................................... 9

Piggability of Pipelines ................................................................................................ 9Preparation of the Inspection..................................................................................... 11Inspection Procedures............................................................................................... 12Verification Dig.......................................................................................................... 13

Results of ILI ................................................................................................................ 13Standard-Resolution MFL Tools ................................................................................ 13High-Resolution MFL Tools ....................................................................................... 14Ultrasonic Metal-Loss Detection Tools....................................................................... 14Assessment of Anomalies ......................................................................................... 14Reporting Requirements ........................................................................................... 14

Data Management........................................................................................................ 15References................................................................................................................... 16Bibliography ................................................................................................................. 17Appendices ............................................................................................................. 21-34

A: Glossary of Terms ................................................................................................ 21B: Acronyms ............................................................................................................. 26C: Typical Specifications (Tables C1 to C7)............................................................... 27D: Preparing for an Inspection................................................................................... 34E: Launching and Receiving Procedures ................................................................... 34


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Introduction

Since introduction in the late 1960s, ILI tools have mainlybeen used to inspect the wall of the pipe for corrosion(metal loss). ILI tools have also become available forperforming other tasks, such as the following:

• Crack Detection• Geometry Measurement• Leak Detection• Temperature and Pressure Recording• Bend Measurement• Product Sampling• Wax Deposition Measurement• Curvature Monitoring• Pipeline Profile – Mapping• Photographic Inspection• Strain Analysis

The increased use of ILI technology reflects theimprovement of the technology. Pipeline defect detectionhas improved in terms of the variety of anomalies detected,increased accuracy of detection, and reliablecharacterization of anomalies. The increased reliability ofILI, the introduction of pipeline integrity management

programs by many pipeline operators, and increasedregulatory involvement is expected to push the technologydevelopment and use of ILI tools still further.

Besides the development of technologies addressingdifferent types of defects, operational challenges have led todevelopment of dual-diameter ILI tools (collapsible pigs),i.e., tools that can pass through pipelines with two differentdiameters, inspecting both pipelines. Another addition to ILItools that has become available is speed control, the abilityto bypass flow and establish inspection speeds at muchlower speeds than the flow of product. In addition, some ofthe tools are available as tethered tools, typically forinspecting shorter pipeline sections and sections withoutflow.

None of the above-mentioned tools and applied NDEtechnologies is universally applicable. The pipeline operatorand the ILI service company jointly choose the proper ILItechnology, and match the performance of the tool to therequested defect specifications.

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Types of In-Line Inspection Tools

Metal Loss/Gain Detection Tools

There are two principal methods for detection of metal lossin pipe walls: the magnetic flux leakage (MFL) method andthe ultrasonic testing (UT) method. MFL was the firstmethod developed and has been the most widely used. Athird method, called eddy current, has been developed, butis used only to detect defects on the inside of the pipe wall.Each method has its own particular strengths andlimitations.1-4

Magnetic Flux Leakage (MFL) Tools

The basic principles of magnetic flux leakage arestraightforward.5 MFL tools induce an axially orientedmagnetic flux into the pipe wall between two poles of amagnet. A homogeneous steel wall without defectscreates an undisturbed and uniform distribution ofmagnetic flux. Metal loss or gain associated with thesteel wall causes a change in the distribution of the fluxwhich, in a magnetically saturated pipe wall, “leaks” outof the pipe wall. Sensors detect and measure thisleakage field and hence detect the metal loss. Themagnitude and shape of the measured leakage field isused to characterize the size and shape of the regionof metal loss. The leakage signals are passed throughsophisticated microprocessors, and the resulting dataare stored for detailed computer analysis andsubsequent reporting.

General Performance Characteristics

• Indirect measurement, which allows limitedquantification using complex interpretationtechniques;

• With additional sensors, discriminatesbetween internal and external defects;

• Maximum wall thickness is limited due tomagnetic saturation requirement;

• Signal depends on length-to-width ratio ofdefects; limited ability on narrow axialanomalies;

• Results may be affected by pipe steelcharacteristics and history;

• Results may be affected by stress in pipe wall;• Performance is not affected by the medium

present in the pipeline—suitable for both gasand liquid pipelines;

• Moderate pipeline cleaning required(compared to ultrasonic tools); and

• Tools available for pipelines 3 in. (8 cm) andgreater in diameter.

Types of Detectable Features

• External metal loss;• Internal metal loss;• Welds: girth welds, longitudinal welds, spiral

welds, coil welds, and thermite welds (ifferromagnetic material present in the weld);

• Hard spots;


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• Cold working• Dents;• Bends;• T-piece;• Flange;• Valves;• Casings;• Location magnets;• Steel sleeves;• Clamps;• Patches;• Spalling (if metal loss associated); and• Near-wall excess metal.

MFL ILI tools are commonly classified into categories ofstandard-resolution (SR) (also called low orconventional resolution), high-resolution (HR), andextra-high-resolution tools. The differences betweenthese categories are the number, size, and orientationof MFL sensors, magnetic circuit design andmagnetization levels, and the type of analysis that isapplied to recorded data supplied by each type ofinstrument. All three types of tools use magnets toinduce a magnetic field into the pipe wall, and eitherinductive search coils or solid-state (Hall-effect)sensors to detect flux leakage. Standard-resolutiontools have fewer MFL sensors (inductive coil sensors)for a given pipe size than do high- or extra-high-resolution tools. Each of these sensors covers a largerpart of the circumference of the pipe and gives anaverage of the flux leakage distribution in the area thatit covers. The much smaller and more advanced Hallsensors (used on HR tools) can examine a smallerarea of the pipe wall and reveal more detailedinformation. Therefore, HR tools provide a much bettercharacterization of anomalies in the pipeline.3,6

Accordingly, the amount of data is greater and the dataprocessing procedures more sophisticated. Tables C1,C2, and C3 of Appendix C provide more detailedinformation about the specifications of the three maintypes of ILI tools.

Ultrasonic Testing (UT) Tools

UT inspection tools directly measure the pipe wallthickness as the ILI tool travels through the pipeline.1, 2

They are equipped with transducers that emit ultrasonicsignals perpendicular to the surface of the pipe. Anecho is received from both the internal and externalsurfaces of the pipe and, by timing these return signalsand comparing them to the speed of ultrasound inpipe steel, the wall thickness can be determined.Transducers are deployed in a carrier to cover thecircumference of the pipe wall uniformly. Typicalspecifications for ultrasonic inspection tools are given inTable C4 of Appendix C.

For efficient transmission of sound from the ultrasonictransducer to the pipe wall and back, ultrasonicinspection procedures typically employ a liquid to

“couple” the transducer to the pipe wall. Many liquidsusually transported through pipelines providesufficiently good coupling for UT. In gases, however,because of a mismatch in acoustic properties of steeland gas that lead to difficulties in delivering enoughacoustic energy into the pipe wall, ultrasonicinspections are not possible without an additionalcouplant. Gas pipeline inspections can be performedby utilizing the UT tool in a slug of liquid (e.g., water,diesel oil, etc.) between batching pigs.7


• Direct and linear wall thickness measurementmethodallows reliable depth sizing;

• Can discriminate between internal, midwall,and external defects;

• Sensitive to a larger number of features thanMFL;

• No upper limits to inspectable pipe-wallthickness;

• Minimum wall thickness limitthe remainingthickness of pipe wall that is too thin cannotbe measured because of the finite duration ofthe ultrasonic pulse;

• Does not depend on changes in materialproperties;

• Only runs in homogeneous liquids (in a batchof homogeneous liquid in gas pipelines—see“Operational Issues” for further details);

• Generally, UT tools require a higher degree ofcleanliness of the pipeline than the MFL tools;

• The accuracy of the data, especially thedefect depth and length, leads to veryaccurate maximum allowable operatingpressure (MAOP) calculation results;

• Interpretation of results is easilycomprehensible because it deals with directlymeasured wall thickness; and

• Minimum size of tools available is 6 in. (15cm) up.


• External metal loss;• Internal metal loss;• Welds: girth weld, longitudinal weld, spiral

weld, coil weld;• Dents, deformations;• Bends: field bend, forged bend, hot bend;• Welded attachments and sleeves (features

under a sleeve are also detected);• T-pieces;• Flanges;• Valves;• Laminations;• Sloping laminations;• Hydrogen-induced cracking (HIC) and

induced laminations;• Blisters;


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• Inclusions;• Longitudinal channeling; and• Wall thickness variations of seamless pipe.

Crack Detection Tools

Crack detection has become an increasingly importantissue in the pipeline industry because of occurrences ofcrack-like defects (e.g., stress corrosion cracking [SCC],fatigue cracks, longitudinal seam weld imperfections, etc.)8

that cause leaks and ruptures on operating pipelines.Generally, the NDE technique that allows for the mostreliable in-line detection of crack-like defects is ultrasonictesting (UT). Because most crack-like defects (fatiguecracks as well as SCC) are perpendicular to the main stresscomponent (i.e., the hoop stress in a pipe), the ultrasonicpulses are injected in a circumferential direction to obtainmaximum acoustic response.

Liquid-Coupled Tools

Liquid-coupled tools utilize shear waves generated inthe pipe wall by angular transmission of the ultrasonicpulses through a liquid coupling medium (oil, water,etc.).9 The angle of incidence is adjusted such that apropagation angle of 45° is obtained in pipeline steel.This technique is appropriate for crack inspection, andit is established as one of the standard techniques inultrasonic testing.9 Typical specifications for liquid-coupled tools are given in Table C5 of Appendix C.


• Can only be operated in liquid environments;• Gas pipelines can be inspected running the

tool in a slug of liquid;7

• Full pipe body coverage—no exclusion zones;• Capable of defect-type discrimination;• Capable of discriminating between internal,

mid-wall, and external defects; and• Actual wall thickness measured.


Longitudinally oriented cracks and crack-likedefects:

Cracks:• Stress corrosion cracks (SCC)• Fatigue cracks• Toe cracks

Crack-like defects:• Notches• Grooves• Scratches• Lack of fusion• Longitudinal weld irregularities

Geometry-related features:• Welds• Dents

Installations:• Valves• T-pieces• Welded attachments

Mid-wall defects:• Inclusions• Laminations

Wheel-Coupled Tools

These tools utilize shear waves injected into the pipewall at an angle of 65º using liquid-filled wheels astransducers. Typical specifications for wheel-coupledtools are provided in Table C6 of Appendix C.


• Operation in gas or liquid;• Internal and external discrimination not

available; and• Tools with a diameter smaller than 20 in. (51

cm) are currently not available.

Electromagnetic Acoustic Transducer (EMAT)Tools

The electromagnetic acoustic transducer (EMAT)consists of a coil in a magnetic field at the internalsurface of the pipe wall. Alternating current (AC)placed through the coil induces a current in the pipewall, causing Lorentz forces (force acting on movingcharges in magnetic fields), which in turn generateultrasound. The type and the configuration of thetransducer used define the types and modes ofgenerated ultrasound and the characteristics of itspropagation through the pipe wall.

• Application of EMATs for use in ILI tools is stillin the development phase; and

• EMATs do not need a coupling medium—readily applicable in gas pipelines.

Other Methods

Other methods that have been developed for crackdetection in pipelines include:

Circumferential MFL Tools

Typical specifications for circumferentialmagnetization tools are given in Table C7,Appendix C.

These tools magnetize the pipe wallcircumferentially. Most cracks are very tight andtherefore do not alter the propagation of magnetic

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flux sufficiently to enable reliable detection. On theother hand, stress concentration associated withcracks changes the magnetic properties of pipesteel and thus changes the propagation ofmagnetic flux, which, in turn, causes increasedprobability of detection. Experiments with toolsutilizing circumferential magnetization havedetected cracks and lack of fusion in the longseam weld in live pipelines and SCC in pull-through tests.10


• Operation in liquid and gas pipelines;• No internal/external defect discrimination;

and• Capable of detecting metal loss.

Eddy Current Tools

This method can be used to inspect internal cracksonly due to limited through-wall penetration ofeddy currents.

Geometry Tools

Geometry tools (sometimes referred to as caliper pigs)utilize either mechanical arms or electromagnetic methodsto measure the bore of the pipe, look for dents, other ovalitychanges, and deformations, and sense girth welds and wallthickness changes. In some configurations, they can alsomeasure bends in pipelines.

The applications for which the geometry tools are usuallyused include:

• In acceptance stages of new pipelines to detect dentinginduced during backfill;

• Monitoring the bore of pipelines to detect mechanical orthird-party damage;

• Checking to see that there are no restrictions in thepipeline prior to running heavier and moresophisticated ILI tools; and

• If equipped, for pipeline bend measurements.


• Operate readily in both gas and liquid pipelines;• Provide full pipeline coverage; and• Tolerate moderate debris in pipelines.

Mapping Tools

The operation of mapping tools is based on inertialnavigation using built-in gyroscopes and accelerometers.The data acquired are X, Y, Z angular change and X, Y, Zvelocity change.

The tool can be used for:

• Creating pipeline log books;• Verification of existing pipeline log books;• Determination of local ground movement or any

changes in pipeline geometry;• Bend measurements;• Direct feed into geographic information system (GIS)-

based databases for data layering; and• Locating dig sites correlated to inspection data.

General Characteristics

• Establishes absolute coordinates;• Accuracy of the established absolute coordinates

depends on the accuracy of the reference pointpositions and the coordinate spacing;

• Superimposing inspection results withgeographical data and aerial (satellite) imagespossible;

• Base for combining data with results of other ILIand pipeline data into databases; and

• Absolute coordinates given as longitude, latitude,and altitude, or easting, northing, and elevation.

Specifications

Horizontal positioning accuracy:

0.05% of the distance traveled from the referencepoint e.g., at 1 km (0.62 mi.) from reference point,horizontal position accuracy is +/- 0.50 m ( 164 ft);and

Vertical positioning accuracy:

0.09% of the distance traveled.

Auxiliary Developments

Some ILI tools are available as tethered tools, typically forinspecting shorter pipeline sections. The tools areconnected to a control unit via an umbilical or pulled bytethered cable trucks from either end and, therefore, areused off-line. Because they are tethered, they typicallyoperate at speeds much lower than the conventional on-lineILI tools (approximately 1.5 mph [0.67 m/s, 132 ft/min]).Operational challenges have led to the development ofspecialty ILI tools that are designed for a specific inspectiontask. For example, dual-diameter ILI tools (also calledcollapsible pigs) have been developed. These tools canpass through pipelines containing different diameters andperform inspection of both sections.

Another development in ILI technology is the “speedcontrol.” Most ILI tools have a maximum effective speed ofinspection, usually lower than the speed of fluid beingpumped through the pipeline. Tools with the ability tobypass flow (mostly in gas pipelines) and equipped withspeed control units achieve more stable inspection runs andallow for higher-speed flows (greater throughputs).


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Decision-Making Process

Motivation

When integrity verification of a pipeline system, or a portionthereof, is desired, a descriptive, reproducible, andtrustworthy method or process is generally used.Sometimes a pipeline integrity management system andlife-cycle operation plan facilitate this process.11

One method of checking system integrity is the hydrostatictest. This test provides assurance that the pipeline canwithhold a certain internal pressure. This type ofexamination provides no further information about the actualcondition of the pipe and the defects that can still exist andcould continue to grow with time.

In-Line Inspection (ILI) is one pipeline integrity managementtool used to identify and quantify the risk of corrosion andcracking failure modes. ILI provides the location andcharacteristics of pipeline anomalies in such an effectivemanner as to enable the operator to address the anomaliesbased on priority and to mitigate pipeline failures. Further,the information provided by ILI tools allows for futuremaintenance programs to be developed with regard toeconomic considerations.

Risk Analysis-Based Considerations

ILI data, with their quantitative information and locationaccuracy, allow for informative comparisons to cathodicprotection, environmental facts, pipe specification,class location information, and other pertinent data toprioritize maintenance schedules. Growth of corrosionis also often considered to determine potential risk.

Reviewing the Effectiveness of Corrosion ControlPrograms

ILI can guide maintenance activities of corrosion controlprograms by evaluating the effectiveness of cathodicprotection along the pipe. Shielded areas as well asregions of low potential can be highlighted by thepresence and density of corrosion features. In thenewer fusion-bond epoxy-coated lines, in whichextremes in applied potential have blistered anddisbonded the coating, ILI can detect existing corrosionat those locations. The ILI information is often used bythe operator as an evaluation of the effectiveness of thecorrosion control program.

Assessing the Suitability for Continued Operationat Existing or Higher Operating Pressures

ILI is used to justify maximum safe operating pressuresallowable.12 Prior to any such justification, a siteexcavation program is often considered to provideconfidence in the ILI information. Raising the MAOPalso considers other factors, such as operatingstresses in class locations.

Operating Experience on Pipe with SimilarCharacteristics

Comparative analyses of ILI data can be made on pipehaving similar characteristics, such as pipespecifications, coating, environmental conditions, andoperating history. Such analyses could provide insightinto the condition of uninspected comparable lines.

Proactive Maintenance

Maintenance programs are often scheduled based onthe information provided by ILI. Excavations areprioritized over a period of time to mitigate anomalieseconomically. Subsequent ILIs of the same pipefacilitate the estimate of corrosion growth on a feature-by-feature basis. This can refine the maintenanceschedule as well as help determine re-inspectionfrequency.13, 14

Goals

When the use of ILI is being considered, certain definableinformation is often sought, whether it is for SCC detection,cracking, or general and/or pitting corrosion. The followingparameters have been defined in the section titled “Types ofIn-Line Inspection Tools” and are highlighted here.

Detection

Features that ILI can detect include, but are not limitedto:

• General and pitting corrosion;• Cracking;• SCC;• Mid-wall defects such as stringers and laminations;• Hard spots;• Mechanical damage;• Weld defects;• Ovalities; and• Long-seam weld defects.

Location

The location of corrosion anomalies, pipeline features(e.g., tees, valves, etc.), and various other features canbe accurately defined. Currently, two methods aretypically employed to identify the location of thefeatures from the ILI tool data.

The first and older method uses odometer wheels thatelectronically “count” the distance traveled by the tool.Typically, more than one odometer wheel is used toprovide redundancy and to preclude slippageproblems. To correct for slippage, abovegroundmarkers (AGM) are placed at appropriate intervalsalong the inspection section (the closer the spacing, thegreater the accuracy in defining a location). The


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passage of the ILI tool is identified and recorded by theAGM. A correction is made by relating the odometerwheel reading to the surveyed AGM position.

The more recently developed method of tracking thetool location is through the use of inertial units asdescribed in the section dealing with mapping tools.Running mapping tools before or after an ILI run allowsfor subsequent correlation that leads to locating the ILIdata with submeter accuracy.

Measurement

The performance characteristics for each type of toolare noted in the section titled “Types of In-LineInspection Tools.” The data measured accurately andwith confidence are the feature depth, length,orientation, and location.

Sometimes, the characterization does not end with theactual defining of individual pits or cracks. Someengineering judgement is often applied to the results toform a more accurate representation of the degree towhich the corrosion affects the integrity of the pipeline.Interaction rules and assessment criteria aredeveloped.

Discrimination

ILI methods are able to discriminate various anomalies,the characteristics of which depend on the type of toolemployed. Examples of such anomalies are:

• Metal loss, pitting, or grind marks,• Cracking, actual cracks, or laminations, and• Corrosion or mill/construction damage.

Monitoring Frequency

ILI offers the pipeline operator the ability to definespecific maintenance at discrete locations to repaircorrosion that is, or could become, an integrity concern.By applying growth rates to identified corrosionfeatures, one could plan the maintenance scheduleover a period of time. There could come a point whena re-inspection is performed, either to define growthrates accurately or to address economic considerations

(planned excavations cost more than the cost ofanother inspection). Multiple inspections allow for amore accurate determination of growth rates on a per-feature basis14 and contribute to the development of amaintenance plan. A risk-based inspection (RBI)approach is sometimes used to define inspectionfrequency.11,13

Risks

Obstacles in the pipeline can cause damage to the ILI tools,resulting in failed runs or even causing the tool to get stuckin the pipeline.

Some obstacles that typically affect the risk of damageinclude:

• Bends – ILI tools have a minimum bend radius that canbe negotiated;

• Valves – diameters that could restrict the passage of atool;

• Hot taps – abrupt transition can cause tool damage;• Loose or missing scraper bars;• Line cleanliness – gritty sludge can cause excessive

tool wear;• Dent, buckles – can cause the tools to get stuck; and• High temperatures and hostile environments.

Operating procedures and conditions, such as corrosiveelements in the fluid stream, high dissolved gasconcentrations in a liquid stream, prolonged no-flowconditions, etc., can also present risks to successfulinspections.

Other

Residual pipe magnetization from MFL tools could be aconcern, because the flux density and applied field strengthin subsequent MFL inspections could be affected. Pipeweldability could be hampered, and metallic debris couldaccumulate at isolation joints.

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Cost/Benefit

A clear understanding of ILI technology, its applications,limitations, and a realistic expectation of the data analysisare key components in any cost/benefit analysis.

Some basic factors that are usually considered include:

Cost

ILI Tool – The type of tool and level of analysis usedcan have a significant impact on cost. ILI costs canvary depending on the level of accuracy desired. Less

expensive tools typically provide less quality andquantity of information. A higher-cost tool typicallyprovides more detailed information. These decisionsare obviously driven by the goal of the inspection.

Cost of Preparing the Pipeline – The cost ofmodification to make a line piggable could beprohibitive. Thus, identification of such requirementsare a key component of the analysis. The cost analysisis often not limited to dollars spent on manpower and


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equipment but, when possible, also considers itemssuch as flow restriction and interruption of service.

Operational – Operational issues could make aninspection cost prohibitive as well. For example, theuse of an ultrasonic tool in a gas line requires eitherfilling the line with liquid or the use of a liquid slug,which can prove to be unacceptable.

Contracting – Contracting for ILI work is usually asignificant effort. The roles of the vendor andowner/operator are typically defined for all aspects ofthe work, from implementation to delivery of the finalreport. The various stages of reporting and paymentschedules associated with milestones are often laidout. Factors such as the implications of re-runs,scheduling changes, and service interruptions areusually addressed.

Verification and Rehabilitation – The verification of ILIdata and pipeline rehabilitation are key portions of thecost analysis. Acceptable repair methods, associatedcosts, and impact to product flow are usually identified.Costs associated with planned interruptions of serviceto do repairs versus not completing an inspection andpossibly dealing with an in-service failure are usuallyconsidered.

Benefits

Determine/Monitor the Condition of the Pipeline – ILIprovides a solid basis from which to decide whether it issafe to continue operating the pipeline. If it is not safe,it allows the operator to quantify the cost of safeoperation. The information can also provide a basis forlong-term planning by modeling corrosion growth.Similarly, improved prevention efforts can be scheduledso as to reduce or eliminate future costs associatedwith repairs.

Pipeline Integrity − ILI can allow the operator to ensurethat the integrity of the line is verified to address anyconcerns stemming from various sources such as thepublic, regulatory agencies, or lack of good records.

Risk Assessment – ILI provides the operator moreinformation from which to complete a risk assessment,because the data can provide the number, severity,and density of anomaly information.

Making the Pipeline Piggable – Once the pipeline hasbeen made piggable, subsequent inspection operationsnormally proceed on a regular basis for minimal cost.This has also allowed more regular use of cleaningpigs, which can reduce costs associated with fouling orinternal corrosion.

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Operational Issues

Piggability of Pipelines

Various factors are usually considered when determiningthe piggability of a pipeline. In general, these can bedivided into physical restrictions and operational issues.

Physical Restrictions

Physical restrictions to pigging a pipeline can include,but are not limited to, items such as:

Inadequate Launchers/Receivers – Considerationsinclude sufficient land availability, adequate barrellength, adequate clearance for loading andunloading tools, appropriately sized kicker line,accessibility to facilities, and condition of existingfacilities.

Internal Diameter Changes (i.e., buckles, dents,bore restrictions, reduced port valves, checkvalves) – Internal diameter changes can bepresent in the line for many different reasons andare usually addressed prior to the internalinspection. Sometimes the tool is able to negotiatethese types of restrictions, but each situation isconsidered on a case-by-case basis. Reducedport valves can result in tool damage, and inextreme cases, can result in the tool becominglodged in the line. Step transitions between wall-thickness sections of pipe can also pose a threat

by presenting a sharp cutting edge. Temperature,pressure, ultrasonic, and other types of probesintruding into the pipeline can present a restrictionto inspection tools. Neglecting to remove themcan damage the facilities and the tools.Typically, ILI vendors are alerted if line wallthickness is less than 6.4 mm (0.25 in.) or greaterthan 1.3 cm (0.50 in.). Some tools are calibratedfor specific wall-thickness ranges.

Tee Connections (Barred/Unbarred) – Branchconnections (30% of the pipe diameter or greater)are usually checked for bars. Hot taps, alsoidentified as sharp edges, could present a hazardto the tools. Also, to avoid tool damage, flowthrough the tees is sometimes shut down,regardless of diameter, when the inspection toolpasses. This sometimes leads to the installation ofadditional feeds to sales taps/receipt points thathave a single connection to the line beinginspected.


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Short Bend Radii – The majority of inspection toolsare capable of negotiating a 3 D(1) bend radius orgreater. Any bends that are tighter are addressedon a case-by-case basis depending on the tool tobe used and the wall thickness of the bend. Anincreasing number of tools are capable of passinga 1.5 D bend radius.

Installations – Installations, such as mainline dripswithout orifice plates (gas lines), pressure “pots”(crude lines), vortex breakers, chill rings, y-branchconnections, and miter bends, can also presentproblems for in-line inspection tools.

Pipeline Operational Issues

Pipeline operational issues that are usually consideredinclude:

Type of Fluid (Gas, Liquid) – The type of fluid is aconsideration for several reasons. Liquid linestypically operate at low enough speeds that in-lineinspection does not result in a throughputrestriction. Liquid lines are ideal for ultrasonictools, because the product itself provides thecoupling between the tool sensors and the pipewall. This is not the case for gas lines, in whichthe product actually acts as a barrier to theultrasonic signals. Thus, in gas lines ultrasonictools are run in a liquid slug that complicates theimplementation of inspections. Gas lines presentan additional hurdle, because they often operate atspeeds well in excess of the maximum allowablein-line inspection speeds. Variable bypass (speedcontrol), available on certain tools, can be used toaddress this issue, but this usually results in amuch more complicated procedure and often stillrestricts the capacity of the line.Some pipeline products could damage a tool.Sour service is an example in which failure toinform the ILI contractor could result in costlyrepair to the tool. Any chemical other than oil orgas is typically reported to the vendor for toolsuitability verification.

Downtime, Tool Run Time, Tool Speed – Thescheduling of any inspection is usually coordinatedto ensure that capacity restrictions, batching (incase of liquid lines), etc., are coordinated withcustomers and other concerned parties. A liquidproducts pipeline operator may not be willing toaccept the risk of product contamination byrunning an ILI tool in certain critical batches, e.g.,aviation fuel. Line conditions are typically set upsuch that the tool speed is maintained in theoptimal range for data collection.

Speed Control—Reduction – This is primarily aconsideration for magnetic flux tools in gas lines.This feature is currently available in tools that are61 cm (24 in.) or more in diameter. The use of thisfeature could require a more complicatedprocedure, lengthening of the tool, and limits thebend capability of tools. The use of this tool andits ramifications are usually considered. In somecases, “fixed bypass” is put into a tool to reducethe inspection speed and keep debris “loose” andcirculating. The addition of fixed bypass is donewith caution. In certain situations, the addition oftoo much “fixed bypass” could result in insufficientdrive to move the tool along the line.

Speed Control—Liquid Lines – This is aconsideration for the inspection of low-flow liquidlines using an MFL tool equipped with inductioncoils (not an issue with Hall-effect sensors). Thenormal pipeline flow is sometimes supplementedwith additional product to achieve the minimumrequired inspection velocity.

Availability of Manpower and Equipment – Thespeed of the tool and the length of the run are theprimary considerations in determining manpowernumbers. Manpower is used for loading,launching, and receiving the tool. In addition,manpower is used for tracking, monitoring, andoperating valves during the inspection. Manpowerin the pipeline operation control center is alsoconsidered, because outages and procedures caninvolve more coordination of effort than issupported at normal staffing levels.

Procedure to Assess Piggability

The procedure usually followed to assess the piggability ofa pipeline has several aspects. As-built drawings are oftenreviewed to identify physical restrictions. If the informationis inadequate, this typically identifies a need to run gaugingor caliper pigs. As a part of this process a pipelinequestionnaire, typically provided by the vendor, is usuallycompleted. Cleaning specifications are usually discussedwith the vendor. If there is no cleaning history available forthe pipeline, a suitability assessment can be made aftereach progressive cleaning run is completed. In olderinstallations, gathering of anecdotal information at the fieldlevel can be an additional source of information regardingthe piggability of a pipeline.

___________________________(1) D = pipeline diameter.


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Preparation of the Inspection

Proper timing usually minimizes the impact of the inspectionon normal operations. The pipeline operator and theservice-providing company cooperate in the planning stagesand preparation of the pipeline, and both parties review allrelevant information.

Key activities that are typically scheduled in preparation foran inspection are included in Appendix D.

Equipment, Personnel, Transportation, andWorkshop Facilities

Identification of resources up front is normally a part ofthe exercise. This not only includes resources for anypipeline modifications, but also resources neededduring the run itself. For personnel, the speed and thelength of the inspection determine the number of shiftsof manpower for the duration of the run. Manpoweraccommodations for loading, launching, tracking, andreceiving are typically reviewed. The level of staffing issometimes affected by considerations such as remoteaccess, access during daylight hours, and probability ofencountering wildlife. In some areas, helicopter accessor all-terrain vehicle access is the only option fortracking. Access for heavier equipment (crane orpicker truck) is often considered for launcher andreceiver sites as well as nearby workshop and tool-cleaning facilities for the vendor.

Pipeline Preparation, Pipeline Modifications,Cleaning of Pipeline, Checking of Bore and Bends,Checking Suitability of Launchers/Receivers,Checking Valves

Pipeline modifications to facilitate cleaning, gauging,electronic caliper, and in-line inspection of the systemare typically designed, fabricated, and installed toconform to the specifications of ILI tools available forthe inspection. The launcher/receiver facilities and anyother modifications could be either a temporary or apermanent installation. Any restrictions identified in theplanning stage are normally rectified or confirmed withthe vendor as not posing a risk to the inspection tool.Particular attention is typically paid to existing bendradii for in-line inspection tool passage and the type ofvalves existing on the pipeline system. In addition, allvalves that could be used are serviced and confirmedto be fully functioning.

Cleaning and Gauging

When warranted, a cleaning program for the pipeline isdesigned. The specific pigs for cleaning the pipeline areidentified. Historical data are evaluated for anticipatedcontaminate deposits such as scale, dust, paraffin, etc.The results of current maintenance pigging activities inthe pipeline aid in the cleaning program design.

A gauge plate/bend plate pig is sometimes run todetermine worst-case restrictions present in thepipeline.

The pipeline is cleaned to the satisfaction of the ILIvendor prior to initiating the in-line inspection.

Caliper or Bend Tools

A caliper or bend tool is normally run in the pipelineprior to a metal-loss ILI. The purpose of this inspectionis to provide detailed data to prove the pipeline bore(internal diameter) or to evaluate the bend radii toensure passage of the metal-loss tool. Benchmarkingor tracking could be used during the caliper/bendinspection. Some caliper/bend tools are available withpipeline mapping capabilities.

If pipeline bend and bore information is current andreliable, a gauging plate pig or “dummy tool” can beused instead.

A response plan to the caliper/bend data is oftendeveloped to deal with potential restrictions that couldbe discovered.

Dummy Tool Run

Sometimes a dummy tool run is performed prior to alive inspection run. The dummy tool is designed tomimic the characteristics of the live tool. The purposeof the dummy run is to train field personnel in the safeand proper handling and operation of the live tool. Adummy run could improve the likelihood that the liverun will be successful.

Benchmarking: Preparing Aboveground LocationReference Points

Surveying/Benchmarking

Benchmarks are discrete survey points along thepipeline route for placing reference markers.These markers are either permanently attached tothe pipeline (magnets, for example) or portableaboveground marker systems (AGM). Readilyidentifiable permanent pipeline installations, suchas valves, are sometimes used as benchmarks. IfAGM is used, special care is normally taken toensure that the pipeline cover does not exceed themaximum allowable for the AGM at the benchmarklocations. If an AGM is placed on or above acasing, it often does not detect the passage of theILI tool.

The purpose of benchmarking is to correct formeasured distance inaccuracies caused by ILI toolodometer wheel slippage and significant changesin topographic elevations along the pipeline route.Benchmark locations on the pipeline are usuallyspaced at certain minimum intervals. Closer


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spacing provides a more accurate locationdefinition. Benchmarking also provides referencepoints for tracking the ILI tool as it progressesthrough the pipeline and references for use insurveying for verification or pipe inspectionexcavations. Benchmarks are typically placed ineasily accessible locations on the pipeline route.

Benchmark documentation consists of:

• Vehicle accessibility (map or sketch of how toget to the location);

• Drive time (in minutes) between benchmark(AGM) locations,

• Parties to be contacted (landowners,agencies, etc.) prior to going to thebenchmark;

• Distance and method used to find and set thebenchmark point;

• Notes showing establishment of thebenchmark location;

• Pipeline station number of the benchmarkpoint;

• Identification number of the benchmark point;• Name of the benchmark point;• Milepost of the benchmark point;• Global positioning system (GPS) latitude;• GPS longitude; and• GPS elevation.

Contingency Plans for Operational Problems

A contingency plan is sometimes put in place to dealwith the possibility of lodging an inspection tool in theline. The plan typically covers aspects such as lines ofcommunication, operational actions that could be usedto dislodge the tool, interruption of service, and removalof the tool by means of a cutout. The contingency planwould also consider the possibility of a failure of the run(either due to the tool or line conditions) and whether are-run would be possible.

Inspection Procedures

Mobilization

Mobilization of tools and manpower sufficiently inadvance of the run date provides the vendor enoughtime for tool preparation and commissioning. It alsoprovides operator and tracking crews sufficient time forpreparation.

Launching/Receiving

General Preparation

• Safety equipment such as fire extinguishers, gasdetection meter (in jargon, explosive meter is alsoused), absorbent pads, silencers for blowing downthe barrel on gas lines, environmental kits,

nitrogen to purge receiver barrel, etc., are often onsite at both launch and receive stations inadvance.

• Safe operational procedures are used for theopening/venting of launchers and receivers.These are pressure vessels and pose a safetyhazard if not properly tested prior to opening.

• Exact timing of the ILI tool launch is coordinatedwith the operations control center.

• Care is taken to contain all products.• The proper size tools and equipment for use in the

loading and unloading of the ILI tool are on site inadvance.

• If utilized, all pig indicators on the pipeline sectionhave been reset and are ready to identify thepassage of the ILI tool.

Typical launching and receiving procedures areincluded in Appendix E.

Monitoring and Establishing Proper FlowConditions

Any procedure developed for running an inspection tooltypically addresses not only the loading, launching, andreceiving procedures, but also any operational and flowconditions that could occur during the run. Specificmilestones and any activities associated with themilestones are detailed. Also, all personnel involvedusually have an understanding of the toolrequirements, the product flow, the ramifications of anyvalve movements, changes in compression/pumpingconfigurations, etc.

Tool Tracking

Each tracking crew typically consists of:

• An adequate number of individuals trained in theuse of pig tracking equipment, trackingcalculations, line finding equipment, etc.

• An adequate number of vehicles suitable for theright-of-way being traveled.

• Equipment capable of facilitating real-timecommunications at any time during the trackingactivities.

• Adequate number of sets of working acoustic pigtracking equipment.

When an electronic transmitter is used for trackingpurposes, the proper mounting and operation of thedevice is normally ensured prior to launch.

Typically, the pipeline operations control center isupdated at the following times:

• When the tool is ready for launch.• When the tool has been launched and tracking is

under way.• Any time irregularities are noted in the flow or pig

travel.

ohn Grapiglia - Invoice INV-294898-902F1C, downloaded on 1/12/2010 11:10:41 PM - Single-user license only, copying and networking prohibited.

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• In advance of scheduled changes in pipeline flowconditions as identified in the inspectionprocedure.

• Every three hours to confirm the pig position andthat the tracking personnel are not incapacitated.

• Several times in advance of the pig arriving at anyintermediate booster station, pig signal, orreceiving location.

• When the pig has been received, and the pipelinecan be returned to normal operation.

Tracking locations are usually established downstreamfrom pipeline appurtenances or intermediate boosterstations to ensure the pig negotiates and clears allin-line facilities.

Post-Run Data Assessment

For established technologies, the vendor is able toreport within 24 to 48 hours whether an inspection runwas successful and valid data were collected. Thisreport is typically provided prior to demobilizing.

Verification Dig

Upon completion of an ILI, several anomalies reported bythe inspection tool are usually visually investigated. Thepurpose of these verification digs is to assess the accuracyof reporting and attempt to correlate actual versus reportedconditions. Sometimes the inspection vendor performs are-grade of the data based on the verification diginformation.

Selection of Sites

Selections of anomalies to be inspected for verificationare typically based on several factors. A cross-sectionof reported anomaly depths, lengths, and orientationsis one factor. Inspection of anomalies in areas of loweraccuracy confidence, such as near girth welds or

casing ends, is another. Sites are typically selected forease of access, unless there is another prevailingconsideration, such as a potential threat to thecontinued safe operation of the pipeline.

Establishing Correlation with the ILI Report

Special effort is usually made to ensure that the correctlocation is found for each verification dig. This processis often facilitated by the use of dig sheets provided bythe inspection contractor. Several measurements frompipeline benchmarks, both upstream and downstreamfrom the location, could be involved. The location ofseveral pipe girth welds in the vicinity of the anomalylocation is usually verified to confirm that the properpipe joint has been excavated.

Anomalies inspected in the verification dig program areusually documented by defect type, axial length, depthprofile or maximum depth, circumferential width,orientation (often referred to as o’clock position), andrelative distance from pipe girth welds. A grid systemplaced over the defect can aid in the measurement ofdefect geometry. The appropriate anomaly interactionrules established for the ILI are often considered inperforming the measurements.

Evaluation of Examined Defects

A “unity graph” of reported vs. actual anomalygeometry provides a visual aid in assessing theaccuracy of the reported data. Consistent majordeviations from the established tool tolerances areusually reported back to the inspection vendor.

Those assessing the verification data consider thestated tool tolerances and the applicable interactionrules in evaluating the accuracy of the reported data.

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Results of ILI

Because there are a variety of ILI tools, the kind of resultsobtained from inspection varies greatly. However, thehighest volume of inspection is being performed using thetools detecting metal loss (corrosion).

As pointed out in the section titled “Metal Loss/GainDetection Tools,” the accuracy and interpretation of the dataobtained from the inspections using those tools aredifferent.

Standard-Resolution MFL Tools

Standard-resolution MFL tools monitor the levels ofmagnetic flux leakage using wide sensors, the size andquality of which depend on the tool size.

For accuracy of detection see Table C1 in Appendix C:Typical Specifications for Standard ILI Tools.

Standard resolution surveys are a time-proven, relativelyinexpensive inspection method for surveys in which high-resolution technology is not desired. Standard resolutionsurveys provide length and depth measurements of bothisolated and clustered anomalies. The survey tools retain allsignals detected. No data filters or on-board processing areused to eliminate “below threshold” signals. This isespecially valuable when extended lengths of interactive,low-level corrosion occur. The printed survey recordpresents 100% of the recorded data even when indicationsare too low for formal interpretation.

Field Playback

A field playback unit produces an initial printout of thesurvey record. Inspection results are typically reviewedwith the pipeline operator within 24 hours of the survey.One initial field log is typically provided to the operator


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immediately after the run. Maintenance projects areoccasionally initiated based on these results. A fullyinterpreted survey is generally delivered to the client 30to 45 days after the inspection.

Data gathered by these tools can be used in prioritizingthe number and order of repairs through the use ofclustering of defects and application to various industrycodes.

High-Resolution MFL Tools

High-resolution MFL technology differs significantly fromstandard-resolution surveys in that it offers much moreaccurate detection and allows more sophisticated codeassessment techniques (see Table C2: TypicalSpecifications for High-Resolution ILI Tools).

The analog signal of each sensor is digitally sampled andstored. The high sampling rate allows accurateinterpretation of depths and lengths of pipeline anomalies.

The width of sensors provides the enhanced anomalyresolution. The higher definition allows more accuratedetermination of adjacent anomaly separation.

As a visual aid to the data analyst, each anomaly can berepresented in a color-coded C-scan display. This viewprovides a detailed graphic of the magnetic flux pattern,which is closely associated with the dimensions of theanomaly. Valuable features contained in the tool and C-scan software package aid interpretation of high-resolutiondata.

Internal/external discrimination is provided. This providesmaintenance crews an idea of which corrosion indicationscan be visually identified upon excavation. Externalindications are commonly due to construction damage,protective coating disbondment, cathodic protection failure,or mill-related anomalies. Internal indications tend to becaused by chemical damage from the pipeline product,recent changes in pipeline product, sulfate-reducingbacteria, pipeline debris, laminar flow conditions, ormill/construction-related anomalies.

Experienced analysts review the inspection data throughautomated computer processes as well as additionaldetailed manual analysis. Computer algorithms are used tointerpret the digital data and create a spreadsheet offindings. Qualified analysts correlate the computer analysisto the inspection data gathered by the tool and makeadjustments based on various analysis procedures.

High-resolution software, reporting parameters,internal/external discrimination, and B- and C-scan typeviews assist in providing very high quality data to thepipeline industry. Presentation of all survey data oncomputer screens has eliminated the bulk of surveyprintouts. High-resolution technology is a dependable, cost-effective way to determine the condition of pipelines indensely populated and environmentally sensitive areas.

The data gathered through the use of these high-resolutiontools are used in the pipeline industry to prioritizemaintenance in areas of possible defect interaction. Defectinteraction is generally described as the potential forclustered pipe wall loss to weaken pipe strength as severelyas a single large defect. The importance of interactionassessment has been a driving force behind thedevelopment of high-resolution data sampling rates andsensor dimensions.

The accuracy of detection allows for MAOP calculations.

Ultrasonic Metal-Loss Detection Tools

The ultrasonic tools actually measure the wall thicknesswith a high resolution and accuracy (see Table C4: TypicalSpecifications for Ultrasonic Testing Tools).

As opposed to interpretation of MFL data, which is aninferential method, ultrasonic inspection is based on actuallymeasuring the wall thickness and the interpretation of datais more straightforward.

The results are stored in digital form and proprietarysoftware is made available with C-scans and B-scans forinterpreting and visualizing the data. In addition, becausethe data are a result of a direct and linear measurement ofthe wall thickness, river-bottom profiles of anomalies withthe resolution set by number of available sensors and thesampling frequency can be created.

A reliable discrimination between internal and externalanomalies is given. The method also reliably detectsmidwall anomalies (e.g., inclusions and laminations). This,in addition to the availability of anomaly profiles, allows theusage of the most advanced defect assessment algorithms.

Assessment of Anomalies

Many pipeline operators request an assessment of theinspection data ranking anomalies according to somegeometric criteria, such as maximum depth and length.Anomalies are also often prioritized based on their relativeseverity.

The assessment of the results from an in-line inspectiontypically include:

• An analysis into the cause of the detected flaws andthe associated degradation rate.

• A calculation of the allowable operating pressure underwhich the pipeline containing detected anomalies canbe safely operated.

• An analysis of integrity improvement requirements bydegradation mitigating or repair.

For an assessment to be meaningful, an appropriateassessment code is typically used. The more sophisticatedassessment codes achieve the most useful results inconjunction with accurate and precise data, which means


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that a tool capable of delivering this kind of data is used.Some of the assessment codes used for allowableoperating pressure calculations are listed in Appendix A.

Reporting Requirements

In an attempt to standardize the operational and reportingrequirements for MFL and ultrasonic ILI tools, the EuropeanPipeline Operators Forum (POF)(2) has initiated a documentcalled “Specifications and Requirements for Intelligent PigInspection of Pipelines.”15

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Data Management

Effectiveness of ongoing risk assessment and maintenanceprograms relies strongly on the use of available informationand on monitoring conditions over a period of time.

A substantial amount of inspection and monitoring data iscollected over a pipeline’s life. Examples of such data arecathodic protection station checks, close interval potentialsurveys, intelligent pigging results, pipeline coatinginspections, etc. These data may reside within variousdepartments and considerable effort can be involved tocollect, collate, and arrange these data in a format thatallows ready comparison against acceptable values.

The number of data points is large, especially with theapplication of a risk-based assessment (RBI) system, andthe pipeline register, inspection and monitoring data, andintegrity data can be stored in an electronic database. Thisgreatly simplifies the comparison of measured valuesagainst design values during pipeline integrity assessment.

High-resolution ILI tools produce vast amounts of relevantdata that are not only stored but also efficiently used andcross-referenced to other available ILI and non-ILI data.The ILI vendors provide databases specifically developedfor storage and management of ILI data, with the followingfeatures:

• Specialized database for management of ILI data;• Capacity for storing ILI data in such a system is

enormous even using only PCs;• All relevant information can be stored in the database;• Pipeline features, e.g., welds, tees, bends, installations,

etc.;• Data from different types of ILI tools;• Subsequent runs with same tools;• Other relevant information – from sources other than

ILI (cathodic protection, coating, excavations,geographical information, etc.);

• Rehabilitation and repair information, updating thedatabase by entering changes; and

• GIS-based to allow combining with survey data (e.g.,from a mapping tool), maps of the terrain, and aerialphotographs.

Advantages of Using a Data Management System

• Vast amounts of ILI and non-ILI information can bestored;

• Keeping track of changes and updating referencepoints is made very easy;

• Data from different tools can be easily cross-referenced (e.g., a pipe containing a crack can inaddition be corroded or dented, which wouldincrease the severity of the crack);

• Combining ILI with non-ILI data (e.g., corrosion ina river crossing, or close to high power cables);

• Sorting and filtering – searching for data (e.g., listall corrosion defects with depths >40% in class 1locations);

• Importing documents, photographs, videos,drawings, etc., allows user-friendly visualization oflocations of anomalies (displays of aerial picturesof terrain with superimposed maps and drawn inpipeline with depicted selected defects); and

• Integration of defect assessment (MAOP) modulesallows sorting and prioritizing anomalies based onthe MAOP calculations;

• Prioritizing of anomalies based on combinedinformation (e.g., a corrosion spot in a specificclass location and in conjunction with a gouge);and

• Compatibility with other data managementsystems.

___________________________(2) Pipeline Operator Forum, c/o Shell International Exploration and Production BV, EPT-OM, P.O. Box 60, 2280 AB Rijswijk, Netherlands.


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References

1. H.J.M. Jansen, W.H. van den Berg, B. Kuilman, “AComparison Between Magnetic-Flux Leakage andUltrasonic Techniques for Corrosion Detection in Pipelines,”Proc. of the Pipeline Pigging and Inspection TechnologyConf., held February 17-20, 1992 (Houston, TX: PipelineIndustry and Pipes and Pipelines International,(3) 1992).

2. P.M. Hoyt, “A Comparison of Ultrasonic and DivertedMagnetic-Flux Pipeline Inspection Technologies,” Proc. ofthe Pipeline Pigging and Inspection Technology Conf., heldFebruary 17-20, 1992 (Houston, TX: Pipeline Industry andPipes and Pipelines International, 1992).

3. A. Teitsma, “Pipeline Inspection by Intelligent HighResolution and Conventional Magnetic Flux Leakage Pigs,”Int. Conf. on Pipeline Reliability, paper no. IV-6-1 (Houston,TX: Gulf Publishing Co.,(4) 1992).

4. A. Crouch, R. Anglisano, M. Jaarah, “Quantitative FieldEvaluation of Magnetic-Flux Leakage and Ultrasonic In-LineInspection,” Proc. of the Pipeline Pigging Conf., heldFebruary 14-16, 1996 (Houston, TX: Pipeline Industry andPipes and Pipelines International, 1996).

5. A. Bubenik, J.B. Nestleroth, R.J. Eiber, B.F. Saffel,“Magnetic-Flux (MFL) Technology for Natural Gas PipelineInspection,” Gas Technology Institute (GTI)(5) TopicalReport, GTI-91/0367, November 1992.

6. K. Plaizier, “Which Smart Pig Do I Chose? AComparison of MFL Technologies from an Operator’sViewpoint,” Proc. of the Pipeline Pigging and InspectionTechnology Conf., held February 1-4, 1993 (Houston, TX:Pipeline Industry and Pipes and Pipelines International,1993).

7. Arkenburg, J.B., and M. Lewis. “Ultrasonic BatchingTechnology for Gas Pipelines.” Proc. of the PipelinePigging Conf., held February 13-16, 1995. Houston, TX:Pipes and Pipelines International, 1995.

8. “Public Inquiry Concerning Stress Corrosion Crackingon Canadian Oil and Gas Pipelines,” National Energy Boardof Canada,(6) Report of the Inquiry, MH-2-95, November1996.

9. J. Krautkrämer, H. Krautkrämer, Ultrasonic Testing ofMaterials, 4th fully revised ed. (New York, NY: SpringerVerlag,(7) 1990).

10. P. Mundell, K. Grimes, “Field Tests Demonstrate TFIDetects Long Seam Weld Defects,” Pipeline and GasIndustry 83, 6 (June1999): pp. 33-36.

11. H.J.M. Jansen, B.F.M. Pots, C.W.M. Voermans, “ShellPipeline Risk-Based Inspection in Aging Pipelines,” Proc. ofMeche Conf., held October 11-13, 1999 (Newcastle, UK:IMeche C571/029, 1999), p. 131.

12. B. Melan, “High-Resolution MFL Reinspection: Confir-mation of Established Operating Integrity,” Proc. of thePipeline Pigging Conf., held February 13-16, 1995(Houston, TX: Pipeline Industry and Pipes and PipelinesInternational, 1995).

13. P.H. Vieth, S.W. Rust, B.P. Ashworth, “Use of In-LineInspection Data for Integrity Management,”CORROSION/99, paper no. 541 (Houston, TX: NACE,1999).

14. W.H. Brown, “Using ILI Pigs to Establish PipelineCorrosion Rates – Case Histories,” CORROSION/99,paper no. 523 (Houston, TX: NACE, 1999).

15. Work in Progress by the Pipeline Operator Forum,“Specifications and Requirements for Intelligent PigInspection of Pipelines” (Rijswijk, Netherlands: POF).

16. ASME(8) B 31G (latest revision), “Manual forDetermining the Remaining Strength of Corroded Pipelines:A Supplement to ASME B 31 Code for Pressure Piping”(New York, NY: ASME).

17. U.S. Code of Federal Regulations (CFR) Title 49,“Transportation,” Part 192 (Washington, DC: Office of theFederal Register,(9) 1999).

18. P.H. Vieth, J.F. Kiefner, “RSTRENG2 User’s Manual,”American Gas Association, Pipeline Research Committee,Project Report, PR-218-9205, Catalog No. L51688, March31, 1993.

19. J.F. Kiefner, P.H. Vieth, “A Modified Criterion forEvaluating the Remaining Strength of Corroded Pipe,”American Gas Association, Pipeline Research Committee,Project Report AGA-PR-3-805, Catalog No. l51609,December 22, 1989.

20. H.J.M. Jansen, P.B.J. van de Camp, M. Geerdink,“Magnetization as a Key Parameter of Magnetic-FluxLeakage Pigs for Pipeline Inspection,” Insight 36, 9 (1994):pp. 672-677.

___________________________(3) Pipes & Pipelines International (PPI), P.O. Box 21, Beaconsfield Bucks, HP9 1NS, UK.(4) Gulf Publishing, 3301 Allen Parkway, Houston, TX 77019.(5) Gas Technology Institute (GTI) (formerly Gas Research Institute [GRI]), 8600 W Bryn Mawr Ave, Chicago, IL 60631.(6) National Energy Board , 444 Seventh Avenue SW, Calgary, Alberta, Canada T2P 0X8.(7) Springer-Verlag New York, Inc., 175 Fifth Avenue, New York, NY 10010.(8) ASME International, Three Park Ave., New York, NY 10016-5990.(9) Office of the Federal Register, National Archives and Records Administration, 700 Pennsylvania Ave. NW, Washington, DC 20408-0001.


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Bibliography

General

Barbian, O.A., et al. “Advances in Pipeline IntegrityAssessment Using In-Line Inspection Tools.” 4th Int.Conf. and Exhibition on Pipeline Pigging and InspectionTechnology, paper no. II 20. Houston, TX: GulfPublishing Co., 1992.

Beller, M., H. Goedecke, and J. Burris. “New Developmentsand Technologies in the On-Line Inspection ofPipelines,” Proc. of the Pipeline Week Conf., heldSeptember 8-12, 1997. Houston, TX: Gulf PublishingCompany and Pipe Line and Gas Industry, 1997.

Cordell, J.L. “An Introduction to Conventional and IntelligentPigging.” Proc. of the Pipeline Pigging Conf., heldFebruary 13-16, 1995. Houston, TX: Pipes andPipelines International, 1995.

Crouch, A.E. “In-Line Inspection of Natural Gas Pipelines.”GTI Topical Report GTI-91/0365, May 1993.

Harle, J.C. Corrosion Inspection of the Trans-AlaskaPipeline, Conference on Pipeline Pigging Technology,held February 4-7, 1991. Houston, TX: Gulf PublishingCo., 1991

Harle, J.C., Corrosion Inspection of the Trans AlaskaPipeline , Conference on Pipeline Pigging Technology,held February 14-16, 1996. Houston, TX: GulfPublishing Co., 1996.

Jansen, H.J.M., and M.M. Festen. “Intelligent PiggingDevelopments for Metal Loss and Crack Detection.”Insight 37, 6 (1995): pp. 421-425.

Posakony, J., and V.L. Hill. “Assuring the Integrity ofNatural Gas Transmission Pipelines.” GTI TopicalReport GTI-91/0366, November 1992.

Shamblin, T. “Intelligent Pig Inspection, Evaluation andRemediation of Uncoated Seamless Pipelines.”CORROSION/99, paper no. 539. Houston, TX:NACE, 1999.

Stirling, D.G. “Evaluation of Coating Condition Using theElastic Wave Pig.” GTI Final Report GTI-97/0073.March 1997.

Uzelac, N.I. “In-Line Inspection of Gas TransmissionPipelines.” Hart’s Pipeline Digest Focus Series 35, 2(1998): pp. 35-40.

Uzelac, N.I. “In-Line Inspection of Gas TransmissionPipelines.” Proc. of the Pipeline Pigging Conf., heldFebruary 2-4, 1999. Houston, TX: Clarion TechnicalConferences and Pipes and Pipelines International,1999.

Vieth, P.H., et al. “Alyeska Program Allows Pig PerformanceComparison.” Oil & Gas Journal, 95, 6 (1997): pp. 52-59.

Magnetic Flux Leakage

Atherton, D.L., R. Barnes, R.M. Donaldson, T.W. Krause,and R. Little. “Effects of Line Pressure Stress,Magnetic Properties and Test Conditions on MagneticFlux Leakage Signals.” GTI Annual Report GTI-94/0221. July 1994.

Atherton, D.L., C. Hauge, T.W. Krause, A. Pattantyus, R.M.Donaldson, and R. Barnes. “Effects of Line PressureStress, Magnetic Properties and Test Conditions onMagnetic Flux Leakage Signals.” GTI Annual ReportGTI-95/0180. May 1995.

Atherton, D.L., K. Mandal, C. Hauge, T.W. Krause, D.Dufour, P. Weyman, D. Micke, B. Sijgers, and L.Clapham. “Effects of Line Pressure Stress, MagneticProperties and Test Conditions on Magnetic FluxLeakage Signals.” GTI Annual Report GTI-96/0197.May 1996.

Bubenik, T.A., J.B. Nestleroth, R.J. Eiber, and B.F. Saffell.“MFL Technology for Natural Gas Pipeline Inspection.”GTI Topical Report GTI-91/0367. November 1992.

Crouch, A.E., R.E. Beissner, G.L Burkhardt, E.A. Creek,T.S. Grant, and F.A. Bruton. “MFL Inspection of GasPipelines: The Effects of Biaxial Stress.” GTI TopicalReport GTI-95/0484. March 1996.

Mitchell, J.L. “Smart Pigs Getting Smarter to MeetOperators Demands.” Pipe Line and Gas Industry 79,6 (1996): pp. 37-43.

Nestleroth, J.B., and R.J. Davis. “Magnetic-Flux LeakageInspection of Gas Pipelines: The Effects of RemnantMagnetization.” GTI Topical Report GTI-95/0006. April1995.

Nestleroth, J.B., and R.J. Davis. “The Effects of Velocity onMagnetic-Flux Leakage Inspection of Gas Pipelines.”GTI Topical Report GTI-95/0008. June 1996.

“New Generation Inspection Tool Developed for GasSystem Zeepipe.” Pipe Line and Gas Industry 78, 10Staff Report (1995): pp. 52-53.

Schmidt, J.T. “Magnetic Flux Leakage Inspection ofPipelines – An Operator's Viewpoint.” MP 33, 7 (1994):p. 53-57.

Schmidt, J.T. “Magnetic Flux Leakage Technology forNatural Gas Pipelines – An Operator's Viewpoint.”CORROSION/93, paper no. 584. Houston, TX: NACE,1993.


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Scrivner, R.W. “MFL Inspection of Gas Pipelines:Experience with a Collapsible Tool.” GTI Final ReportGTI-96/0223. July 1996.

Shamblin, T. “Columbia Gas Steps up Annual MFL LineInspection Program.” Pipe Line and Gas Industry 79, 6(1996): pp. 23-27.

Siebert, M., and J. Sutherland. “Application of theCircumferential Component of Magnetic-Flux LeakageMeasurement for In-Line Inspection of Pipelines.”CORROSION/99, paper no. 540. Houston, TX:NACE, 1999.

Ultrasonic Corrosion Inspection

Goedecke, H. “Ultrasonic Corrosion Surveys - What YouGet and What You Don’t Get.” Pipes and PipelinesInternational January-February (1996): pp 5-17.

Kondo, M., M. Kobayashi, and M. Kurashima. “UltrasonicCorrosion Inspection of Crude Oil Pipeline.”CORROSION/99, paper no. 525. Houston, TX:NACE, 1999.

Myers, J., and A. Ackert. “Ultrasonic In-Line Tools Used toInspect 30-in. Natural Gas Line.” Pipe Line and GasIndustry 80, 8 (1997): pp. 41-45.

Crack Detection

Addison, R.C., Jr., and A.D.W. McKie. “Non-DestructiveMethods for Inspection of Gas Pipes in Gas PipingSystems.” GTI Annual Report GTI-94/0452.November 1994.

Addison, R.C., Jr., A.D.W. McKie, and A. Safaeinili. “Non-Destructive Methods for Inspection of Gas Pipes in GasPiping Systems.” GTI Annual Report GTI-95/0477.November 1995.

Atherton, D. L., W. Czura, B.J. Mergelas, and X. Guo.“Remote Field Eddy Current Defect Interaction.” GTIAnnual Report GTI-93/0458. December 1993.

Atherton, D. L., L. Clapham, W. Czura, and B.J. Mergelas.“Remote Field Eddy Current Defect Interaction.” GTIAnnual Report GTI-94/0451. December 1994.

Atherton, D.L., L. Clapham, W. Czura, B.J. Mergelas, S.Smith, J. Winslow, and Y. Zhang. “Remote Field EddyCurrent Defect Interaction.” GTI Final Report GTRI-95/0506. December 1995.

Bubenik, T.A., D.R. Stephens, B.N. Leis, and R.J. Eiber.“Stress Corrosion Cracks In Pipelines: Characteristicsand Detection Considerations.” GTI Topical ReportGTI-95/0007. April 1995.

Crouch, A.E., C.M Teller, J.L. Fisher, G.M. Light, and C.M.Fortunko. “Assessment of Technology for Detection ofStress Corrosion Cracking in Gas Pipelines.” GTI FinalReport GTI-94/0145. April 1994.

Culbertson, D.L., and C.E. Whitney. “Field Evaluation of theBritish Gas Elastic-Wave Vehicle for Detecting StressCorrosion Cracking in Natural Gas TransmissionPipelines.” GTI Final Report GTI-91/0241. July 1995.

Khoroshih, A.V., H.H. Willems, O.A. Barbian, Y.P. Surkov,and V.G. Rybalko. “Inspection of Trunk Gas PipelinesSubject to External Stress Corrosion Cracking.”Defektoskopija, 5, 29 (1997): pp. 3-13.

Marreck, P., B. Martens, R. Krishnamurthy, and N.L. Tozer.“Mobil Oil’s Experience with In-Line Detection andCharacterization of SCC.” Proc. of the Pipeline PiggingConf., held February 2-4, 1999. Houston, TX: ClarionTechnical Conferences and Pipes and PipelinesInternational, 1999.

Mundell, P., and K. Grimes. “A New Breed of Intelligent Pigfor the Detection of Defects in the Long Seam Weld ofSteel Pipelines.” Insight 41, 2 (1999): pp. 75-79.

“Stress Corrosion Cracking.” Canadian Energy PipelineAssociation (CEPA),(10) Recommended Practices,1997.

Sourkov, Y.P., and A.V. Khoroshih. “Investigation of Casesof Corrosion Cracking in Operating Gas Pipelines.” 3RInternational 35, 7 (1996).

Uzelac, N.I., H.H. Willems, and O.A. Barbian. “In-LineInspection Tools for Crack Detection in Gas and LiquidPipelines.” CORROSION/98, paper no. 88. Houston,TX: NACE, 1998.

Weischedel, H.R. “Novel Electromagnetic Method for the In-Line Inspection of Gas Pipelines: Proof-of ConceptExperiments.” GTI Final Report GTI-96/0063. February1996.

___________________________(10) Canadian Energy Pipeline Association (CEPA), 1650, 801 6th Avenue SW, Calgary, Alberta, Canada T2P 3W2.


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Willems, H.H., O.A. Barbian, and N.I. Uzelac. “In-LineCrack Inspection as a Part of Pipeline IntegrityManagement.” Proc. of the 2nd Int. Pipeline Conf., IPC98, held June 7-11, 1998. Houston, TX: ClarionTechnical Conferences and Pipes and PipelinesInternational, 1998.

Willems, H.H., O.A. Barbian, and N.I. Uzelac. “InternalInspection Device for Detection of Longitudinal Cracksin Oil and Gas Pipelines.” Proc. of the ASMEInternational Pipeline Conf., held June 9-14, 1996.New York, NY: ASME, 1997.

Willems, H.H., O.A. Barbian, and N.I. Uzelac. “InternalInspection Device for Detection of Longitudinal Cracksin Oil and Gas Pipelines – Results from an OperationalExperience.” Proc. of the 1st Int. Pipeline Conf., IPC96, held June 7-11, 1998. Houston, TX: ClarionTechnical Conferences and Pipes and PipelinesInternational, 1998.

Willems, H.H., O.A. Barbian, and N. Uzelac. “Results of In-Line SCC-Inspection with the UltraScan CD Tool.”Proc. of the 8th Int. Offshore and Polar EngineeringConf., held May 24-29, 1998: The International Societyof Offshore and Polar Engineers, 1998.

Willems, H.H., A. Hugger, O.A. Barbian, and N.I. Uzelac.“Results of In-Line Crack Inspection Using theUltraScan CD Tool.” Proc. of the Banff PipelineWorkshop: Managing Pipeline Integrity, held April 16-18, 1997. Banff, Alberta, Canada: CANMET, 1997.

Unpiggable Pipelines

Crouch, A.E., F.A. Burton, and G.R. Bartlett. “In-LineInspection of Unpiggable Natural Gas Pipelines.” GTITopical Report GTI-95/0323 October 1995.

Scrivner, R.W. “Magnetic-Flux Leakage Inspection of GasPipelines: Experience with a Collapsible Tool.” GTIFinal Report GTI-96/0223 July 1996.

Operational Issues

Bal, C. “Steps in Establishing a Pigging Programme.” Proc.of the Pipeline Pigging and Inspection TechnologyConf., held February 19-22, 1990. Houston, TX:Pipeline Industry and Pipes and Pipelines International,1990.

Herpin, S.D. “Pipeline Efficiency and Integrity AssessmentThrough Cleaning and In-Line Tool Inspection.”CORROSION/99, paper no. 526. Houston, TX:NACE, 1999.

Wilder, J.R. “Batching an Ultrasonic Pig in a Natural GasLiquids Pipeline.” Proc. of NACE South Central Conf.,held October 14-16, 1996. Houston, TX: NACE, 1996.

Integrity Assessment

Batte, A.D., B. Fu, M.G. Kirkwood, and D. Vu. “NewMethods for Determining the Remaining Strength ofCorroded Pipelines.” Proc. of the International Conf. onOffshore Mechanics and Arctic Engineering, held April13-17, 1997 in Yokohama, Japan. New York, NY:ASME, 1997

Beller, M. “On-Line Inspection: Part of an EfficientMaintenance Program.” Proc. of Risk Analysis andIntegrity Assessment Seminar, held February 21-22,Abu Dhabi, United Arab Emirates, 1998. Houston, TX:Energy Logistics (ELI/PennWell), 1998.

Bhatia, A., T. Morrison, G. Desjardains, “Analysis ofCorrosion Growth Using a High-Resolution In-LineInspection Tool”, Proc. of the NACE Northern AreaEastern Conference, held October 24-27, 1999.Ottawa, Canada, Paper 3B.1. Houston, TX: NACE,1999.

Germerdonk, K., A. Atto, and J. Franz. “Mid-Wall DefectsMay Affect the Integrity of Pipelines: How Can They BeDetected by Intelligent Inspection Tools?” Proc. of the1997 Pipeline Pigging Conf. Houston, TX: ClarionTechnical Conferences and Pipes and PipelinesInternational, 1997.

Germerdonk, K., T. Reiter, P. Mackenstein, W. Schmidt,and P. Jäger. “Fitness for Purpose Analysis for aPipeline Affected by Severe Critical Mid-Wall Defects.”Proc. of the 9th Int. Symposium on Loss Preventionand Safety Promotion in the Process Industries, held1998. Stockholm, Sweden: European Federation ofChemical Engineering, 1998.

Grimes, K., and T. Wheeler. “Length Adaptive PressureAssessment (LAPA) of Metal Loss Data.”CORROSION/99, paper no. 528. Houston, TX:NACE, 1999.

Worthingham R.G., T.B. Morrison, G.J. Desjardains. “CaseHistory of Integrity Management on a CorrodedPipeline,” Proc. of the NACE Northern Area WesternConference, held March 8-11, 1999, Calgary, Alberta,Session 3A. Houston, TX: NACE, 1999.

Pipeline Simulation Facility

Bubenik, T.A., J.B. Nestleroth, and M.J. Koenig. “GTIPipeline Simulation Facility Pull Rig.” GTI TopicalReport GTI-94/0377. April 1995.

Crouch, A.E., and F.A. Bruton. “Development of a Test Bedto Improve In-Line Inspection (ILI) Technologies forGas Pipeline Inspection.” GTI Topical Report GTI-91/0218. July 1991.

ohn Grapiglia - Invoice INV-294898-902F1C, downloaded on 1/12/2010 11:10:41 PM - Single-user license only, copying and networking prohibited.

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Eiber, R.J., T.A. Bubenik, J.B. Nestleroth, S.W. Rust, W.A.Maxey, and D.J. Jones. “GTI NondestructiveEvaluation Program: Pipeline Simulation FacilityDevelopment.” GTI Annual Report GTI-92/0140.December 1990.

Eiber, R.J., T.A. Bubenik, J.B. Nestleroth, S.W. Rust, W.A.Maxey, and D.J. Jones. “GTI NondestructiveEvaluation Program: Pipeline Simulation FacilityDevelopment.” GTI Annual Report GTI-92/0141.December 1991.

Koenig, M.J., T.A. Bubenik, and J.B. Nestleroth. “GTIPipeline Simulation Facility Stress Corrosion CrackingDefect Set.” GTI Topical Report GTI-94/0380. April1995.

Koenig, M.J., T.A. Bubenik, S.W. Rust, and J.B. Nestleroth.“GTI Pipeline Simulation Facility Metal Loss DefectSet.” GTI Topical Report GTI-94/0381. April 1995.

Nestleroth, J. B., T.A. Bubenik, and A. Teitsma. “GTIPipeline Simulation Facility Magnetic Flux LeakageTest Bed Vehicle.” GTI Final Report GTI-96/0207.June 1996.

Nestleroth, J.B., R.J. Davis, and T.A. Bubenik. “GTI PipelineSimulation Facility Nondestructive EvaluationLaboratory.” GTI Topical Report GTI-94/0378. April1995.

Vieth, P.H., W.A. Maxey, R.E. Mesloh, J.F. Kiefner, andG.M. Williams. “Investigation of the Failure in GTI’sPipeline Simulation Facility Flow Loop.” GTI FinalReport GTI-96/0188. May 1996.

Third-Party Damage

Davis, R.J., T.A. Bubenik, and A.E. Crouch. “The Feasibilityof MFL ILI as a Method to Detect and CharacterizeMechanical Damage.” GTI Final Report GTI-95/0369.June 1996.

Francini, R.B., R.W. Hyatt, B.N. Leis, V.K. Narendran, D.Pape, and F.B. Stulen. “Real-Time Monitoring to DetectThird-Party Damage.” GTI Final Report GTI-96/0077.March 1996.

Randall H., N.A. Dunker, and N.M. Santee. “Third-PartyDamage Prevention Systems.” GTI Final Report GTI-95/0316. October 1995.


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Appendix A: Glossary of Terms Used in the In-Line Nondestructive Testing of Pipelines

The following terms are commonly used in the in-linenondestructive testing of pipelines. This Glossary isintended as a reference. Terms are not necessarily usedwithin this report.

Aboveground Marker (AGM): A portable device placed onthe ground above a pipeline that both detects and recordsthe passage of an in-line inspection tool or transmits asignal that is detected and recorded by the tool.

Anomaly: A possible deviation from sound pipe material orweld. Indication may be generated by nondestructiveexamination, such as in-line inspection.

ASME B 31G:16 “Manual for Determining the RemainingStrength of Corroded Pipelines: A Supplement to ASME B31 Code for Pressure Piping,” published by ASMEInternational. This is commonly used when analyzingmetal-loss anomalies in pipe.

B 31G: See ASME B 31G.

B-Scan: A cross-sectional display of a test object formedby plotting the beam path lengths for echoes with a presetrange of amplitude, in relation to the position of beam axis(in ultrasonic testing), or the values of the measuredmagnetic field (with magnetic flux leakage), as the probe isscanned in one direction only.

Batch, Batching: Separated volume of liquid within aliquids pipeline or of liquid within a gas pipeline. Sealing(batching) pigs are typically used for separation.

Bellhole: An excavation to permit a survey, inspection,maintenance, repair, or replacement of pipe sections.

C-Scan: A two-dimensional plane display of a test objectformed by plotting the presence of echoes within a presetrange of amplitude, a beam path length (in ultrasonictesting), or the values of the measured magnetic fields (withmagnetic flux leakage), in relation to the position of thescanning probe.

Calibration Dig: Exploratory excavation to validate findingsof an in-line inspection tool with the purpose of improvingdata interpretation.

Caliper Pig: See Geometry Pig.

Camera Pig: A configuration pig that carries a video or filmcamera and light source(s) for photographing the insidesurface of a pipe on an intermittent, real-time, or continuousbasis.

Cathodic Protection (CP): A technique to reduce thecorrosion of a metal surface by making that surface thecathode of an electrochemical cell.

Characterize: To qualify the type, size, shape, orientation,and location of an anomaly.

Check Valve: Valve that prevents reverse flow. Can causedamage to in-line inspection tools if not fully opened.

Class Location: A criterion for pipeline design set by theUnited States Code of Federal Regulations, Title 49, Part192.17 Class 1 is rural and Class 4 is heavily populated. Aclass location is based on the number and type of buildingssituated in an area that extends 220 yd (200 m) on eitherside of the centerline of any continuous 1.0-mile (1.6-km)length of a gas pipeline.

Classify: To separate indications into categories, e.g.,anomalies, nonrelevant indications, pipeline components,etc.

Cleaning Pig: A utility pig that uses cups, scrapers, orbrushes to remove dirt, rust, mill scale, and other debrisfrom the pipeline. Cleaning pigs are utilized to increase theoperating efficiency of a pipeline or to facilitate inspection ofthe pipeline.

Coating Disbondment: The loss of adhesion between acoating and the substrate.

Coil Sensor: See Induction Coil.

Corrosion: The deterioration of a material, usually a metal,that results from a reaction with its environment.

Crack Coalescence: Joining of two or more cracks inclose proximity to form a longer crack.

Crack, Cracking: Very narrow elongated defects causedby mechanical splitting into parts.

Critical Defect: A defect for which an analysis indicatesthat immediate attention is required.

Data Analysis: The process through which indicationsrecorded in an in-line inspection are evaluated to classify,characterize, and size them.

Defect: An anomaly for which an analysis indicates that thepipe is approaching failure as the nominal hoop stressapproaches the specified minimum yield stress of the pipematerial.

Detect: To sense or obtain a measurable in-line inspectionindication from an anomaly in a pipeline.

Differential Pressure: The difference between thepressures behind and ahead of the in-line inspection tool –the actual propeller of the tool.

Diffusion: The passage of a substance into a body (e.g.,hydrogen into steel).


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Dirty Steel: A term used to denote steel containing a highnumber of nonmetallic inclusions.

Discrete Repair: A short segment of pipeline identified tobe repaired.

Dissolution: The decomposition of a solid into parts.

Distribution Line: A gas pipeline other than a gatheringline or transmission line (See U.S. Code of FederalRegulations, Title 49, Part 192).17

Double Submerged Arc Weld (DSAW): Weld using fillermetal passes on the inside and outside of the pipe.

Ductility: A measure of the capability of a material to bedeformed plastically before fracturing.

Dummy Tool Run: Preliminary run of an uninstrumentedpig to verify safe passage of a fully instrumented toolthrough a section of pipeline. Dummy runs can also beused to remove debris from the inside of the pipeline.

Elastic Limit: The maximum stress to which a materialmay be subjected without retention of any permanentdeformation after the stress is removed.

Electric Potential: A voltage existing between the pipeand its environment.

Electric Resistance Weld (ERW): Weld formed byresistance heating of the two edges of a pipe and thenforcing them together to create a solid-state weld.

Estimated Repair Factor (ERF): The ratio of the pipelinedesign pressure to the “safe maximum pressure” asdetermined by an analysis criterion (e.g., ASME B 31G,RSTRENG,18 etc.).

Evaluation: A review, following the identification of ananomaly, to determine whether the anomaly meetsspecified acceptance criteria.

False Call: An inspection indication that is erroneouslyclassified as an anomaly or a defect.

Fatigue: The phenomenon leading to fracture of a materialunder repeated or fluctuating stresses having a maximumvalue less than the tensile strength of the material.

Feature: As used in this text, any physical object detectedby an in-line inspection tool during the performance of aninspection run. Features may be anomalies or indications,pipeline valves and fittings, nearby metallic objects, or otheritems.

Flash Welded: Distinct type of electric resistance weld(ERW) pipe, made from individually rolled plates formed intocans before being welded.

Fracture Mechanics: A quantitative analysis for evaluatingstructural reliability in terms of applied stress, crack length,and specimen geometry. For the purpose of this report, thestudy of the physics of defect initiation and growth in amaterial.

Fracture Toughness: A measure of the resistance of amaterial to defect extension, either slow or rapid.

Free Corrosion Potential: The electric potential that existsin the absence of an applied potential with corrosionoccurring.

Free Surface: A surface with one side not constrained byadjacent metal, just air.

Gathering Line: A pipeline that transports gas from aproduction facility (e.g., gas, well) to a processing orcompressor station prior to entry into the transmissionpipeline.

Gauge Plate/Bend Plate Pig: A utility pig mounted with aflexible metal plate of a specified diameter less than theminimum internal diameter of the pipeline. Pipe borerestrictions less than the plate diameter or short radiusbends will permanently deflect the plate material.

Gel Pig: A utility pig that is composed of a highly viscousgelled liquid, often used for pipeline cleaning.

Geometry Pig: A configuration pig designed to recordconditions, such as dents, wrinkles, ovality, bend radius andangle, and occasionally indications of significant internalcorrosion, by sensing the shape of the internal surface ofthe pipe.

Girth Weld: Circumferential weld joining two joints of pipe.

Hall-Effect Sensor, Hall Element: A type of sensor thatdirectly measures magnetic field. Hall-effect sensorsrequire power to operate.

High Vapor-Pressure (HVP) Liquid: Hydrocarbons orhydrocarbon mixtures in the liquid or quasi-liquid state witha vapor pressure in excess of 107 kPa (15.5 psi) absolute at38°C (100°F).

Holiday: A discontinuity in a protective coating thatexposes unprotected surface to the environment.

Hoop Stress: Stress around the circumference of a pipe(i.e., perpendicular to the pipe length) caused by internalpressure.

Hydrogen Embrittlement: A loss of ductility of a metalresulting from absorption of hydrogen.

Hydrolysis: Decomposition of a chemical compound byreaction with water.


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Hydrostatic Testing (Re-Testing): Testing of sections of apipeline by filling the line with water and pressurizing it untilthe nominal hoop stresses in the pipe reach a specifiedvalue.

Imperfection: An anomaly in the pipe that will not result inpipe failure at pressures below those that produce nominalhoop stresses equal to the specified minimum yield stressof the pipe material.

Incident: An event that is reported to U.S. Department ofTransportation,(11) Office of Pipeline Safety, that involvesfatalities, injuries, property damage in excess of $50,000,unintentional release of natural gas, customer outages, orother conditions that, in the opinion of the pipeline operator,are significant enough that they should be reported.

Indication: A finding of a nondestructive testing inspection.

Induction Coil: A type of sensor that measures the timerate of change in magnetic flux density. Induction coils donot require power to operate, but have a minimuminspection speed requirement.

In-Line Inspection (ILI): The inspection of a pipeline fromthe interior of the pipe using an in-line inspection tool. Alsocalled Intelligent or Smart Pigging.

In-Line Inspection Tool: The device or vehicle that uses anondestructive testing technique to inspect the pipeline fromthe inside. Also known as Intelligent or Smart Pig.

Instrumented Pig Tool: Older term for in-line inspectiontools.

Interaction Rules: Specifications that establish spacingcriteria between anomalies or defects. If the indications ordefects are proximate to one another within the criteria, theanomaly or defect is treated as a single larger unit forengineering analysis purposes.

Intergranular Crack: Crack growth or crack path that isbetween the grains of a metal.

Joint: A single section of pipe that is welded to others tomake up a pipeline.

Launcher: A pipeline device used to insert a pig into apressurized pipeline.

Leak: A small opening, crack, or hole in a pipeline causingsome product loss, not necessarily immediately impairingthe operation of the pipeline.

Liquefied Natural Gas (LNG): Natural gas liquefied byrefrigeration or pressure in order to facilitate storage ortransport.

Liquefied Petroleum Gas (LPG): Petroleum gases(butane, propane, etc.) liquefied by refrigeration or pressureto facilitate storage or transport.

Loading Rate: Rate at which pressure increases in apipeline.

Longitudinal Channeling: Narrow, deep (channel-like),axially oriented corrosion, often along a longitudinal seamweld.

Low Vapor-Pressure (LVP) Liquid: Hydrocarbons orhydrocarbon mixtures in the liquid or quasi-liquid state witha vapor pressure of 107 kPa (15.5 psi) absolute or less at38°C (100°F).

Lorentz Forces: Forces acting on moving charges inmagnetic fields.

Magnetic Field Strength: The magnitude of the magneticfield produced by a magnet.

Magnetic Flux Leakage (MFL): The flows of flux from amagnetized material, such as the wall of a pipe, into amedium with lower permeability, such as gas or air.

Magnetic Flux Lines: A representation of the strength anddirection of a magnetic field. Flux lines are drawn parallel tothe direction of magnetic force. The spacing of these linesrepresents the magnetic field strength. Flux lines alwaysform nonintersecting closed loops starting at the north poleand ending at the south pole of a magnet.

Magnetic Particle Inspection (MPI): A nondestructiveexamination technique for locating surface flaws in steelusing fine magnetic particles and magnetic fields.

Magnetic Permeability: The ability of magnetic flux todiffuse through (or permeate) a magnetic material. Theratio of magnetic flux density to magnetic field strength.

Magnetic Saturation: The degree of magnetization atwhich a further increase in magnetic field strength producesa decrease in magnetic permeability of a material.

Mapping Pig: A configuration pig that uses inertial sensingor some other technology to collect data that can beanalyzed to produce an elevation and plan view of thepipeline route.

Maximum Allowable Operating Pressure (MAOP): Themaximum internal pressure permitted during the operationof a pipeline as defined by the U.S. Code of FederalRegulations.17

___________________________(11) U.S. Department of Transportation (USDOT), 400 7th St. SW, Washington, DC 20590.


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Maximum Operating Pressure (MOP): The maximuminternal pressure that cannot normally exceed the maximumallowable operating pressure expected during the operationof a pipeline.

Metal Loss: Any of a number of types of anomalies in pipein which metal has been removed from the pipe surface,usually due to corrosion or gouging.

Microstructure: Structure of metals and alloys as revealedafter polishing and etching; hot-rolled steels usually consistof bands of ferrite (iron) and pearlite (carbon) but maycontain other microstructures such as matensite (hard brittlegrains) or bainite (not as hard or brittle as martensite).

Mill Scale: The oxide layer formed during hot fabrication orheat treatment of metals.

Nondestructive Evaluation (NDE): The evaluation ofresults from nondestructive testing methods ornondestructive testing techniques in order to detect, locate,measure, and evaluate anomalies.

Nondestructive Testing (NDT): The actual application ofa nondestructive testing method or a nondestructive testingtechnique.

Nondestructive Testing Method (NDT Method): Aparticular method of nondestructive testing, such asradiography, ultrasonic, magnetic testing, liquid penetrant,visual, leak testing, eddy current, and acoustic emission.

Nondestructive Testing Technique (NDT Technique): Aspecific way of utilizing a particular nondestructive testingmethod that distinguishes it from other ways of applying thesame nondestructive testing method. For example,magnetic testing is a nondestructive testing method whilemagnetic flux leakage and magnetic particle inspection arenondestructive testing techniques. Similarly, ultrasonic is anondestructive testing method, while contact shear-waveultrasonic and contact compression-wave ultrasonic arenondestructive testing techniques.

Nonmetallic Inclusion: A particle of foreign material in ametallic matrix. Usually the foreign material is an oxide,sulfide, or silicate, but may be of any substance foreign tothe matrix.

Nonrelevant Indication: A response recorded during aninspection that comes from a source outside the pipeline,such as foreign objects in the ditch.

Nucleate: Initiate the growth of a crack.

Off-Line Inspection: Inspection of a pipeline section that isremoved from service.

On-Line Inspection: Inspection of a pipeline section whileit is in service.

Passivity: The state of being passive. For the purpose ofthis report, a function of the electrochemical environmentinvolving formation of a passive or protective film.

pH: The negative logarithm of the hydrogen ion activitywritten as pH = -log10 (aH

+) where aH+ = hydrogen ion

activity = the molar concentration of hydrogen ionsmultiplied by the mean ion-activity coefficient. For thepurpose of this report, a measure of the acidity or alkalinityof a substance.

Pig: A generic term signifying any independent, self-contained device, tool, or vehicle that moves through theinterior of the pipeline for inspecting, dimensioning, orcleaning.

Pig Sig: A usually mechanical sensor on the pipe activatedby the passage of the in-line inspection tool.

Pigging: See In-Line Inspection.

Pipeline: That portion of the pipeline system betweencompressor or pump stations including the pipe, protectivecoatings, cathodic protection system, field connections,valves, and other appurtenances attached or connected tothe pipe.

Pipeline Component: A feature, such as a valve, cathodicprotection connection, or tee that is a normal part of thepipeline. The component may produce an indication that isrecorded as part of an inspection by an in-line inspectiontool or configuration pig.

Pipeline System: All portions of the physical facilitiesthrough which gas, oil, or product moves duringtransportation, including pipe, valves, and otherappurtenances attached to the pipe, such as compressorunits, metering stations, regulator stations, delivery stations,holders, and other fabricated assemblies. (See U.S. Codeof Federal Regulations, Title 49, Part 192.)17

Pressure: Level of force per unit area exerted on the insideof a pipe or vessel.

Pressure Reversal: Failure of a defect (e.g., crack) at apressure level below the maximum level reached on a priorloading (e.g., hydrostatic retest).

Proportional limit: See Elastic Limit.

Receiver: A pipeline facility used for removing a pig from apressurized pipeline.

Remediation: An operation or procedure that eliminatesthe factor or factors causing an imperfection, defect, orcritical defect.


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Remnant Magnetization: The magnetization level left in asteel pipe after the passage of a magnetic in-line inspectiontool.

Residual Stress: Stress present in an object in theabsence of any external loading; results from manufacturingprocess, heat treatment, or mechanical working of material.

RSTRENG: Analysis criterion specified in the AmericanGas Association project report AGA-PR-3-805,19 “AModified Criterion for Evaluating the Remaining Strength ofCorroded Pipe.”

RESTRENG 2: An enhanced version of RSTRENG asspecified in the American Gas Association project reportAGA-PR-218-9205.18

Rupture: The instantaneous tearing or fracturing of pipematerial causing large-scale product loss and immediatelyimpairing the operation of the pipeline.

Rupture Pressure Ratio (RPR): The ratio of the “predictedburst pressure” calculated by an analysis criterion (e.g.,ASME B 31G, RSTRENG, etc.) to the pressure at specifiedminimum yield stress (SMYS).

Seam Weld: The longitudinal weld in pipe, which is madein the pipe mill.

Selective Pipe Replacements: Pipe replacementsundertaken adjacent to critical areas such as dwellings.

Sensors: Devices that receive a response to a stimulus,e.g., an ultrasonic sensor detects ultrasound.

Shielded Corrosion: Corrosion between the pipe and theprotective coating, which is not controlled by cathodicprotection currents. Commonly referred to as “cathodicshielding.”

Slug: Confined liquids within a gas pipeline.

Smart Pig: See In-Line Inspection Tool.

Sour Gas: Natural gas containing hydrogen sulfide in suchproportion as to require treating in order to meet domesticsales gas specifications.

Specified Minimum Yield Strength (SMYS): A requiredstrength level that the measured yield stress of a pipematerial must exceed, and which is a function of pipe grade.The measured yield stress is the tensile stress required toproduce a total elongation of 0.5% of a gauge length asdetermined by an extensometer during a tensile test.

Sphere Pig: A spherical utility pig made of rubber orurethane. The sphere may be solid or hollow, filled with airor liquid. The most common use of sphere pigs is as abatching pig.

Strain: Increase in length of a material expressed on a unitlength basis (e.g., inches per inch).

Strain Hardening: An increase in hardness and strengthcaused by plastic deformation at a temperature below there-crystallization range.

Stress: Tensile or compressive force per unit area in thepipe wall as a result of the loads applied to the structure.

Stress Intensity Factor: A fracture mechanics termrelating the crack size, geometry, and stress acting on acrack.

Stress Raiser or Concentration: A change in contour,discontinuity, gouge, or notch that causes local increases inthe stress in a pipe.

Stress Relief: Reduction of residual stresses eitherthrough a mechanical overload or through an elevatedtemperature.

Stress Relieving (Thermal): Heating a metal to a suitabletemperature, holding at that temperature long enough toreduce residual stresses, and then cooling slowly enough tominimize the development of new residual stresses.

Sub-Critical Crack: A crack that is not large enough tocause a failure of a pipeline at a given pressure.

Survey: Measurements, inspections, or observationsintended to discover and identify events or conditions thatindicate a departure from normal operation of the pipeline.

Tensile Stress: Stress that elongates the material.

Tenting: A tent-shaped void formed along the longitudinalseam-weld or circumferential weld reinforcement in a pipewhen the external coating is not in continuous intimatecontact with the pipe and weld surfaces.

Terrain Conditions: The soil type, drainage, andtopography at a given location.

Testing: See Hydrostatic Testing (Re-Testing).

Tool: A generic term signifying any type of instrumentedtool or pig.

Transducer: A device for converting energy from one formto another, e.g., in ultrasonic testing, conversion of electricalpulses to acoustic waves and vice versa.

Transgranular Crack: Crack growth or crack path that isthrough or across the grains of a metal.


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Transmission Line: A pipeline, other than a gathering ordistribution line, that transports gas from a gathering orstorage facility to a distribution center or storage facility;operates at a hoop stress of 20% or more of the specifiedminimum yield stress of the pipe; or transports gas within astorage field. (See U.S. Code of Federal Regulations, Title49, Part 192.) 17

Trap: Pipeline facility for launching or receiving tools andpigs.

Utility Pig: A pig that performs relatively simple mechanicalfunctions, such as cleaning the pipeline.

Yield Pressure: The pressure at which the nominal hoopstress in the pipe wall equals the specified minimum yieldstress of the pipe grade.

Yield Strength: The stress at which a material exhibits aspecified deviation from the proportionality of stress tostrain. The deviation is expressed in terms of strain byeither the offset method (usually at a strain of 0.2%) or thetotal-extension-under-load method (usually at a strain of0.5%).

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Appendix B: Acronyms Commonly Used in theIn-Line Nondestructive Testing of Pipelines

The following acronyms are commonly used in the in-line nondestructive testing of pipelines. This list isintended as a reference. The acronyms are not necessarily used within this report.

AGA American Gas AssociationAGM Aboveground markerAPI American Petroleum InstituteASME American Society of Mechanical EngineersCAPP Canadian Association of Petroleum ProducersCEPA Canadian Energy Pipeline AssociationCFR U.S. Code of Federal RegulationsCSA Canadian Standards AssociationDOT U.S. Department of TransportationEMAT Electromagnetic acoustic transducerGTI Gas Technology Institute (formerly Gas Research Institute)ILI In-line inspectionMAOP Maximum allowable operating pressureMFL Magnetic flux leakageMIC Microbiologically influenced corrosionMPI Magnetic particle inspectionNDE Nondestructive evaluationNDT Nondestructive testingNEB National Energy Board of CanadaOPS Office of Pipeline Safety, U.S. Department of Transportation (DOT)PRCI Pipeline Research Council InternationalPSF Pipeline Simulation Facility at Battelle, Columbus, OhioSCC Stress corrosion crackingSMYS Specified minimum yield strengthUT Ultrasonic testing


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Appendix C: Typical Specifications

The following tables provide typical specifications for in-line inspection tools.

Table C1: Typical Specifications for Standard-Resolution (Low, Conventional) MFL ToolsAxial sampling distance:

Analog recording

Circumferential sensor spacing:40 to 150 mm (1.6 to 6.0 in.)

Detection limitations:No discrimination between internal and external defectsProvide approximate estimate of corrosion severityPipeline excavations may be needed to establish references for calibrationLimited detection capability upstream and downstream from girth weldsClustered defects may not be individually identified

Minimum defect depth:20% of wall thickness (WT)

Minimum inspection speed requirement:0.34 m/s (0.75 mph)

Maximum inspection speed requirement:4 m/s (9 mph)

Depth sizing accuracy:± 15% of WT

Length sizing accuracy:± 13 mm (0.50 in.)

Location accuracy:Axial (relative to closest girth weld): ± 50 mm (2.0 in.)Circumferential: ± 30°

Confidence level:80%


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Table C2: Typical Specifications for High-Resolution (HR) MFL ToolsAxial sampling distance:

From 2 mm (0.08 in.)If the tool operates with a fixed sampling frequency, the axial sampling distance increases withinspection speed.


Detection limitations:Minimum defect depth: 10% of WTAccuracy of measurement of defect depth: 10% of WT

Minimum inspection speed requirement:0.5 m/s (~1 mph) (Inductive coils); None (Hall-Effect sensors)

Maximum inspection speed requirement:4 to 5 m/s (9 to 11 mph)

Minimum magnetization level:Minimum magnetic field strength: 10 to 12 kA/m (3 to 3.7 kA/ft)Minimum magnetic flux density: 1.7 T

(this requirement should eliminate sensitivity to speed and remnant magnetization)20

Depth sizing accuracy:General metal loss: Minimum depth: 10% of WT

Depth sizing accuracy: ± 10% of WTLength sizing accuracy: ± 20 mm (0.8 in.)

Pitting metal loss: Minimum depth: 10 to 20% of WT Depth sizing accuracy: ± 10% of WT Length sizing accuracy: ± 10 mm (0.4 in.)

Axial grooving metal loss: Minimum depth: 20% of WTDepth sizing accuracy: -15/+10% of WTLength sizing accuracy: ± 20 mm (0.8 in.)

Circumferential grooving metal loss: Minimum depth: 10% of WT Depth sizing accuracy: -10/+15% of WT Length sizing accuracy: ± 15 mm (0.60 in.)

Axial slotting metal loss: Minimum depth: Detectable but not reportedCircumferential slotting metal loss: Minimum depth: 10% of WT

Depth sizing accuracy: -15/+20% of WT Length sizing accuracy: ± 15 mm (0.6 in.)

Corrosion at girth welds: Adjacent to the weld: Minimum depth: 10% of WT Depth sizing accuracy: ± 10 to 20% of WTOn or through the weld: Minimum depth: 10 to 20% of WT

Depth sizing accuracy: ± 10 to 20% of WTLength sizing accuracy (axial):

10 mm (0.4 in.)Width sizing accuracy (circumferential):

± 10 to 17 mm (0.4 to 0.7 in.)Location accuracy:

Axial (relative to closest girth weld): ± 0.1 m (4 in.)Circumferential: ± 5°


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Table C3: Typical Specifications for Extra-High-Resolution MFL Tools

Axial sampling distance:2 mm (0.08 in.) up to inspection speeds of 2 m/s (4.5 mph)


Detection limitations:Minimum defect depth: 3% of WTAccuracy of measurement of defect depth: 5 to 10% of WT

Depth sizing accuracy:± 5 to 10% of WT

Length sizing accuracy:± 10 mm (0.4 in.)

Location accuracy:Axial (relative to closest girth weld): ± 0.1 m (4 in.)Circumferential: ± 5°



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Table C4: Typical Specifications for Ultrasonic Testing Tools

Axial sampling distance:3 mm (0.12 in.)

Circumferential sensor spacing:8 mm (0.3 in.)

Maximum inspection speed requirement:2 m/s (4.5 mph) (to achieve maximum axial resolution; axial resolution deteriorates linearly at

speeds higher than 2 m/s [4.5 mph])

Detection capabilities:Basic accuracy of depth measurements: ± 0.5 mm (0.02 in.)

for flat surfaces and wall thickness: ± 0.2 mm (0.008 in.)Longitudinal resolution: 3 mm (0.12 in.)Circumferential resolution: 8 mm (0.3 in.)Minimum detectable corrosion depth: 0.2 mm (0.008 in.)

Minimum size of pits to be detected:Indication and area extension, no depth measurement: Diameter: 10 mm (0.4 in.)

Depth: 1.5 mm (0.06 in.)With full-depth measurement: Diameter: 20 mm (0.8 in.)

Depth: 1 mm (0.04 in.)

Location accuracy:Axial (relative to the closest girth weld): 0.1 m (4 in.)Circumferential: ± 5°



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Table C5: Typical Specifications for Liquid-Coupled Crack-Detection Tools

Axial sampling distance:3.0 mm (0.12 in.)


Detection limitations:Detectable defects: Minimum length: 30 mm (1.2 in.)

Minimum depth: 1 mm (0.04 in.)Defect alignment: ± 15° of the pipe axisDefect location: Internal mid-wall, external, base material, longitudinal weld

Inspection speed:Up to 1.0 m/s (2.3 mph) (to achieve maximum axial resolution; axial resolution deteriorates linearly

at speeds higher than 1.0 m/s [2.3 mph])

Available sizes:56 to 142 cm (22 to 56 in.) (smaller sizes will be available in 2001)

Sizing accuracy:Length: ± 10% WT (for features > 100 mm [4 in.])

± 10 mm (for features < 100 mm [4 in.])Width (for crack fields):± 50 mm (2 in.)Depth: classification in categories:

< 12.5 % WT12.5 to 25 % WT25 to 40 % WT > 40 % WT


Confidence level:80 %


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Table C6: Typical Specifications for Wheel-Coupled Crack-Detection Tools

Axial sampling distance:5 mm (0.2 in.)

Circumferential sensor spacing:210 to 285 mm (8.3 to 11 in.) depending on tool size

Detection limitations:Detectable defects: Minimum length: 50 mm (2 in.)

Minimum depth: 25% of WTDefect alignment: ± 10° of the pipe axisDefect location: Base material excluding 50 mm (2 in.) upstream and downstream from girth

weld.No internal/external defect discrimination

Inspection speed:0.5 to 3 m/s (1.1 to 6.7 mph) in liquid1 to 3 m/s (2.2 to 6.7 mph) in gas

Available sizes:61 cm (24 in.), 76 to 91 cm (30 to 36 in.)



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Table C7: Typical Specifications for Circumferential Magnetization Tools

Axial sampling distance:3.3 mm (0.13 in.)


Detection limitations:Detectable defects: Minimum length: 25 mm (1.0 in.)

Minimum width: 0.1 mm (0.004 in.)Minimum depth: 25% WT

Defect alignment: ± 15° of the pipe axisDefect location: Within 50 mm (2 in.) on each side of the long seam weld

No external/internal defect discriminationInspection speed:

0.2 m/s (0.45 mph) to 4 m/s (9 mph)

Sizing accuracy:Length: ± 25 mm (1.0 in.)Depth: ± 20% WT

Available sizes:15 to 142 cm (6.0 to 56.0 in.)

Location accuracy:Axial (relative to the closest girth weld): 0.2 m (8 in.)Circumferential: ± 7.5°



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Appendix D: Preparing for an Inspection

Key activities that are scheduled in preparation for an inspection have included the following:

• Anticipation of the condition of the pipeline.• Completion of pipeline questionnaire − summary of the pipeline and its characteristics.• Definition of the need for cleaning of the line as well as the recommended cleaning pigs to be used.• Identification of the need for a gauge plate or bend plate pig to be sent down the line.• Identification of any restrictive bends or fittings and how they will be addressed.• Summation of line modifications necessary to perform the inspection.• Identification of the need for a caliper tool to be run in the line.• Identification of the need for setting aboveground benchmarks for the caliper tool.• Identification of the need for a bend tool to be run in the line.• Recommendation of detection technology to be employed.• Identification of a tool and its availability to meet the conditions of the pipeline (with or without

modifications).• Timing of contractor data analysis and reporting to the operator.• In a gas line, any outage-specific considerations require the use of variable bypass technology.• Definition of a procedure to be used for running the inspection tool.• Identification if more than one vendor can provide a tool for the required system.• Definition of the need for a dummy metal-loss tool run.• Identification of which tools are to be tracked and whether they are to be tracked continuously or

discretely.• Identification of a recommended benchmarking system to be employed by the metal-loss survey tool.• Development of contingency plan for emergency operations.• Determination of the feasibility of conducting repairs/excavations once the in-line inspection is complete.

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Appendix E: Launching and Receiving Procedures

The following procedures describe launching and receiving procedures for in-line inspection (ILI) tools.

Launching Procedure

Caution:

1. ILI tools can never be pushed backward.2. Damage will occur if the ILI tool hits the launcher isolation valve before or as it is being launched.

The following list is the state-of-the-art procedure typically conducted during launching operations. (Theprocedure is usually modified after a thorough site investigation):

1. Isolate the launching trap.2. Drain and depressurize the launching trap.3. Ensure that all ILI tool diagnostic checks are complete, and the tool is operational and ready to load.4. Load the ILI tool until the front cups seal within the reducer.5. Equalize pressure in the launching trap.6. Ensure that the desired inspection flow rate is achieved and open the launcher isolation valve. Pressures

are equalized such that the tool does not move.7. Launch the ILI tool.8. Restore the trap to original state.

Receiving Procedure

Caution:

1. Damage may occur if the ILI tool hits the receiver closure door.2. Damage may occur if the receiver isolation valve is closed before the entire ILI tool has passed.


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The following list is the state-of-the-art procedure typically conducted during receiving operations. (Theprocedure is usually modified after a thorough site investigation):

1. Set up the trap for receipt – ensure valving is appropriate.2. Receive the tool, isolate the receiving trap, open the bypass valve.3. Drain and depressurize the trap.4. Remove the ILI tool.5. Restore trap to original state.


tr-35100 - in line non destructive inspection of pipelines

Documents

clarion technical conferences

gas research institute

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ultrascan cd tool

closest girth weld

pipeline research committee

nondestructive testing techniques

national energy board