Nace Rp010202 Inspeccion de Tuberias

StandardRecommended Practice

In-Line Inspection of Pipelines

This NACE International standard represents a consensus of those individual members who havereviewed this document, its scope, and provisions. Its acceptance does not in any respectpreclude anyone, whether he has adopted the standard or not, from manufacturing, marketing,purchasing, or using products, processes, or procedures not in conformance with this standard.Nothing contained in this NACE International standard is to be construed as granting any right, byimplication or otherwise, to manufacture, sell, or use in connection with any method, apparatus, orproduct covered by Letters Patent, or as indemnifying or protecting anyone against liability forinfringement of Letters Patent. This standard represents minimum requirements and should in noway be interpreted as a restriction on the use of better procedures or materials. Neither is thisstandard intended to apply in all cases relating to the subject. Unpredictable circumstances maynegate the usefulness of this standard in specific instances. NACE International assumes noresponsibility for the interpretation or use of this standard by other parties and acceptsresponsibility for only those official NACE International interpretations issued by NACE Internationalin accordance with its governing procedures and policies which preclude the issuance ofinterpretations by individual volunteers.

Users of this NACE International standard are responsible for reviewing appropriate health, safety,environmental, and regulatory documents and for determining their applicability in relation to thisstandard prior to its use. This NACE International standard may not necessarily address allpotential health and safety problems or environmental hazards associated with the use ofmaterials, equipment, and/or operations detailed or referred to within this standard. Users of thisNACE International standard are also responsible for establishing appropriate health, safety, andenvironmental protection practices, in consultation with appropriate regulatory authorities ifnecessary, to achieve compliance with any existing applicable regulatory requirements prior to theuse of this standard.

CAUTIONARY NOTICE: NACE International standards are subject to periodic review, and may berevised or withdrawn at any time without prior notice. NACE International requires that action betaken to reaffirm, revise, or withdraw this standard no later than five years from the date of initialpublication. The user is cautioned to obtain the latest edition. Purchasers of NACE Internationalstandards may receive current information on all standards and other NACE Internationalpublications by contacting the NACE International Membership Services Department, 1440 SouthCreek Dr., Houston, Texas 77084-4906 (telephone +1[281]228-6200).

Approved 2002-02-17NACE International

1440 South Creek DriveHouston, Texas 77084-4906

+1 281/228-6200

ISBN 1-57590-142-0© 2002, NACE International

NACE Standard RP0102-2002Item No. 21094

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NACE International i

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Foreword

Since the transportation of hydrocarbons by pipeline began in the 1860s, the primary means ofestablishing pipeline integrity has been through the use of pressure testing. These tests have beenmost often performed upon completion of the construction of the pipeline. The completed pipelinesegment has been pressurized to a level equal to or exceeding the anticipated maximum operatingpressure (MOP). Government regulations have recently specified the test pressures, test media,and test durations that must be achieved for pipelines to be permitted to operate within theirjurisdictions. However, until very recent history, there have been no such requirements forpipelines to be periodically tested for integrity. Some pipeline operators have traditionallyperformed periodic integrity assessments in a variety of forms with varying degrees of success.

In the mid-1960s, pipeline operators began to use a form of instrumented inspection technologythat has evolved into what is known today as in-line inspection (ILI). ILI is but one tool used inpipeline integrity assessment. The technology has now become so reliable that it holds aprominent place in many operators’ integrity programs because when properly applied, ILI providesmany economies and efficiencies in integrity assessment at a relatively small risk.

This standard recommended practice outlines a process of related activities that a pipeline operatorcan use to plan, organize, and execute an ILI project. Guidelines pertaining to ILI datamanagement and data analysis are included. A key companion guide to this standard is NACEInternational Publication 35100.1

This standard is intended for use by individuals and teams planning, implementing, and managingILI projects and programs. These individuals include engineers, operations and maintenancepersonnel, technicians, specialists, construction personnel, and inspectors. Users of this standardmust be familiar with all applicable pipeline safety regulations for the jurisdiction in which thepipeline operates. This includes all regulations requiring specific pipeline integrity assessmentpractices and programs.

This NACE standard was prepared by Task Group 212 on In-Line Nondestructive Inspection ofPipelines. Task Group 212 is administered by Specific Technology Group (STG) 35 on Pipelines,Tanks, and Well Casings. This standard is issued by NACE International under the auspices ofSTG 35.

In NACE Standards, the terms shall, must, should, and may are used in accordance with thedefinitions of these terms in the NACE Publications Style Manual, 4th ed., Paragraph 7.4.1.9. Shalland must are used to state mandatory requirements. The term should is used to state somethinggood and is recommended but is not mandatory. The term may is used to state somethingconsidered optional.

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ii NACE International

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NACE InternationalStandard

Recommended Practice

In-Line Inspection of Pipelines

Contents

1.General............................................................................................................................ 12.Definitions........................................................................................................................ 13.Tool Selection.................................................................................................................. 34.Pipeline ILI Compatibility Assessment ............................................................................ 45.Logistical Guidelines ....................................................................................................... 96. Inspection Scheduling ................................................................................................... 117.New Construction—Planning for ILI Surveys ................................................................ 148.Data Analysis Requirements ......................................................................................... 169.Data Management ......................................................................................................... 19References........................................................................................................................ 20Bibliography ...................................................................................................................... 20Appendix A........................................................................................................................ 21TablesTable 1: Types of ILI Tools and Inspection Purposes ....................................................... 5FiguresFigure 1: Plan View of a Generic Pig Trap ...................................................................... 23

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Section 1: General

1.1 This standard is applicable to carbon steel pipelinesystems used to transport natural gas, hazardous liquidsincluding anhydrous ammonia, carbon dioxide, waterincluding brine, liquefied petroleum gases (LPGs), and otherservices that are not detrimental to the function and stabilityof ILI tools.

1.2 This standard is primarily applicable to “free-swimming”ILI tools but not tethered or remotely controlled inspectiondevices.

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1.3 This standard provides recommendations to thepipeline operator based on successful, industry-provenpractices in ILI.

1.4 This standard is specific to the inspection of line pipeinstalled along a right-of-way, but the general process andapproach may be applied to other pipeline facilities such ashydrocarbon distribution and gathering systems, waterinjection systems, station piping, and isolated crossings ofrailroads, highways, or waterways.

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Section 2: Definitions

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. An indication may be generated by nondestructiveexamination, such as in-line inspection.

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 [MFL]), as theprobe is scanned 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.

Caliper 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 (also referred to as geometry pig).

Chainage: Position of a point along the pipeline, typicallytaken from a fixed reference such as a valve.

Check Valve: Valve that prevents reverse flow. Can causedamage to ILI tools if not fully opened.

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.

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

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

Data Analysis: The process through which indicationsrecorded in an ILI 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 strength of the pipematerial.

Detect: To sense or obtain a measurable ILI indicationfrom an anomaly in a pipeline.

Distribution Line: A gas pipeline other than a gatheringline or transmission line (see U.S. Code of FederalRegulations, Title 49, Part 192).2

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

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: Any object detected by an ILI tool during theperformance of an inspection run. Features may beanomalies or indications, pipeline valves and fittings, nearbymetallic objects, or other items.

Gauging Pig: A utility pig mounted with a flexible metalplate, or plates, 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.

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Geographical Information System (GIS): A computersystem capable of assembling, storing, manipulating, anddisplaying geographically referenced information.

Girth Weld: Circumferential weld joining two joints of pipe.

Global Positioning System (GPS): The navigationalsystem utilizing satellite technology to provide a user anexact position on the earth’s surface.

Hydrotest: A pressure test of a pipeline to ensure it meetsdesign conditions and is free of leaks.

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 strengthof the pipe material.

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.

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.

Kicker Line: Piping and valving that connects thepressurizing pipeline to the launcher or receiver.

Launcher: A pipeline facility used to insert a pig into apressurized pipeline, may be referred to as pig trap.

Leak: A small opening, crack, or hole in a pipeline causingsome product loss.

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

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

Mapping Pig: A configuration pig that uses inertial sensingor other technology to collect data that can be analyzed toproduce an elevation and plan view of the pipeline route.

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Maximum Allowable Operating Pressure (MAOP): Themaximum internal pressure legally permitted during theoperation of a pipeline.

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.

Narrow Axial External Corrosion (NAEC): Narrow, deep,axially oriented corrosion, often along a longitudinal seamweld.

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, ultrasonics is anondestructive testing method, while contact shear-waveultrasonic and contact compression-wave ultrasonic arenondestructive testing techniques.

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 Signal: Usually a mechanical sensor on the pipeactivated by the passage of a pig.

Pipeline: That portion of the pipeline system including thepipe, protective coatings, cathodic protection system, fieldconnections, valves, and other appurtenances attached orconnected to the 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.

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Pipeline System: All portions of the physical facilitiesthrough which gas, oil, or product moves duringtransportation, including pipe, valves, and otherappurtenances attached to the pipe, compressor units,pumping units, metering stations, regulator stations, deliverystations, breakout tanks, holders, and other fabricatedassemblies.

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

Receiver: A pipeline facility used for removing a pig from apressurized pipeline, may be referred to as trap.

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

RSTRENG3: A computer program designed to calculate theresidual strength or failure pressure of corroded pipe.

RESTRENG 2: An enhanced version of RSTRENG asspecified in the American Gas Association project reportAGA(1)-PR-218-9205.4

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(2) B 31 G,5 RSTRENG,3 etc.) to the pressure atspecified minimum yield strength (SMYS).

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

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

Smart Pig: See In-Line Inspection Tool.

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

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

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

Transducer: A device for converting energy from one formto another, for example, in ultrasonic testing, conversion ofelectrical pulses to acoustic waves and vice versa.

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 strength of the pipe; or transports gas withina storage field.

Trap: Pipeline facility for launching or receiving tools andpigs. See Launcher and Receiver.

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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Section 3: Tool Selection

3.1 Appropriateness of the Inspection Tool

3.1.1 Representatives from the pipeline operator andthe ILI service vendor should analyze the goal andobjectives of the inspection and match relevant factsknown about the pipeline and expected anomalieswith the capabilities and performance of an ILI tool.Table 1 provides an overview of types of anomaliesand available tool categories, indicating theirappropriateness for the objective of the inspection. Adiscussion of these items follows.

3.1.1.1 Accuracy and detection capabilities of theILI method (i.e., probability of detection,classification, and sizing must match theexpectations) should be evaluated (see Table 1).

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3.1.1.2 Detection sensitivity: The minimumdetectable anomaly size specified for the ILI toolmust be smaller than the size of defect anticipatedto be detected.

3.1.1.3 Classification capability: The ILI toolshould be able to differentiate the targeted defecttype from other types of anomalies.

3.1.1.4 The sizing accuracy should be sufficient toenable prioritization.

3.1.1.5 The location accuracy should enablelocating anomalies.

3.1.1.6 Requirements for defect assessment:Results of ILI must be adequate for the expecteddefect assessment algorithm.


___________________________(1) American Gas Association (AGA), 400 N. Capitol Street NW, Washington, DC 20001.(2) ASME (formerly American Society of Mechanical Engineers) International, Three Park Ave., New York, NY 10016-5990.

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3.2 Operational Issues

3.2.1 Pipeline operators should provide a completedquestionnaire that lists all relevant parameters andcharacteristics of the pipeline section to be inspectedto the ILI vendor (see sample in Appendix A).Operational issues that should be considered arediscussed below.

3.2.1.1 Mechanical characteristics of the pipe

3.2.1.1.1 Pipe characteristics such as steelgrade, type of welds, length, internaldiameter (ID), elevation profile, etc., shouldbe considered. Any restrictions, bends,known ovalities, valves, and unbarred teesthrough which the ILI tool may need tonegotiate should be identified.

3.2.1.1.2 Launchers and receivers should bereviewed for suitability, because ILI toolsvary in complexity, geometry, andmaneuverability.

3.2.1.1.3 Pipe cleanliness should bereviewed as part of planning for an ILI runbecause this can influence tool wear,integrity of data collected, and other issuesthat may affect the success of a run.

3.2.1.2 Characteristics of the fluid pumped

3.2.1.2.1 The type of fluid (gas or liquid)may affect the technology chosen (e.g.,ultrasonic testing [UT] is not practical in gaspipelines without the use of a liquid couplantand some liquids, e.g., ethane, haveunsuitable ultrasonic properties).

3.2.1.2.2 Aggressiveness of the fluid (e.g.,H2S) can limit the tools’ ability to operateeffectively.

3.2.1.2.3 Acceptable ranges of flow rate,pressure, and temperature must meet thevendor’s specifications.

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3.2.1.2.4 The speed of the productinfluences the speed of the ILI toolinspection. If speeds are outside the normalranges, performance can be compromised.

3.2.1.2.5 Reduction of product flow and/orspeed reduction capability of the ILI toolshould be considered for inspection ofhigher-velocity lines. Conversely, theavailability of supplementary product mustbe considered when speeds are too low.

3.2.1.2.6 Extreme (both hot and cold)temperature can also affect tool operationand must be considered.

3.2.1.2.7 The total time necessary for theinspection is dictated by inspection speedand may be limited by the total capacity ofbatteries and data storage capability of thetool.

3.2.1.3 Reliability of the ILI tool. The reliability ofthe ILI method should be evaluated based onanalysis of the following factors:

3.2.1.3.1 Confidence level of the ILI tool,e.g., probability of detecting, classifying, andsizing the anomalies.

3.2.1.3.2 History of the ILI tool performanceverified through excavation.

3.2.1.3.3 Operational success rate andfailed surveys.

3.2.1.3.4 Ability of the tool to inspect the fulllength and full circumference of the pipesection.

3.2.1.3.5 Ability to indicate the presence ofmultiple-cause anomalies (anomalies otherthan those it is primarily designed for, e.g.,the detection of dents by a metal loss tool).

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Section 4: Pipeline ILI Compatibility Assessment

4.1 If analysis indicates that the ILI tool is not suited forthe pipe section in question, the tool selection processshould be revisited to address the specific operationallimitation(s) encountered.

4.2 A typical prerun questionnaire used to compileinformation, to be given to the ILI vendor and whichfacilitates operator record keeping, is included in AppendixA. The following is a more detailed discussion of items.


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ALIPEROOLS

MAPPINGTOOLS

etection no detection




ction,(G)

g

detection,sizing notreliable

no detection


detection no detection


ction,g(H)

detection,sizing

ction,g(B)

detection,sizing(B)(I)

etection detection,sizing

ol, also circumferential position.

ement.

an be used only in liquid environments, i.e.,couplant.

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Table 1: Types of ILI Tools and Inspection Purposes

METAL-LOSS TOOLS CRACK-DETECTION TOOLSMagnetic Flux Leakage (MFL)

ILI PURPOSE Standard-resolution(SR) MFL

High-resolution(HR) MFL

Ultrasonic(compression

wave)

Ultrasonic(shear wave)

TransverseMFL

CT

METAL LOSS (CORROSION)External corrosionInternal corrosion

detection,(A)

sizing,(B)

no ID/OD(C)

discrimination

detection,(A)

sizing(B)detection,(A)



sizing(B) no d

NARROW AXIAL EXTERNALCORROSION no detection(A) no detection(A) detection,(A)

sizing(B)

detection,(A)


sizing(B) no d

CRACKS AND CRACK-LIKE DEFECTS(Axial)

Stress corrosion crackingFatigue cracksLongitudinal seam weld imperfectionsIncomplete fusion (lack of fusion)Toe cracks

no detection no detection no detection detection,(A)

sizing(B)detection,(A)(D)

sizing(B) no d

CIRCUMFERENTIAL CRACKING no detection detection,(D)

sizing(D) no detectiondetection,(A)

sizing(B) ifmodified(E)

no detection no d

detection(F)detection, (F)

sizing notreliable

detection,(F)

sizing notreliable

detection,(F)

sizing notreliable

detection, (F)

sizing notreliable

DENTSSHARP DENTSWRINKLE BENDSBUCKLES In case of detection, circumferential position is provided.

detesizin

GOUGES Detection (A) and Sizing(B)

LAMINATION OR INCLUSION limiteddetection

limiteddetection

detection,sizing(B)

detection,sizing(B)

limiteddetection no d

PREVIOUS REPAIRSdetection of steel sleeves andpatches, others only withferrous markers

detection onlyof steelsleeves andpatcheswelded to pipe

detection onlyof steelsleeves andpatcheswelded to pipe

detection onlyof steel sleevesand patches,others only withferrousmarkers

no

MILL-RELATED ANOMALIES limiteddetection

limiteddetection

detection detection limiteddetection

no d

BENDS no detection no detection no detection no detection no detection detesizin

OVALITIES no detection no detection no detection no detection no detection detesizin

PIPELINE COORDINATES no detection no detection no detection no detection no detection no d

(A) Limited by the minimum detectable depth, length, and width of the defects.(B) Defined by the specified sizing accuracy of the tool.(C) Internal diameter (ID) and outside diameter (OD).(D) Reduced probability of detection (POD) for tight cracks.(E) Transducers to be rotated by 90°.(F) Reduced reliability depending on the size and shape of the dent.

(G) Depending on the configuration of the to(H) If equipped for bend measurements.(I) If the tool is equipped for ovality measur

Shaded area indicates ILI technologies that cliquids pipelines or in gas pipelines with a liquid


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4.3 Tool Environment

4.3.1 The product and the resulting environment thatthe tool is exposed to during inspection are importantfactors in determining which tool should be used.Because tools can be run while the line is in- or out-of-service, consideration should be given to thefollowing:

4.3.1.1 Tethered tools: Some ILI tools areavailable as wireline (tethered) tools, typically usedfor inspecting shorter pipeline sections. Thesetools are connected to a control unit via anumbilical and pumped through a line or pulledthrough the line by tethered cable trucks fromeither end. Tethered tools are used off-line, andusually operate at speeds much lower than theconventional on-line ILI tools (approximately 0.7m/s [1.6 mph, 140 ft/min]). These tools represent avery different operation and should be discussedwell in advance with the vendor.

4.3.1.2 Temperature and pressure: Most toolshave specific temperature and pressure ranges foroperation that should be addressed in advance.

4.3.1.3 Fluid composition considerations: If theproduct contains chemicals such as H2S,modification to the standard tool design should beconsidered to deal with the corrosive properties.Other chemicals may also require adaptation ofthe tool and should be addressed in advance.

4.4 Pipeline Features

4.4.1 Launching and receiving facilities must beadequate for the type of tool. Launchers and receiversmay be installed with new construction or duringmodification of existing facilities and may bepermanent or temporary installations. Considerationshould be given to the following:

4.4.1.1 Work space availability: The work areashould be reviewed to ensure sufficient space formaneuvering tools and associated equipment(e.g., cranes and lifting equipment) during loadingand unloading. Space requirements for any otherancilliary equipment, such as additional pumpingunits, flares, tanks, etc., should be identified.

4.4.1.2 Adequate barrel length: Sufficient roommust be maintained between the door and theisolation valve such that the tool can beaccommodated in that length. For launchers, theoverbore section length should be greater than orequal to the tool length; nominal pipe length canbe kept to a minimum. In cases in which theoverbore section is shorter than the tool length,significant consideration must be given toalternative loading methods such as pulling a toolin. For receivers, the nominal pipe section length

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must be greater than or equal to the tool length toensure the entire tool will clear the isolation valve.The length of the overbore section must besufficient to accommodate the tool stoppingdistance upon receipt. Actual length requirementsmay vary depending on the tool used.

4.4.2 Many mechanical pipeline features present ahazard for ILI tools by damaging or lodging the tools.While the list below cannot account for every type ofpipeline feature that poses a threat, it provides adescription of the most commonly found problematicinstallations.

4.4.2.1 Internal diameter changes (e.g., buckles,dents, bore restrictions, reduced port valves, andcheck valves) can be present in the line for manydifferent reasons and should be addressedbefore the internal inspection. Sometimes thetool is able to negotiate these types ofrestrictions, but each situation should beconsidered on a case-by-case basis.

4.4.2.2 Probes intruding into the pipeline canrestrict inspection tools. Neglecting to removethem can damage the facilities and the tools.

4.4.2.3 A review of areas with knowngeotechnical movement should be considered.

4.4.2.4 Wall thickness is an important parameterfor which some tools need to be calibrated andthus should be considered by the vendor. ILIvendors should be alerted if line wall thickness isless than 6.4 mm (0.25 in.) or greater than 13mm (0.50 in.). Smaller-diameter lines withheavy-wall pipe may severely limit the numberand types of tools that can be successfully used.

4.4.2.4.1 Heavy-wall pipe can lead tospeed excursions when using MFLtechnology in gas lines, e.g., travel through aheavy-wall section can require morepressure differential relative to light-wallsections. Thus, when the tool transitions to alighter-wall section, the larger pressuredifferential can result in an “overspeed.”These “overspeeds” can cause datadegradation.

4.4.2.4.2 Wall thickness changes such asheavy-wall road and rail crossings can posea problem for ILI tools depending on thenature of the transition between the heavy-and light-wall sections. Specifically, “step”transitions present a “cutting edge” for ILItools and can result in damage. Wheneverpossible, “step” transitions should beavoided, and “tapered” transitions should beused.


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4.4.2.5 Short radius bends: The majority ofinspection tools are capable of negotiating a 3-D(3) bend radius or greater. Any bends that aretighter should be addressed on a case-by-casebasis depending on the tool to be used and thewall thickness of the bend. An increasingnumber of tools are capable of passing a 1.5-Dbend radius.

4.4.2.6 Back-to-back bends: Bends installed in aback-to-back configuration, i.e., without anintervening section of straight pipe between thebends, can present an impediment or stickinghazard for ILI tools.

4.4.2.7 Valves: Reduced port valves can result intool damage, and in extreme cases can result inthe tool’s becoming lodged in the line. Closeattention must be given to the ability of tools tonegotiate through check valves. Check valveflappers should be locked in the open positionwhenever possible.

4.4.2.8 Field bends and river crossings shouldbe reviewed thoroughly, because olderconstruction lines may contain tight radius bends,mitres, and step transitions. These locations arepotentially more susceptible to geotechnicalmovement and may have pipeline deformationsthat may not be detected until ILI is attempted.

4.4.2.9 Internal coating can interfere withinspection. Conversely, certain tools candamage internal coatings. Thus, this factor mustbe considered prior to ILI.

4.4.2.10 Sales taps/feeds must be reviewed. Inmost cases, the sales taps and feeds must beisolated as the ILI tool passes. Factors affectingthis decision include size and orientation of tap,amount of flow, single/dual connection (single-connection lines sometimes require theinstallation of additional feeds to salestaps/receipt points), amount of line debris, andtype of tool.

4.4.2.11 Unbarred and back-to-back tees:Branch connections (30% of the pipe diameter orgreater) should have scraper bars; however,larger unbarred branch connections may betolerable depending on tool geometry andorientation. Hot taps, also identified as sharpedges, can present a hazard to the tools. Thedimensions between tees should be reviewedkeeping the specific ILI tool in mind, becauseback-to-back tees can create a situation in whichthe ILI tool stalls. This results when the geometryof the tees, combined with the cup spacing of the

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tool, is such that the propelling product can followa path around the tool without providing anydriving force to the tool.

4.4.2.12 Installations such as mainline dripswithout orifice plates (gas lines), pressure “pots”(crude lines), vortex breakers, chill rings, y-branch connections, and mitre bends can presentproblems for ILI tools.

4.4.2.13 Hydrate precautions: When a line hasthe potential to form hydrates, provisions shouldbe made for their collection, removal, and safedisposal.

4.4.2.14 Pyrophoric materials: Pyrophoricmaterials, particularly iron sulfides, can beproduced from pipelines by the efficient cleaningaction of ILI tools. If pyrophoric materials arepresent, additional vigilance is required to ensurethat fires are not initiated. Provisions should bemade for the collection, wetting, removal, andsafe disposal of pyrophoric materials.

4.4.2.15 Facility piping and dimensions: Pipingconfigurations including, but not limited to, thefollowing should be reviewed to facilitateoperations required for ILI:

4.4.2.15.1 Kicker line sizing may vary bydiameter and service. However, in the caseof gas transmission lines, the amount of gasavailable should be sufficient to propel a toolif the speed control fails in the open position.For liquid service, kickers should be sized toaccommodate acceptable full-rate pressuredrop and within corporate erosion limits.

4.4.2.15.2 Appropriate location and sizeof fittings: Blowdowns (and silencers ifrequired), equalization, draining, and purgingconnections should be ensured.Connections should be such that the pipingbetween the launcher isolation valve and thereducer can be vented to ensure tools arenot propelled backwards during the periodbetween loading of the tool and pressurizingthe launch barrel prior to starting ILIoperations. Any requirements for flaringshould be considered at this stage.

4.4.2.15.3 Eccentric versus concentricreducers: Eccentric reducers allow foreasier loading and unloading of the tool fromthe barrel. Vertical launchers should useconcentric reducers without hold-up rings.


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(3) D = pipeline diameter.

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4.4.2.15.4 Pig passage indicators shouldbe installed on both the upstream anddownstream sides of the isolation valve. Ifthese are not available, an alternate methodsuch as a compass for magnetic tools shouldbe used to ensure tool passage.

4.5 Product, Product Flow, and Speed Requirements

4.5.1 The type of fluid should be considered forseveral reasons. Some services can damage a tool.Sour service is an example in which failure to informthe ILI contractor of the substance present in the lineduring the survey can result in costly repair to the tool.Any chemical other than oil, sweet gas, odorant, orwater should be reported to the vendor for toolsuitability verification.

4.5.2 Insufficient product flow: Liquid lines usuallyoperate at low enough speeds that ILI does not resultin a throughput restriction. This can result in theconverse problem in which normal product flow mustbe supplemented. When low-flow liquid lines areinspected using an MFL tool equipped with inductioncoils, the normal pipeline flow may need to besupplemented with additional product to achieve theminimum required inspection velocity.

4.5.3 Restricting normal product flow: The schedulingof any inspection should be coordinated to ensurethat capacity restrictions, batching (e.g., liquid lineswith multiphase liquids or gas pipelines), etc., arecoordinated with customers and other concernedparties. A liquid products pipeline operator may notbe willing to accept the risk of product contaminationby running an ILI tool in certain critical batches, e.g.,aviation fuel. Line conditions should be set up suchthat the tool speed is maintained in the optimal rangefor data collection.

4.5.4 Velocity-controlled tools: Gas lines oftenoperate at speeds well in excess of the maximumallowable in-line inspection speeds. This is a primaryconsideration for magnetic flux tools in gas lines.

4.5.4.1 Variable bypass (speed control),available on certain tools, should be used toaddress this issue. The use of this featurerequires a more complicated procedure, e.g.,lengthening of the tool, and limits the bendcapability of tools. The ramifications of usingvariable bypass should be considered carefully.

4.5.4.2 In some cases, “fixed bypass” is put intoa tool to reduce the inspection speed and keepdebris “loose” and circulating. The addition offixed bypass should be done with caution. Incertain situations, the addition of too much “fixedbypass” could result in insufficient drive to movethe tool along the line. All these factors must beassessed and weighed against the need to

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reduce product throughput and the possible needto flare.

4.6 Surveys

4.6.1 MFL surveys can be conducted in either gas orliquid lines assuming that line velocity is within thetool specifications. Product composition should beconsidered.

4.6.2 UT surveys: Liquid lines are best suited for UTtools because the product itself provides the couplingbetween the tool sensors and the pipe wall. Suitabilityof liquids for UT inspections must be verified prior toan inspection run.

4.6.2.1 In gas lines, UT tools must be run in aliquid medium to perform the survey, because theproduct actually acts as a barrier to the UTsignals. This may be accomplished either bytotal displacement of the line to a liquid orencapsulating the UT tool in liquid within a liquidslug or batch. If liquid volumes can be handledreasonably, the line should be completely filledwith liquid. The UT should then be propelled withthe same liquid.

4.6.2.2 If only a limited supply of liquid isavailable, UT tools should be run in a “slug” ofliquid. This method requires in-depth planningand should include the following factors:

(a) Alternate choices for UT surveys,(b) Elimination of gas entrapment,(c) Gas contamination due to bypass from thedriving gas,(d) The amount of liquid that will be lost tovalves, take-offs, lateral lines, etc., along the line,and(e) Adequate velocity control of the slug.

4.6.3 Pipeline geometry (caliper or gauging pig)surveys

4.6.3.1 A caliper or bend tool should be run inthe pipeline prior to an ILI tool. The purpose ofthis inspection is to (1) provide detailed data toprove the pipeline bore, (2) to evaluate the bendradii to ensure passage of the ILI tool, and (3) toobtain as much information as possible prior tosending in the more expensive and less flexibleILI tools. Lines that are good candidates forcaliper surveys are those not previouslyinspected, lines with repairs between surveys,lines subject to high risk of third-party damage,and lines subject to a high geotechnical risk.

4.6.3.2 A response plan to the caliper/bend datashould be developed to handle potentialrestrictions that could be discovered.



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4.6.3.3 If pipeline bend and bore information iscurrent and reliable, a gauging plate pig ordummy tool may be used instead. The dummytool should be designed to mimic thecharacteristics of the live tool. The purposes ofthe dummy run are to assess the potential for livetool damage by observing the condition of thedummy tool after the run and to provide anopportunity for field personnel to practice safeand proper handling and operation techniquesprior to running of the live tool. A successfuldummy run should improve the likelihood that thelive run will be successful.

4.6.3.4 Benchmarking or tracking should be usedduring the caliper/bend inspection. Somecaliper/bend tools with inertial mappingcapabilities that allow the information to becorrelated with global positioning systems (GPS)are available.

4.7 Pipeline Cleanliness

4.7.1 When warranted, a cleaning program for thepipeline should be designed and implemented. Thespecific pigs for cleaning the pipeline should beidentified.

4.7.2 Historical data should be evaluated foranticipated contaminant deposits such as scale, dust,paraffin, etc.

4.7.3 The results of regular maintenance piggingactivities in the pipeline aid in the cleaning programdesign. Lines with regular maintenance piggingprograms may require less cleaning before ILI toolinspections are conducted.

4.7.4 ILI service providers should provide guidelinesfor cleaning requirements.

4.8 Information Gathering

4.8.1 The following procedure should be used toassess pipeline compatibility:


4.8.1.1 As-built drawings should be reviewed toidentify physical restrictions. If this information isinadequate, gauging or caliper pigs should berun.

4.8.1.2 It is important to provide as muchinformation as possible to the vendor to avoidunforeseen problems and/or delays in the toolrun. To facilitate this, a pipeline questionnaire,usually provided by the vendor, should becompleted (see Appendix A).

4.8.1.3 Cleaning specifications should bediscussed with the vendor. If there is no cleaninghistory available for the pipeline, a suitabilityassessment should be made after eachprogressive cleaning run is completed.

4.8.1.4 In older installations, anecdotalinformation at the field level should be obtainedas an additional source of information regardingthe compatibility of a pipeline.

4.8.2 Additional information that should be used toensure the appropriate tool setup (both mechanicallyand from a software perspective) is used forinspecting a specific line includes the following lists:

(a) Internal review of documented sources• Drawings, survey books, and sample prerun,• Weld tallies and joint length records,• Purchasing records,• Caliper survey run results,• Routine pigging run data,• Gauging plate runs,• Bellhole inspection surveys or prior repair

records, and• Third-party construction activity records.

(b) Site visits• Gathering of anecdotal information from

operational staff, and• Facility visit for vendor and operator.

(c) Other sources• Previous inspections.

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Section 5: Logistical Guidelines

5.1 Primary Contracting Considerations

5.1.1 Contracting for ILI work is a significant effort.The roles of the vendor and owner/operator should bedefined for all aspects of the work fromimplementation to delivery of the final report. Thevarious stages of reporting and payment schedulesassociated with milestones should be laid out. Factorssuch as the implications of reruns, schedulingchanges, and service interruptions should beaddressed.

5.1.2 Definition of scope of work

5.1.2.1 The scope of work should be defined wellin advance of any pricing discussions and/orcontracting. The scope of work should addressall aspects of field operations including:

(a) Project specifications for data analysis,(b) Roles and responsibilities, e.g., transporting,loading, cleaning, and tracking of tools,(c) Related manpower,



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(d) Any quality assurance issues and/ormethods of ensuring quality,(e) Specific deliverables regarding corrosionsizing, shape, probability of detection, confidencelimits, etc., and(f) Impact of deliverables on data analysis forthe specific line and resulting calculations.

5.1.3 Liability issues

5.1.3.1 Liability issues should be fully addressedin the contract documents. This includes itemssuch as replacement costs, tool handling,custody transfers, and related clauses.

5.1.3.2 Tool damage issues should be laid out inthe contract documents. Values for mostcommonly occurring types of damage should bedefined. Point of custody transfer should also bediscussed.

5.1.3.3 Clarification of liabilities and responsibilityfor tool retrieval (monetary and logistical) as wellas the process for determining the cause oflodging the tool must be addressed in thecontract.

5.1.3.4 All stakeholders should be aware of thepossibility of stuck tools, and discussion/development of an action plan for tool retrievalshould be in place if the event actually occurs.

5.1.4 Conformance to local, operator, andgovernment regulations

5.1.4.1 The contract shall include specificwording to address health, safety, andenvironmental (HSE) standards and anycompany-specific guidelines that may go aboveand beyond the standard industry practice.

5.1.5 Survey-acceptance criteria

5.1.5.1 A set of survey-acceptance criteriashould be developed and agreed to by bothparties prior to the start of the ILI survey. Thesecriteria help to define when a rerun survey isrequired and include the following:

5.1.5.1.1 Physical damage to sensors afterrun: The tool should be visually examined assoon as possible following the run to give aquick indication of the potential need for arerun. While sensor damage can occur atany point along the line, severe signs ofwear on surfaces normally not exposed tothat type of damage are an indication thatthe damage occurred early in the run andthat significant information may not havebeen collected. The field log or datasummary should be reviewed to confirm the

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time of the damage and the impact of thatdamage on data collected.

5.1.5.1.2 Lost sensor channels on data:When a field or preliminary log is reviewed,those channels that have stopped obtainingdata should be readily evident. Loss ofchannels may be acceptable, especially incases in which lost channels are notadjacent. Depending on the total number ofchannels on the tool, losses of 1 to 5% maybe tolerated. Lines that have beeninspected previously and have a goodhistory may tolerate sensor loss near theupper limit. Lines that have never beeninspected or lines that have significantintegrity concerns may not tolerate even a1% loss.

5.1.5.1.3 Sensor noise: Damaged sensorsor bad electrical connections may make achannel noisy, thus creating signals thatmask out adjacent good data channels.Noisy channels are also readily evident onthe log and should be addressed in amanner similar to lost channels.

5.1.5.1.4 Distance inaccuracy: Inaccuratedistance recording can create significantproblems when operators are trying to locateanomalies for verification or repair. If thetotal line length varies by more than 1% fromthat recorded by previous ILI, a rerun shouldbe considered. For longer lines, particularlythose longer than of 100 km (62 miles),distance variation tolerances should bereduced to between 0.25% and 0.5%.

5.1.5.1.5 Missed or not recorded features:Small line features such as pressure gaugefittings, small bore vents and drains, andother taps and fittings 25 mm (1.0 in.) or lessin diameter may not produce large signals,particularly when they fall between or acrosstwo sensors. Missing such features shouldnot warrant a rerun. Missing known flangesets, valves, or large bore tees brings theveracity of all log information into question.

5.1.5.1.6 Velocity underruns or overruns:When tool velocities exceed the vendor’supper and lower limits, data loss can beexcessive. Surging in gas or in crude lineswith high gas content is often responsible forvelocity excursions. If the total line distanceaffected by the excursions exceeds 1 to 2%,a rerun should be made. However, the rerunshould not be conducted until the processparameters that led to the velocity problemscan be addressed and modified to ensurethat the rerun survey is conducted within the


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tool’s velocity limits. If data with knownvelocity excursions are accepted, the effectof the over-speed on data degradation(acquisition and sizing) must be defined toallow effective management of the issue.

5.2 Post-Run Operational Report

5.2.1 Requirements for the post-run operationalreport should be defined up front and should includeitems such as:

(a) Pipeline name,(b) Date of run,(c) Type of run,(d) Length and diameter of run,(e) Any significant tool modifications for run,(f) Average speed of run and/or speed profile,(g) Run success failure, and(h) If failed, reason for failure (and associatedremedial work).

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5.3 Data Specifications

5.3.1 Data analysis specifications are discussed indetail in Section 9 and should be defined andunderstood by both parties before work is begun.

5.4 Reporting Schedule

5.4.1 The timeline for preliminary and final reportdeliverables, including exceptions such as longer linelengths or heavily corroded lines, should beestablished.

5.5 Verification Requirements

5.5.1 Any expectations of both parties for correlationexcavations to verify the data should be established inadvance.

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Section 6: Inspection Scheduling

6.1 Factors that should be considered when schedulingthe inspection include the following:

6.1.1 Access to sites

6.1.1.1 Consideration should be given not only tolaunch/receive site access, size and groundcondition, but also to tracking locations. Trackinglocations may be affected by length of daylight,wildlife corridors, weather, and otherenvironmental and safety issues.

6.1.2 Throughput/outage considerations (includingreruns)

6.1.2.1 Scheduling should account for systemcapacities and their effect on tool speeds andperformance.

6.1.2.2 The timing of any resulting excavationsshould be considered as part of the planningprocess. This includes coordination with otherrelated and unrelated outages on the system.

6.1.3 Manpower

6.1.3.1 The amount of manpower requiredshould primarily be dictated by the location of therun, the complexity of the run procedure, and anyenvironment and safety issues. As with anyother field operation, the clarification of roles andresponsibilities should be part of manpowerplanning.

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6.1.4 Inspection run time

6.1.4.1 Each inspection tool has limitationsregarding the amount of pipe that may beinspected in a single pass. These limitations area function of battery life and data storagecapacity. The nonhomogenous nature ofseamless pipe or spiral weld may result in higher-than-average signal density that consumes datastorage capacity more rapidly than pipe of a morehomogeneous material, such as ERW. Forlonger pipe segments, multiple runs may berequired in order to obtain a complete inspection.

6.1.5 Land and access

6.1.5.1 Landowner issues may be involvedduring tool tracking operations and possiblyduring launch and receive operations as well. Inpopulated areas, silencers may be required ongas lines due to noise restrictions. There may beadditional concerns in crossing aboriginal orotherwise “protected” lands.

6.1.6 Environmental

6.1.6.1 Plans should be made for handling anywaste during tool runs. Permits may be requiredfor transportation of hazardous material as wellas for accessing the pipeline rights-of-way in orthrough environmentally sensitive areas.



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6.1.7 Procedural

6.1.7.1 Pumping with liquids obtains bothoperational predictability and consistent toolspeeds. This requires planning such thatcustomer impacts are minimized while good dataare collected from the inspection. Procedures forpumping with liquids should consider the majorfactors listed below.

(a) Supplemental flow (see Paragraph 4.5),(b) Dissolved gas in fluid,(c) Purging/draining,(d) Pyrophoric materials wetting, collection, anddisposal (see Paragraph 4.4.2.14), and(e) Freezing conditions: When water must beused as a propulsion fluid, ILI surveys should bescheduled during months when freezing cannotoccur. If this is not possible, provisions should bemade to address possible freezing of equipment.

6.1.7.2 Procedures in gas lines have the sameobjective as procedures in liquid lines: tomaintain both operational predictability andconsistent tool speeds. In gas lines, there is anadded level of complexity resulting from thechallenge of dealing with a compressible fluid.Factors to consider include:

(a) Speed control,(b) Fluids in normal gas service lines,(c) Launch,(d) Receive, and(e) Flow conditions.

6.1.7.3 Pigging bidirectional lines

6.1.7.3.1 Some lines are piggable in morethan one direction. Subsequent ILI surveysshould be run in the same direction as thefirst to simplify the tasks of featurecorrelation and field chainage. In thismanner, an anomaly downstream from agiven valve is always downstream from thatvalve, not downstream on one log andupstream on the next, etc.

6.2 Resourcing (Manpower and Equipment)

6.2.1 The speed of the tool and the length of the runshould be primary considerations in determiningmanpower numbers. Manpower in the pipelineoperation control center should also be considered,because outages and procedures can involve morecoordination of effort than is supported at normalstaffing levels.

6.2.2 Access for heavy equipment (crane and/orpicker truck) should be considered for launcher andreceiver sites. Access to nearby workshop and tool


cleaning facilities for the vendor are typically alsorequired.

6.2.3 Pumping equipment sizing

6.2.3.1 When pumping equipment, as either solepropulsion or supplemental propulsion source, isrequired, the equipment should be sized toreduce the potential for failure during operation toa minimum.

6.2.3.2 Equipment should not be run over 80%of design capacity. Although most tools will“power down” if stopped for a sufficiently longtime, battery capacity can be a concern in longerlines.

6.2.3.3 Time spent stationary in the line while apump is repaired may impact the ability of thetool to collect data over the entire line. When thedischarge capacity of a pump is near itsmaximum, at the minimum required flow rate forthe tool, any decrease in pump efficiency coulddrop the tool below the minimum velocity. If thisis not detected the entire line may be run with noacceptable data acquired. In these cases, twopumps should be run at 75% capacity to avoidthe possibility of the tool velocity’s droppingbelow the minimum.

6.2.4 Liquid storage

6.2.4.1 When liquid must be used to propel anILI tool, a minimum of 10% and preferably 25%excess over the calculated line fill volume shouldbe on hand to cover bypass, passing isolationvalves, unknown take-off fill volumes, and othercontingencies.

6.2.5 Slops collection

6.2.5.1 When ILI surveys produce nonnormalprocess fluids, i.e., liquid from a gas line or high-solids content product as a consequence ofdebris removal, provisions must be made forcollection of this slops volume. Temporarytankage and piping connections may be requiredto divert and collect the material.

6.3 Benchmarking and Tracking

6.3.1 Use of GPS

6.3.1.1 Use of a GPS should be considered tofacilitate and document ILI surveys. GPS isuseful in reestablishing AGM benchmarklocations that may become destroyed byunrelated activities or encroachments on theright-of-way. Because GPS uses a coordinatesystem independent of pipeline stationing orother traditional land-based coordinate systems,



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errors in pipeline stationing should be identifiedand corrected.

6.3.1.2 GPS offers an easy method ofdocumenting all related ILI information in a singlegeographical reference format. This facilitatesthe integration of the collected ILI survey datainto pipeline GIS.

6.3.2 Surveying/benchmarking

6.3.2.1 Benchmarks are discrete survey pointsalong the pipeline route for placing referencemarkers. These markers are either permanentlyattached to the pipeline (magnets, for example)or portable aboveground marker systems (AGM).Readily identifiable permanent pipelineinstallations, such as valves, are also used asbenchmarks. If AGMs are used, special careshould be taken to ensure that the pipeline coverdoes not exceed the maximum allowable depthfor the AGM at the benchmark locations. If anAGM is placed on or above a casing, it may notdetect the passage of the ILI tool.

6.3.2.2 Tracking locations should be establisheddownstream from pipeline appurtenances,intermediate booster stations, and procedurallysignificant locations to ensure the pig negotiatesand clears all in-line facilities.

6.3.2.3 The purpose of benchmarking is tocorrect for measured distance inaccuraciescaused by ILI tool odometer wheel slippage andsignificant changes in topographic elevationsalong the pipeline route. Benchmark locations onthe pipeline are usually spaced at certainminimum intervals, typically 1 to 2 km (0.6 to 1.2miles). Closer spacing provides a more accuratelocation definition. Benchmarking providesreference points for tracking the ILI tool andmaintaining its appropriate speed as itprogresses through the pipeline. It also providesreferences for use in surveying the location ofexcavations. Benchmarks should be placed ineasily accessible locations on the pipeline route.

6.3.2.4 Benchmark locations should besurveyed, well documented, and maintained aspart of the permanent pipeline record.

6.3.3 Pig Tracking

6.3.3.1 An adequate number of individualstrained in the use of pig-tracking equipment,tracking calculations, line-finding equipment, etc.,should be available.

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6.3.4 Transmitters for tracking

6.3.4.1 When an electronic transmitter is usedfor tracking purposes, the proper mounting andoperation of the device should be verified prior tolaunch. The device should be well secured andshould not affect the bend-passing capability ofthe tool. MFL tools do not necessarily requiredevices, because the tool passage may bemonitored using the magnetic fields generated bythe tools.

6.3.5 Tracking milestones

6.3.5.1 The pipeline operations control centershould be updated at the following times:

(a) When the tool is ready for launch.(b) When the tool has been launched andtracking is under way.(c) Any time irregularities are noted in the flowor pig travel.(d) In advance of scheduled changes in pipelineflow conditions as identified in the inspectionprocedure.(e) At regular intervals to confirm the pigposition and that the tracking personnel are notincapacitated.(f) Several times in advance of the pig arrival atany intermediate booster station, pig signal, orreceiving location.(g) When the pig has been received, and thepipeline can be returned to normal operation.

6.3.6 Mechanical detection devices

6.3.6.1 There are a number of mechanical pigpassage indicators on the market. Most areintrusive and are activated by physical contact ofthe pig with a protruding toggle. Recently,magnetically activated nonintrusive detectiondevices have come on the market. Thesedevices require that a magnetic source bepresent in the ILI tool but have the benefit ofbeing nonintrusive and are therefore portable.Thus it is conceivably possible that one devicecould be used to monitor the passage of a toolalong a line by confirming passage at onelocation and then moving the device to the nextlocation along the line to confirm arrival andpassage.

6.3.7 Monitoring passage at surface features

6.3.7.1 As ILI tools move through a line, theirpassage can normally be monitored at locationswhere the line comes above grade, such as atline breaks, isolation valves, or line ties in risers.If the ambient noise levels in the area arerelatively low, ILI tool passage can be readilyheard.



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6.3.8 Marker activation (AGMs)

6.3.8.1 A number of ILI tool vendors now havesome form of portable marker system. Thesemarkers are time-synchronized with the tool priorto launch. These not only detect passage of thetool but are also used to locate the tool’s relativeposition on the log through time comparison.

6.3.9 Liquid volume monitoring

6.3.9.1 When ILI tools are propelled with a liquidand the total fill volume of the line is relativelywell known, the approximate position of the tooland arrival times at given locations can bepredicted by monitoring the volume of liquiddischarged to propel the tool.

6.3.10 Initial subsea surveys

6.3.10.1 If an ILI inspection of an existing subsealine is being conducted for the first time,placement of magnets, markers, or other devicesat regular intervals along the line to provide


position indications may be a costly exercise.The cost of such placements should becompared to the cost of a line rerun. It mayprove more economical to run an ILI survey tofind out whether there is evidence of corrosion orother anomalies that appear to require follow-upexamination. Placement of fewer magnets ormarkers, bracketing the suspect area, can thenbe arranged. A rerun survey, which will showboth the anomaly indication and new indicationsfor the magnets or markers, can then beconducted.

6.4 Contingency Planning

6.4.1 A contingency plan should be considered todeal with the possibility of lodging an inspection tool inthe line. The plan should cover aspects such as linesof communication, operational actions that could beused to dislodge the tool, interruption of service, andremoval of the tool by means of a cutout. Thecontingency plan should also consider the possibilityof a failure of the run (either due to the tool or lineconditions) and whether a rerun would be possible.

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Section 7: New Construction—Planning for ILI Surveys

7.1 Planning for ILI surveys should begin with systemdesign. Inclusion of ILI-compatible facilities in theconstruction of a new line is much more economical thanattempting to retrofit those same facilities several yearsinto the life of a line. Inclusion of some items in theoriginal design, such as the installation of short puppieces, adds very little to the overall cost of a projectduring construction, but may be economically cost-prohibitive once the line is commissioned (see Paragraph7.2.7). Components other than a launcher and receivermust be added to make a line ILI-compatible. Often thoseadditional components have long delivery lead times. Theparagraphs below address some of the more costly orsignificant items that should be considered when planningfor and constructing a new line to be ILI-compatible.

7.2 Materials

7.2.1 Multiple-diameter line pipe

7.2.1.1 There are a number of different situationsin which the installation of multiple pipe diameterswithin a single pipeline is a viable alternative to asingle-diameter pipeline. However, thisconstruction method can pose significantobstacles to future ILI surveys. The use ofmultiple pipe diameters should be avoidedwhenever possible. If there are no alternatives toa multiple-diameter line, the line should beinstalled using the following guidelines.

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7.2.1.1.1 ILI tools are available to coverincreases or decreases of one-line sizediameter. When line segments between asingle launcher and receiver are dual-diameter, the diameter change must berestricted to one line size, e.g., 560 and 610mm (22 and 24 in.) or 610 and 660 mm (24and 26 in.).

7.2.1.1.2 If design criteria are flexible,contact with ILI vendors prior to diameterselection may increase the number ofvendors capable of providing the multiple-diameter inspection service.

7.2.2 Offshore platforms may be fabricated in theyard with all anticipated future pipeline risers installed.Often, a single riser diameter is chosen forsimplification of construction, and the diameterselected may be larger than that required by the finalpipeline design.

7.2.2.1 Because the cost of retrofitting newrisers, particularly risers installed inside theplatform structure, can be quite high, the originalrisers are used, resulting in a mismatch betweenthe riser and the pipeline diameters. Thismismatch may make the line impossible toinspect. To avoid this problem to the greatestextent possible, risers should be sized to matchthe anticipated pipeline size closely. When thepipeline is constructed, strong consideration



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should be given to increasing or decreasingdiameter to match the installed riser. The cost ofdoing so is more than recovered with the ability toclean and inspect the line successfully to detectpotential defects prior to failure.

7.2.2.2 Although dual-diameter tools areavailable on the market, not all vendors havetools to cover all the possible combinations. Thismay lead to a restricted vendor list for certainsurveys. Additionally, even if the operatorconsiders that a line is one continuous pipeline,the ILI vendors may charge for the use of multipletools. The resulting overall cost for the inspectionof the multi-diameter line is greater than the costof a single-diameter line of the same length.

7.2.3 Valves

7.2.3.1 Whenever possible, valve bores shouldclosely match the pipeline bore. For long large-diameter pipelines, mainline isolation and linebreak valves can represent a significantexpenditure. To help reduce that expenditure,smaller-diameter valves may be specified, e.g.,1.0-m (40-in.) valves may be used in a 1.1-m (42-in.) line. The potential cost savings availablefrom such a selection must be weighed againstincreased costs for ILI surveys and theassociated risk of speed excursions affecting ILItool data collection.

7.2.3.2 Smaller-diameter mainline valves shouldbe addressed in a fashion similar to that usedwith multiple pipe diameters.

7.2.3.3 If check valves are to be used, “through-conduit” (i.e., full-bore) check valves with flappersthat can be locked in the open position should beselected whenever possible.

7.2.4 High-yield-strength bends and fittings

7.2.4.1 While it may be relatively easy to orderline pipe in high yield strengths, bends, tees,reducers, and other fittings may not be so readilyavailable. Long lead times are often required forprocurement of fittings to match the line pipeyield strengths. Failure to allow adequate leadtime often results in heavy-wall lower-yield fittingsbeing used as substitutes. The use of heavy-wallfittings should be balanced against themodification of ILI tools to facilitate inspectionand potential requirement to use specializeddual-diameter tools. Use of heavier-wall fittingsalso results in a higher risk of unavoidable speedexcursions (causing degradation of data) andstuck tools.

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7.2.5 Bends and bend radius

7.2.5.1 A significant number of currentlymarketed ILI tools can negotiate bends with radii3 D or larger. Some tools may negotiate 1.5-Dbends.

7.2.5.2 Prior to placing an order for bends, thecompatibility of those bends for ILI must beverified. Wall thickness of bends becomescritical as the radius of the bend becomes tighter.

7.2.5.3 CAUTION: The smaller the diameter ofthe line to be inspected, the larger the bendradius required to accommodate the ILI tool.Smaller-diameter tools incorporate multiplesegment designs and the “hard body” ormaximum segment diameter is a greaterpercentage of the available line pipe internaldiameter. Greater bend radii should allow the ILItool to pass without damage or without becomingstuck.

7.2.6 Consistent wall-thickness pipe

7.2.6.1 If MFL tools are used for inspection,attention should be given to ensuring thatsufficient pipe of one wall thickness is available tocomplete the construction. Short sections ofheavy-wall pipe for road or railroad crossings, orfor risers into and out of facilities with differentdesign factor requirements are not a majorconcern; however, significant wall-thicknesschanges may restrict the tools that can be usedto inspect the lines or cause unavoidable speedexcursions leading to degradation of data.Heavy-wall fittings pose a higher risk of theseproblems.

7.2.7 “Pup” joint installation

7.2.7.1 To reduce the number of AGMs requiredfor a survey or to reduce the negative impact of afailed or undetected AGM unit, significantlyshorter-than-average “pups” should be installedat regular intervals following the methoddescribed below. Alternative methods such asthe use of magnets can also be considered in theappropriate situations.

7.2.7.2 When feasible, “pup” joints 1.2 to 1.7 m(4 to 6 ft) in length should be installed every 2 km(1.2 miles) along a line. This limits the distancethat must be chained to a maximum of 1 km (0.6mile), i.e., one-half the distance between two“pups.”

7.2.7.3 The location of the upstream ordownstream weld of each “pup” can be markedeither on the surface or through theestablishment of GPS coordinates prior to burial.



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7.2.7.4 Similar installations should be made forsubsea lines; however, a little morepreinstallation planning is required. Lay bargesnormally work with fixed distances betweenwelding station locations, making the installationof short “pup” sections difficult. The followingprocedures should be used for subsea lines:

7.2.7.4.1 The “pup” joint must be preweldedto a longer joint so that the combined lengthof the two falls within the welding stationspacing.

7.2.7.4.2 Composite joints (i.e., standardlength joints composed of pup joints) shouldbe made in advance and installed at presetregular spacings approximately every 2 km(1.2 miles).

7.2.7.4.3 Depending on the configuration ofthe lay barge stinger, it may be possible tomark a “pup” joint girth weld for futureunderwater identification with a stainlesssteel plate attached with polymer fabric ropeor stainless steel banding prior to the joint’sleaving the barge. If it cannot be guaranteedthat the marker can successfully pass thestinger, the weld should be temporarilyidentified, and divers or remote operatingvehicles (ROV) should install the permanentidentification at a later date.

7.3 Collection of Construction Information

7.3.1 During construction, records of the lengths ofjoints installed, radiograph identification, and anynumber of related pieces of information that will be ofvalue during future ILI surveys should be routinelykept.

7.3.2 GPS coordinates may be obtained for everyweld along the line as it lies in the trench prior toburial.

7.3.3 All documentation should be collected and filedin a common location and maintained for the life of


the pipeline. Current technologies may allow thelarge volumes of material to be reduced significantlythrough scanning and subsequent storage in anothermedia format. Regardless of the format, constructiondata are a valuable asset and they should besafeguarded for future reference. When possible, it isideal to incorporate this information as part of a GIS.

7.4 Baseline Surveys

7.4.1 True baseline ILI surveys, i.e., those conductedprior to or very shortly after the start of service, offer anumber of benefits that may significantly reduce theworkload required following future surveys, but arenot required.

7.4.2 A caliper or metal-loss survey can beconducted as part of the preservice work. If asufficient fill rate can be obtained, the caliper may becompleted as the pipeline is filled with water for thepreservice hydrotest. Alternatively, other propulsionmethods such as compressed air may be used.

7.4.2.1 An additional benefit of a baseline ILIsurvey in conjunction with the hydrotest is thedata obtained can be used to confirm theconstruction contractor’s delivery of the systemas required by the contract.

7.4.3 Gauging-plate or deformation-tool surveys canbe run first with compressed air.

7.4.4 The pumps used to fill the line must be capableof maintaining the required flow rate for inspection.

7.4.5 Sufficient water must be available to fill thesection in question. With the arrival of the ILI tool, notonly is the line filled for hydrotest but the baselineinformation on line condition is obtained.

7.5 Repair Records

7.5.1 If repairs are made to a pipeline duringconstruction following a baseline survey or hydrotest,the location of these repairs should be recorded andincorporated into the permanent pipeline records.

________________________________________________________________________

Section 8: Data Analysis Requirements

8.1 Data Analysis Methodologies

8.1.1 General components of ILI data analysis

8.1.1.1 After the raw data collected areconsidered “acceptable,” the ILI service companyshould take the data, analyze them, and producea report.

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8.1.1.2 The ILI service company should haveapplicable algorithms and software to analyze thedata. The results of the analysis should be withinthe tool specifications for detection capabilities,accuracies, confidence intervals, minimumdetection levels, and the detection thresholds.

8.1.1.3 The priorities and criteria for anomalies ofconcern should be predetermined as part of theinspection contract and pipeline operator integrity



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plan or code, taking into account the limitations ofthe inspection tool. The discussion shouldinclude definitions and clarification regardingdefect geometry, probability of detection, sizing,and tool specifications as they relate to thesecriteria. For cracking, this is typically based onpredicted crack depth or a combination of depthand length. For corrosion, pressure calculationsshould be carried out using ASME B 31 G,5

RSTRENG,3 or other assessment algorithmappropriate for the detail of ILI data available.For dents and dent-like anomalies, codesnormally indicate any anomalies that exceed acertain threshold must be removed. Thediscussion should include definitions andclarification regarding defect geometry,probability of detection, sizing, and toolspecifications as they relate to these criteria.

8.1.1.4 Correlations should be made betweenfield assessment information and ILI data. Allaccuracy errors associated with fieldmeasurement and ILI data must be taken intoaccount in integrity assessment and planning.

8.2 Pipeline Features Listed and Reported

8.2.1 The detection, classification, and sizingcapabilities of nondestructive evaluation techniquesdepend on the type and characteristics of the pipelineanomalies. Any given feature can have a largevariety of shapes. Features should be classifiedaccording to their shape and other potentialcharacteristics, e.g., profile.

8.2.2 For a given feature type, the probability ofdetection (POD) should be defined as a statisticalprobability of positively detecting that type of feature.(Recommended values should be stated for POD =90%.)

8.2.3 The reported features should be those that arespecified as being able to be found with a giventool/technology specification. The format, level, andmethod of reporting should be predetermined as partof the contracting process. The following elementsshould be universally reported by all serviceproviders:

(a) Odometer distance (also called “absolutedistance”),(b) Upstream reference girth weld identifier,(c) Feature type and identifier,(d) Circumferential (clock or degree) position,(e) Distance to upstream girth weld (also called“relative distance”),(f) Odometer distance of upstream benchmark,(g) Odometer distance of downstream benchmark,and(h) Feature specific details (see Paragraph 8.4).


8.2.4 More details of features reporting may be foundin the document developed by the European PipelineOperators Forum, “Specifications and Requirementsfor Intelligent Pig Inspection of Pipelines.”6

8.2.5 Anomaly location

8.2.5.1 Nearby features and benchmarks

8.2.5.1.1 When an anomaly on an ILI log isrequired to be located for examination, thelocation of the anomaly should always bereferenced from readily identifiable featuresor benchmark locations, such as surfacevalve, marker magnet location, abovegroundmarker location, take-off, flange set, anunderground short joint, or a heavy-wall pipesection.

8.2.5.2 Surface chaining

8.2.5.2.1 It must be recognized that surfacechainage of distance along a pipeline maynot match the distance the ILI tool travelsinside the pipeline. Ground surface profiledoes not always mimic the actual pipelineprofile. It is often advantageous to chainfrom both an upstream and a downstreamreference feature or benchmark to bracketthe anomaly location.

8.2.5.3 Short joint excavation

8.2.5.3.1 Short pup joints may be locatedthroughout the pipeline either intentionallyinstalled during construction or as the resultof tie-ins, make-up, or a repair. If short jointsare close to the location of the anomaly to beexamined, they may be used in the samemanner as any nearby reference feature.Remember, there may be more than oneshort joint in a particular location, andconfirmation of the joint length is essential toensure the correct joint is used to chain tothe anomaly.

8.2.5.4 Excavation of affected joint

8.2.5.4.1 Even after chaining an anomalylocation using nearby reference features, it isstill possible to be on the wrong pipe joint oron the wrong weld of the affected joint.Therefore, the length of the pipe joint shouldbe verified before an attempt is made tomeasure out to the anomaly location. Thismay be accomplished by excavating theentire joint or just the girth welds of the joint.Additional assurance may be obtained byverifying the orientation of the pipe long-seam weld or spiral weld when it is available.



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8.3 Geometry Tool—Specific Analysis and PrioritizationMethods

8.3.1 Localized deformations such as dents shouldbe stated as absolute deflection from nominal“circular” pipe and as a percent of internal diameter.

8.3.2 Traditional caliper-type geometry tools can beused to determine restriction size, wall-thicknesschange, and other potential deformation restrictions.

8.3.3 More sophisticated deformation tools arecapable of providing more accurate quantification ofdeformation features. Maximum deflection,circumferential (o’clock) position, curvature, shape,buckles, and wrinkles are identifiable.

8.4 Metal Loss (Corrosion)—Tool-Specific Analysis andPrioritization Methods

8.4.1 MFL technology

8.4.1.1 The exact level of reporting is affected bythe resolution level of the technology used. Referto NACE Publication 35100 for details of toolcapabilities.1 Only a general guideline is providedas follows.

8.4.1.2 Conventional resolution allows for thedetection and grading of features to providesome idea of number, density, and priority ofcorrosion features.

8.4.1.3 High resolution allows for detaileddiscrimination and localization of featuregeometry, thereby allowing for clustering. Hence,more advanced defect assessment methods maybe used. Some tools in this category may also bereferred to as extra- or ultra-high resolution. Theuser should understand that tool capabilities varywithin this category, primarily due to sensordensity.

8.4.1.4 Transverse MFL tools magnetize thepipe in the circumferential direction. These toolsare sensitive to different defect geometries thanthe axial MFL and should be used accordingly.

8.4.2 Ultrasonic technology

8.4.2.1 Ultrasonic inspection results are collectedas a pipeline wall thickness rasterized scan andare available as such for viewing and analysis.The topology and “river-bottom profile” (i.e.,profile of how crack depth varies along the lengthof the crack) are inherent in the data that can beused for integrity assessments. The detailedtopology allows advanced defect assessmentmethods to be used.


8.4.3 Clustering and interaction rules (applies to allmetal-loss technologies)

8.4.3.1 Clustering is the grouping of anomaliesaccording to interaction criteria based onmechanical or stress interaction considerations.

8.4.3.2 The effect of corrosion indications inclose proximity should be accounted for using“interaction rules” when dealing with ILI data.These rules must be predetermined as part of thecontracting process, and one of several methodsmay be used. Some examples are:

8.4.3.2.1 Fixed-distance method: Twometal-loss features interact when the axial orcircumferential spacing between features isless than a specified distance (e.g., 100 mm[3.9 in.]).

8.4.3.2.2 Relative distance method: Twometal-loss features interact when the axialspacing between the metal-loss edges isless than the smallest metal-loss featurelength or the circumferential spacing is lessthan the smallest metal-loss width.

8.4.3.2.3 Expanded box/fixed multiple ofwall thickness method: The length and widthextents of metal-loss features are expandedin all directions by a fixed amount that is amultiple of wall thickness (e.g., three timesthe wall thickness [3T]). Two metal-lossfeatures interact if and when the expandedboxes overlap.

8.4.4 Pressure-based analyses and calculations(MFL and UT)

8.4.4.1 Based on the basic length, width, depth,and depth profile information, a burst pressure or“safe” operating pressure calculation should bespecified as part of the reporting specification toaid in the prioritization of anomalies forexcavation or further assessment.

8.4.4.1.1 The algorithms to be used for thispurpose depend on the detail of ILI dataavailable, e.g., bulk metal loss, “river-bottomprofile,” etc.

8.4.4.1.2 An anomaly “box” represents thebasic metal-loss feature (L, W, D). Thelength (L) of an individual feature is that ofthe overall projected length in the axialdirection. The width (W) of a feature is thatof the overall projected width in thecircumferential direction. The detection andmeasurement thresholds of the tool mayresult in different reported values than thoseobserved visually. The ILI contractor should



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specify the thresholds. The depth (D) of themetal loss should be determined by themaximum wall loss in a metal-loss featureand should be given as a depth from or apercentage of the reference wall thickness.

8.5. Crack-Detection Technology—Tool-Specific Analysisand Prioritization Methods

8.5.1 Crack information is supplied categorically as acrack or crack-like feature, its length, and its predicteddepth range. Due to the large volume of informationcollected by the resolution required to detect cracks,reporting timelines are longer than for corrosiontechnology tools.

8.6 Inertial Tools/Mapping Technology—Tool-SpecificAnalysis and Prioritization Methods

8.6.1 Real-world spatial coordinates should beprovided for a given resolution (e.g., every 0.5 m [1.6ft]) to a specified accuracy (e.g., ±1.0 m [3.3 ft])assuming that the corresponding aboveground surveyhas been conducted to sufficient accuracy.Coordinate systems are already standardized andshould be available in latitude/longitude or universaltransverse Mercator (UTM) datum. The data reportedby these tools typically provide the followinginformation.

8.6.1.1 Coordinates for all features in the line (asdetected by the other technologies potentially onthe same tool or a different tool).

8.6.1.2 Bending strain/curvature monitoring;bending strain due to geotechnical movement,external forces, out-of-straightness survey.

8.6.1.3 Absolute bending strains due tocurvature are available for direct assessmentagainst allowable limits.

8.6.1.4 Strain monitoring is the process ofcomparing strains and curvature observed year-to-year when geotechnical or external forces mayhave significantly shifted within the inspection


interval, causing unacceptable loading on thepipeline.

8.6.1.5 An out-of-straightness survey providesresults for areas that are not within the originaldesign/construction specifications.

8.7 Correlation of ILI Reported Results with FieldMeasurements

8.7.1 Field assessment of corrosion: After sufficientsampling and cleaning of the pipe surface to removedeposits and residual coating, a “grid” method can beused to provide corrosion detail over the area ofinterest for the feature. The gridded data can then beplotted as “contours” of depth. This can be achievedvia a variety of methods including pencil probes, pitprobes, etc. This corrosion profile informationcollected should then be utilized for (a) defectassessment by an engineering code to determineacceptability and (b) compared with the ILI toolinformation as verification of analysis.

8.7.2 Field assessment of cracks: After sufficientsampling of the soils, pipe, and/or associated media,consideration must be given to cleaning the pipesurface to allow inspection using a technique such asmagnetic particle inspection to determine the locationof cracking. To optimize the effectiveness of theinspection technique, the pipe surface must be clean,dry, and free of surface contaminants (such as greaseor dirt). The cleaning technique should not create asurface profile on the pipe such that cracking isobscured (e.g., scraping).

8.7.2.1 Each individual crack colony should thenbe documented and photographed. An acceptedtechnique, destructive or nondestructive, shouldbe used to establish crack depth for a sufficientsample size to establish tool confidence andestablish whether repairs are required.

8.7.3 An important part of “closing the loop” is thefeedback of the field inspection results to the ILIservice provider. Using this information, the ILIvendor can continuously improve the validity andaccuracy of the data analysis.

________________________________________________________________________

Section 9: Data Management

9.1 The inspection data should be incorporated into anoverall integrity plan. The inspection data should bemaintained and kept reasonably accessible. It should becorrelated with excavation data, cathodic protection data,any existing construction, coating, soils, and relevantoperating history of the pipe. This exercise allows formore cost-effective decision making in future integritywork.

9.2 Operational and implementation information forsuccessful and unsuccessful inspection can be ofsignificant benefit for reinspections. Examples of this typeof information include but are not limited to:

(a) Pipeline modifications,(b) Debris volume and analysis,(c) Pre-run questionnaire,(d) Repair history,



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(e) Tool types,(f) Operational issues,(g) Procedures, and(h) Aboveground marker locations.

9.3 Use of Growth Rates for Corrosion Inspections

9.3.1 ILI offers the pipeline operator the ability todefine specific maintenance at discrete locations torepair active corrosion that is, or could become, anintegrity concern. By applying growth rates to


identified corrosion features, one can plan themaintenance schedule over a period of time. Therecould come a point when a re-inspection isperformed, either to define growth rates accurately orto address economic considerations when plannedexcavations cost more than the cost of anotherinspection. Multiple inspections allow for a moreaccurate determination of growth rates on a per-feature basis and lead to a well-defined maintenanceplan. A risk-based inspection (RBI) approach issometimes used to define inspection frequency.

________________________________________________________________________

References

1. NACE Publication 35100 (latest revision), “In-LineNondestructive Inspection of Pipelines” (Houston, TX:NACE).

2. U.S. Code of Federal Regulations (CFR) Title 49,“Protection Against Accidental Overpressure,” Part 192(Washington, DC: Office of the Federal Register, 1995).

3. “RSTRENG for Windows” (Houston, TX: NACE).

4. P.H. Vieth, J.F. Kiefner, RSTRENG2 (DOS Version)User’s Manual and Software (Includes: L51688B,Modified Criterion for Evaluating the Remaining Strengthof Corroded Pipe) (Washington, DC: PRCI,(4) 1993).

5. ASME B 31 G (latest revision), “Manual forDetermining the Remaining Strength of CorrodedPipelines: A Supplement to ASME B 31 Code forPressure Piping” (New York, NY: ASME).

6. European Pipeline Operators Forum, “Specificationsand Requirements for Intelligent Pig Inspection ofPipelines.” Shell International Exploration and ProductionB.V., RPT-OM; Rijswijk, The Netherlands, November 6,1998.

Bibliography

Work in Progress by NACE TG 041. “Pipeline DirectAssessment Methodology.” Houston, TX: NACE.


___________________________(4) Pipeline Research Council International, Inc. (PRCI), 1225 Eye St. NW, Suite 350, Washington, DC 20005.


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___________________________________________________________________________________________

Appendix A: Pipeline Inspection Questionnaire

Company Name

Completed byName Fax

Office phone DateChecked by

Name Fax

Office phone Date

Site Information

Pipeline name

Line length (km) (miles) Line OD (mm) (miles)

Launch site L station #

Launch phone Receive phone

Receive site R station #

Base location Base station #

Base shipping address

Base contact Base phone

Type of inspection required: SCC MFL Dent Profile clean

Dummy tool required? Locator required?

Pipeline alignment maps available?

Product Details

Product type H2O content

Wax content Slack line?

CO2 content Hazardous?

H2S content Protective equipment?

Type of flow: Laminar Turbulent Two-Phase (Transitional)

Flow property: Liquid Gas Two-Phase (Both)

Will the line be isolated? Constant velocity?

Flow rate controllable?


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Line Conditions Min. Normal Max.

Launch pressure (kPa)

(psi)

Launch velocity (km/h)

(mph)

Launch flow rate (m3/d)

(MMcfd)

Launch temperature (°C)

(°F)

Receive pressure (kPa)

(psi)

Receive velocity (km/h)

(mph)

Receive flow rate (m3/d)

(MMcfd)

Receive temperature (°C)

(°F)

Note: These values are recorded for regular line conditions. Pressures and velocities will vary during the pig run.

Pipe Details

Last inspection year MAOP

Design pressure Type of cleaning pig

Cleaning program? Frequency

Known/suspected damage

Relevant historical data

Pipeline Conditions

Year of construction Sphere-tees installed?

Pipe cover depth Max Min Type of pipe cover?

Are there high-voltage lines in the vicinity of the pipeline? Where?

Insulating flanges in the pipe? Where?

R.O.W. access (road, air, etc.)

Does pipe have hot taps?

Relevant historical data

Pipe Features Yes No Yes No

Does the pipeline contain the followingfeatures?Thread and collar couplings Chill rings

Bell and spigot couplings Hydrocouples

Stepped hydrocouples Stopple tees

Wye fittingsNontransitioned wall-thickness changes

Mitre joints

Corrosion sampling points Acetylene welds

Internal probes Vortex breakers


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A

B

dD

C

EWork Area

Trap Valve

Kicker Equalizing

F G

H

FIGURE 1Plan View of a Generic Pig Trap

Trap Details Launch Length Receive Length

A Closure to reducer (m)

B Closure to trap valve (m)

C Closure to bridle CL (mm)

d Pipeline diameter (mm)

d’ Pipeline internal diameter (mm)

D Overbore (NPS # or mm)

D’ Overbore internal diameter (mm)

E Axial clearance (m)

F Reducer length (mm)

F’ Reducer wall thickness (mm)

G Reducer to valve (m)

H Bridle (NPS # or mm)

Trap Conditions Launcher Receiver

Orientation

Type/internal diameter of trap valve (mm)

Centerline height of trap(Aboveground) (mm)

Is hoist available? Yes NoCapacityLift Height

Yes NoCapacityLift Height

Is trap equipped with:Pig-Sig?Sphere Tee?Coupons or Internal Fittings?

Trap closure type

Trap pressure rating (kPa)

Concentric or eccentric reducer?

Workshop near trap?

Access limitations (due to available area orground conditions)?AC power at trap site?

Intrinsic safe area, level?


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Site drawings available?

Pipe Information

Nominal WallThickness of Pipe

(mm [in.])

Length of EachWall Thickness

(km [miles])

Pipe WeldType

Pipe Grade(MPa)

Mill OD (mm[in.])

Total Length =

Repair History

Nominal WallThickness andGrade of Pipe

(mm/MPa [in./ksi])

Length of EachWall Thickness

(km [miles])

Start Chainage End Chainage Comments Date ofRepair

Total Length =

Bends

Type Chainage of Bend(km [miles])

Angle(degrees)

BendingRadius

MinimumBore (mm

[in.])

Comments

Tees/Off Takes/BranchesType (Forges,Stopple, etc.)

Chainage ofT/OT/B (km[miles])

O’clockPosition

Max. Off-TakeDiameter (mm [in.])

PigBars?

Comments

Valves

Type Chainage of Valve (km[miles])

Manufacturer Model Minimum Bore (mm[in.])


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Diameter Changes

Type ofReducer

Chainage ofDiameter Change

(km [miles])

Upstream Diameter(mm [in.])

DownstreamDiameter(mm [in.])

DiameterTransition Length

(mm [in.])

Comments

Coatings(If concrete-coated, is there any magnetic content?)InternalExternal

Aboveground ReferencesCan any of the following be located from above ground for references?Line valves Large Bends

CP connections Off-tees

Major WT changes Sleeves

Anodes Casings

Girth welds Insulation Flanges

Known Metal-Loss Information

Internal

External

Mechanical damage

Other

Special Attention

Comments

Completed byName Signature Date

Checked byName Signature Date

Updated byName Signature Date


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