eiberoverview

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Overview of Integrity Assessment Methods for Pipelines

Prepared for

Washington Cities and CountiesPipeline Safety Consortium

November 2003

by

Bob Eiber


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TABLE OF CONTENTS

Background:............................................................................................................................3In-Line-Inspection Descriptions: ......................................................................................... 4

Crack Detection Tools ........................................................................................................ 8

Pressure Testing ................................................................................................................ 8Direct Assessment ............................................................................................................11

Discussion and Comparison of the Capabilities of the Three Assessment Methods.............11ILI Tool Capabilities: ..........................................................................................................11Direct Assessment ............................................................................................................16Comparison of ILI and Hydrostatic Pressure Test..............................................................16

Discussion: ...........................................................................................................................17

Conclusions: .........................................................................................................................18Acknowledgement.................................................................................................................19

References ...........................................................................................................................19


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Overview of Integrity Assessment Methods for Pipelines

Pipelines are an important part of the infrastructure that supplies the energy needs of businessand the public. Liquid pipelines transport fuel that is used to power automobiles, buses, trucksand airplanes. Natural gas pipelines transport natural gas, propane, and other gases used forheating homes, powering electric generation plants and producing chemicals used in industry.These pipelines are normally hidden from view and therefore the public is normally not aware oftheir presence. Occasionally, anomalies are introduced into the pipelines and tragicconsequences can occur such as the pipeline rupture in Bellingham, Washington in June of1999 or Carlsbad, New Mexico in 2000.

The goal of this paper is to review the integrity assessment methods for pipelines, which is oneof the steps in the integrity management of a pipeline. The steps in the integrity managementprocess are:

1. Identifying potential pipeline impacts by threat,2. Collecting data to permit a risk assessment (data include pipeline location versus

population or ecological concerns along with pipeline incident history),3. Conducting a risk assessment to define the location of specific events or conditions that

could lead to a pipeline failure and the potential consequences,4. Conducting an integrity assessment,5. Repair and mitigation of anomalies and prevention of the anomaly failures,6. Updating the data and repeating the cycle.

In step 4 of the integrity management process, the three methods used are 1) in-line-inspection(smart pigs), 2) pressure testing and 3) direct assessment. Each of these will be discussedalong with their capabilities and compared to identify their strengths and weaknesses to assist inunderstanding their potential applications and their advantages and disadvantages. Themethodologies used in integrity assessment are described in the next section.

Background:

Before describing the methods of assessing pipeline integrity, a few comments are provided to

describe what causes loss of integrity in a pipeline. A number of groups have expressedconcern because a number of pipelines in the U.S. have been in service for an extended periodof time, i.e, 25 plus years. Pipelines are composed of steel pipes that do not degrade with time.There are no moving parts in a pipeline that would cause them to wear out like an automobile.

As the steel ages, it gets slightly stronger with time and the toughness level will decreaseslightly with time tending to reduce the pipelines ability to tolerate anomaliesa. The four cause

t i f i id t i d li id i li


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pipelinesb(references are numbered and are at the end of the text; foot notes are lettersand appear at the bottom of each page),

2. Incorrect operation causes 7 percent of the incidents on liquid and natural gaspipelines,3. Malfunction of pressure control equipmentcauses 5 percent of the incidents on liquid

pipelines and 8 percent on natural gas pipelines, and4. Other causes such as gaskets, flanges, fittings, etc cause 27 percent of the

incidents on liquid pipelines and 10 percent of the natural gas pipeline incidents.

The following list summarizes the types of anomalies that are of concern in pipelines:

1. Mechanical damage (third-party damage) from construction equipment introducing adent with a gouge.

2. Corrosionleading to metal loss that maybe general thinning of the pipe, pitting of thepipe, crevice corrosion in electric resistance and flash weld seams or stress corrosioncracking (SCC).

3. Cracks in the seam weld that maybe increasing in length and depth from theoperational pressure cycles that were created from inclusions on the weld line,inadequate pressure during welding, and excessive trim of the excess metal extruded

during electric resistance welding or flash welding.4. Gougeswithout a dent in the body of the pipe that maybe due to construction damage.Also, cracks due to fatigue during shipment, stress corrosion cracks, or hydrogen cracksdue to the environment that forms at the pipe surface. (Generally, these cracks areoriented along the length of the pipe or axially as this is the direction that isperpendicular to the maximum stress in a pipe which is due to pressure.)

5. Wrinkle bends(bends made before the 1950s in which the pipe surface is wrinkled orlocally buckled that have developed cracks from the operational pressure cycles.)

6. Outside forces resulting from land slides, river washouts and settlements can produce

partial collapse or buckles in pipelines.

The significant point is that a major cause of loss of integrity is due to the presence of ananomaly that is present in the pipe and not the age of the pipe. As will be discussed later, agehelps to determine the types of anomolies that are potentially of concern in a pipeline. Theintegrity assessment methods are aimed at detecting and characterizing the presence ofanomalies.

In-Line-Inspection Descriptions:

Pipelines are generally buried and therefore the outside pipe surface is not available for visualinspection. To overcome this restriction, tools have been developed to inspect the pipe wallthickness, position, and geometry from inside the pipeline, hence the reference to in-lineinspection (ILI) A number of ILI tools have been developed and are still being developed to


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the circumferential directionc, and tools that define the location and geometry of the pipeline.

These tools are inserted into an operating pipeline and used to inspect the pipe from the inside.They are moved by the flow of the product in the pipeline and can generally be run withoutremoving the line from serviced, although the inspections usually involve carefully controlledconditions, which may reduce the flow in a pipeline.

Geometry tools:These tools consist of:o caliper, which measure the internal pipe diameter,o deformation, which measure and locate dents in the pipe,o gauging, which assure that the pipe is not collapsed and will allow passage of an ILI

tool,o curvature, which measure the curvature of the pipe along the length of a pipeline, ando position, which measure the position of a pipeline from a reference point.

Metal Loss tools:

MFLThese tools use magnetic flux leakage inspection technology to look for areas of metal

loss that have a circumferential extent. As shown in Figure 1, the MFL tool induces anaxially oriented magnetic flux field into the pipe wall thickness. Sensors on the insidesurface detect locations where the flux field is forced out of the pipe wall thickness bymetal loss such as an area of corrosion on either the inside or outside surface. If no wallthickness reduction is present, the flux field remains in the pipe wall thickness and nosignal is detected. The MFL tool is primarily sensitive to the circumferential extent of ananomaly and its depth. Long narrow areas of metal loss, or axial cracks cannot bedetected because the flux field is parallel to the length of the anomaly and the flux is notpushed outside of the wall thickness. MFL tools have found circumferential cracks in

circumferential welds that are open to either the inside or outside pipe surface. MFLtools have not been successful in locating gouges (either in or out of a dent).

There are two generations of MFL tools. The first generation used wide sensors, on theorder of 4 to 6 inches in the circumferential direction. These wide sensors were not verysensitive and could only categorize anomaly depths into less than 30 percent of the wallthickness, 30 to 50 percent and over 50 percent. The second generation, usuallyreferred to as high resolution tools (hi res or HR) uses narrower sensors on the order of

1 inch in circumferential extent with the result that at least one supplier

e, 1

advertises thatthe tools can detect metal loss with an accuracy of 10 % of the wall thickness with aconfidence limit of 80% (indicating that the measured depth will be within 10% of theactual value 80% of the time) and also measure the length of the metal loss. These twoparameters, length and depth, are needed to predict the severity of an anomaly. Thesame supplier indicates that MFL tools are available for 6 inch diameter 0.312 inch wallthickness to 42 inch diameter 1 5 inch wall thickness


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The accuracy of MFL tools has not been widely validated in the literature but the resultsfrom the 16 inch diameter Olympic Pipeline located in western Washington will be

presented later in this paper to address this issue.

As indicated previously, MFL tools have not been successful in detecting gouges indents, which is one of the major concerns in pipelines. Tools are under development todetect gouges. For example, a recent study has focused on an NLH (non-linearharmonic), technique2that is claimed to be able to find dents with gouges. Time will berequired for the development, field trials and assessment.

Figure 1. Schematic of MFL Technology(Courtesy of Gas Research Institute, Ref 3.)

TFI Transverse flux inspection (TFI) tools also use the magnetic flux leakage technology forthe detection of anomalies but the flux field is reoriented from the axial direction to thecircumferential direction of the pipe. The axial length and depth of an axial anomalyforce the flux field from the pipe wall thickness, which makes the TFI tool sensitive to theaxial length and depth of an anomaly.


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(Flash Weld) seams and also to detect narrow axial corrosion that is not detectable withMFL tools. (ERW and FW are two methods of welding the lengthwise edges of plate or

coil to create a circular pipe in a pipe mill.

f

Historically, ERW and FW have experiencedmore problems than double submerged arc welded pipe or seamless pipe. The primaryreason being that in making ERW or FW seams, the lengthwise edges of the plate to bewelded are heated and pushed together upsetting both edges. Any inclusions or foreignparticles that are in the steel get reoriented to approximately 90 degrees to the wallthickness making them into potential crack-like defects.g The double submerged arcwelds add filler metal to connect the two plate edges to form a circular pipe and there isno upsetting of the pipe wall thickness resulting in welds with few anomalies. Hence,olderh ERW and FW pipe have a greater need to have their seams assessed for

anomalies than newer ERW pipe.)

It is likely but as yet unproven that low pH SCC (stress corrosion cracks) may bedetected with this tool. The one caveat is that the cracks must be open at a pipe surfacefor the flux field to be pushed from the pipe wall thickness and therefore detectable.Because of the TFI tools relatively recent development, the tools capabilities are stillbeing defined.

Ultrasonic;There are two general types of UT (ultrasonic) tools. One type inspects for metal loss,the other inspects for axial cracks in the pipe seam and pipe body (like SCC). Thesetools generally have to be run in a liquid medium to be able to couple the ult rasonicsignal to the pipe wall thickness, which makes their use in a gas pipeline difficult. i (MFLtools work in a liquid or a natural gas pipeline.)

The tools detect metal loss by sending an ultrasound wave perpendicular to the insidewall thickness and measuring the time for the signal to be reflected from the inside and

outside surfaces. Metal loss on either the inside or outside surface is detected by achange in the time of flight of the signal.

Because of the difficulty in using ultrasonic tools in gas lines they have primarily beenused in liquid lines. One supplier 3(PII) claims their UT metal loss tool accuracy is 0.030inches with a 95% confidence limit for a wall thickness range of 0.100 inch to 1.75inches. This is an absolute accuracy limit whereas the MFL was a percent of wallthickness. (Note, at a wall thickness of 0.200 inch the MFL and UT metal loss

accuracies are claimed to be the same whereas for heavier wall thicknesses the UT isclaimed to be more accurate.)

EMAT (electromechanical acoustic transducer);This technique uses magnetic and ultrasonic techniques to inspect a pipe for metal lossand cracks. This has been under development for at least 20 years and the main goal


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has been to inspect for axial cracks in the pipe. No one has yet developed a successfultool for pipeline inspection. One of the vendors is currently indicating that a tool will be

available in the next 1 to 2 years.

Crack Detection Tools

UltrasonicUltrasonic tools for crack detection use an ultrasound wave that is oriented atapproximately 45 degrees to the pipe surface. It isintroduced into the pipe wall and thenreflects from cracks to designate their presence and depth as shown in Figure 2.Ultrasonic crack detection tools employ either liquid filled wheels or operate in a liquid

bath. The liquid-filled wheel was developed tofind SCC in gas pipelines and has beensuccessful in finding SCC and fatigue cracks.4 The liquid bath UT tool has also beensuccessful in detecting SCC in gas and liquid pipelines. 5,6, 7

Figure 2. Ultrasonic Schematic Illustration(Courtesy of Gas Research Institute, Ref.1)

Eddy currentThis is another inspection technique that uses alternating current to induce magneticfields into the steel pipe to detect cracks. To date, no in-line inspection tools using theeddy current technique have been developed for pipelines but a prototype is underdevelopment.

EMATAs mentioned previously, this is a promising technique that is under development for thedetection of cracks in pipelines. There are no tools available at the present timealthough one vendor claims to be in the final development process.


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The disadvantage of a pressure test is that it is a destructive test and a pass/fail test. Only

when an anomaly leaks or breaks is it detected. The higher the test pressure level, the smallerthe crack that can be removed and the longer the time period before the test has to berepeated. Therefore, a high-test pressure level is necessary to remove the smaller cracks thatmight cause failure in service.

Figure 3 provides a specific example of the sizes of anomalies that can be removed in apressure test of 16 inch diameter 0.312 inch wall thickness 52,000 psi SMYSjpipe. The figurepresents a plot of calculated lengths and depths of anomalies that will fail in a pressure test of apipeline at various pressure levels. Along the left side of Figure 3 are pressure levels in pounds

per square inch. Along the bottom of Figure 3 is the anomaly length, in inches. The solid linecurves represent the depths of flaws ranging from 0.1 d/t (depth to thickness) or 10% of the wallthickness to 0.9 d/t or 90% of wall thickness.

Figure 3. Critical Anomaly Lengths and Depths in 16 inch diameter0.312 inch wall thickness X52 Pipek

(Calculated using PTFLAW1 from Ref. 8assuming the pipe hasa high fracture toughness, which is typically the case)

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Typ. Operating Pressure

Leak - Rupture


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operating pressure (MOP) level (72% SMYS, the highest stress allowed by the federalregulations [49 Code Federal Regulations Parts 192 or 195]) the anomaly length that separates

leaks and ruptures

l

is 3.7 inches as shown by the intersection of the 72% SMYS (1460 psipressure) horizontal line and the intersection of the leak-rupture curve for the 16 inch diameterpipe shown. Longer anomalies than 3.7 inches will result in ruptures at 72% SMYS, shorteranomalies will result in leaks.

It is apparent that the longer the anomaly, the lower the failure pressure and the deeper theanomaly the lower the failure pressure. At a pressure equivalent to 72% SMYS, Figure 3indicates that a 12 inch long anomaly with a maximum depth of about 0.47 d/t (between the 0.4and 0.5 d/t curves) would fail. At the same stress level, a 6 inch long anomaly with a maximum

depth of about 0.53 d/t or just a little below the 0.5 d/t curve would also fail. Because both ofthese failure points lie above the heavy dashed curve, both would result in ruptures, as opposedto leaks. Also, a 1.2 inch long anomaly that has a 0.9 d/t would fail at 72% SMYS; however,because it falls below the TWC curve, it would fail as a leak.

The anomaly size (depth and length) that a given pipe size can tolerate without failure isdependent on the diameter of the pipe as well as the pressure level in the pipe assuming thepipes are of the same relative toughness. The larger the pipe diameter, the longer an anomaly

can be all other factors equal. Therefore, Figure 3 only applies to the 16 inch diameter pipe forwhich it was calculated.

Figure 3 can be used to evaluate the effectiveness of a pressure test. About the highest test-pressure stress level that can be used in a hydrostatic pressure test is 100% SMYS. (Higherstresses may cause the pipe to begin to grow permanently and could cause coating damage.)

A more typical minimum test pressure stress level is 90% SMYS. Both 90 and 100% SMYSlevels are shown in Figure 3. At a test pressure of 100% SMYS, the range of anomalies thatwould fail range from 90% deep 0.6 inch long to 20% deep 12 inches long. These are fairly

large anomalies that will fail while slightly smaller anomalies could remain in the pipe after apressure test is finished.

Since a pressure test is a pass/fail test, if an anomaly does not fail in a test, the operator doesnot obtain any information about the type of anomalies that may be developing in a pipeline andis not aware of the need to apply mitigative measures.

One problem with hydrostatic testing is that it is difficult to obtain and dispose of water because

of the current environmental restrictions. Even more important is that it requires taking apipeline out of service, which is very expensive. Hydrostatic testing also requires removing theproduct, pressure testing and repairing any leaks or ruptures and then drying the pipeline afterthe water has been removed and refilling with product. Another problem with hydrostatic testingis that it is difficult to conduct repeated tests on pipelines, which is the situation that has beenmandated by the Office of Pipeline Safety regulation Part 195.452. Repeated stress tests canbegin to cause the growth of flaws that might not grow in service when the test pressure is


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of water can be released. Also, water released from a liquid line may have hydrocarboncontaminants that could damage the environment.

Direct Assessment

There are some pipelines that are currently unpiggable due to valves that will not allow passageof an ILI tool due to very tight bends, or changing diameters along the length of the pipeline.Therefore, other inspection methods have been pursued as a replacement for ILI.

Direct assessment is really an indirect integrity assessment method utilizing a structuredprocess through which an operator is able to integrate knowledge of the physical characteristics

of the pipeline and operating history with the results of inspection, examination and evaluation inorder to assess the integrity. Presently, this method has only been developed for metal loss(corrosion anomalies) and therefore has somewhat limited applicability.

Discussion and Comparison of the Capabilitiesof the Three Assessment Methods

The known capabilities of ILI tools to detect and characterize anomalies will be contrasted withthe capabilities of hydrotesting and direct assessment. Following this a general discussion ofthe methods and their interaction will be presented.

ILI Tool Capabilities:

The ILI tool capabilities that will be presented are those that were obtained from the inspectionof Olympics 16 inch diameter pipeline in 2000 to 2003 using a deformation tool, an HR MFL

tool, and a TFI tool.

Deformation Tool The deformation tool used was the HR Tuboscope tool and its purpose wasto detect dents in the pipeline. Figure 4 presents data from Olympic Pipelines Ferndale toRenton 16 inch diameter line segment comparing the ILI deformation tool dent depth predictionsagainst the actual measured dent depths obtained from inspection of the pipe once it was dugup. The dent depths tend to scatter about the 1:1 line but on the average tend to fall above the1:1 line in the non-conservative region. However, Tuboscope only claims a minimum dent

detection threshold of 2 percent of the pipe diameter for this tool, which is shown in the plot.Only six of the data points are above this limit and therefore the tool has performed better thanclaimed with regard to the minimum dent depth that it can detect.

Although the tool was used in a region outside of the manufacturers stated accuracy limits, itappears to have been successful in detecting and locating dents with shallow depths. Becausethis is a deformation tool the tools accuracy is not extremely critical Its main function is to


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present time, it is only through the detection of dents that dents with metal loss can be located.An improved ILI tool assessment capability is needed for this anomaly type.

Figure 4. Predicted Dent Depth vs. Measured Dent DepthFrom ILI Data on the Olympic 16 inch Diameter Line Segment

HR MFL Tool The HR MFL tool used on the Olympic 16 inch pipeline was developed byTuboscope. Figure 5 presents a plot of predicted metal loss versus the actual metal lossmeasured during an inspection of the metal loss area at dig sites. Comparing the measuredmeasure loss with the predicted metal loss allows assessment of the tools accuracy. The datain Figure 5 have about 40% of the data points within +/- 10% of the diagonal 1:1 line shown. Itappears that the calibration of the MFL tool results by the manufacturer has been shifted intothe conservative region to reduce the number of non-conservative data points since all but twoof the data points fall in the conservative region below the 1:1 line. However, the two datapoints in the non-conservative region are significant. These non-conservative metal loss datapoints are -52 and -23 % in error. Task 680 was predicted to have a depth of 47 percent of thewall thickness and it was measured as 61 percent deep an error of (61-47/61) or 23%. Sincethis is a non-conservative prediction in a depth range where failure could occur, it illustrates whyit is necessary to dig each significant indication, as there is scatter in the results.

One interesting development is that several colonies of shallow SCC have been found in areasof metal loss detected by the HR MFL tool. In one instance the metal loss was on the order ofhalf the wall thickness and the SCC cracks were about 6 percent of the wall thickness. Inanother instance, the SCC cracks and corrosion were a total of about 7 percent of the wallthickness but were detected with the HR MFL tool. While the accuracy is not as good as the

f t l i d f 10% f th ll thi k 80 t f th ti th

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iameter

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threshold, 2%

1 : 1


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Figure 5. Predicted Metal Loss Depth Versus Measured Metal Loss Depth

TFI tools The TFI tool was developed to inspect the seam weld in pipelines for open cracksand axial narrow corrosion. The TFI tool used on the Olympic pipeline was developed by PII(Pipeline Integrity International) of the UK. The TFI tool was run in 2001 and 2002 on thecomplete Olympic system with the exception of the 6 inch Olympic lateral. (No 6 inch diametertool exists and the 6 inch line is seamless and therefore does not have a weld seam to inspect.)

The TFI log for the 20 inch diameter pipeline segment was reviewed for metal loss anomaliesand for ERW weld seam anomalies. The available TFI predicted and measured data have been

plotted in Figures 6 and 7. Figure 6 presents a comparison of the predicted versus measuredaxial lengths of metal loss indications. Figure 7 presents the comparison of predicted versusmeasured metal loss depths. Figure 6 indicates that the tool predicted metal loss lengths from 2to 48 inches and yet the measured lengths were less than an inch to 203 inches. The datareveal that the TFI tool characterization capability to predict metal loss anomaly lengths needsto be improved, as there is a large amount of scatter about the 1:1 line. As an example of theaccuracy, the measured 203 inch metal loss lengths were predicted to be 6 to 12 inches inlength. It should be kept in mind that the primary goal of the TFI tool was not to detect metal

loss as the MFL tool does this successfully. It must also be stated that the data at the presenttime is limited and additional data are needed before an assessment of the tools capabilities ispossible.

Figure 7 indicates that most of the depth data points lie below the 1:1 line in the conservativeregion suggesting that the manufacturer may have set the calibration so that this conservativeresult is achieved One significant observation from Figure 7 is that the depths of metal loss

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Predicted MFL Metal Loss, % wall thickness

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allthickness

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Task 20

Task 680 1 : 1 line


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Figure 6. TFI Metal Loss Predicted Lengths Versus Measured Lengths

Figure 7. TFI Metal Loss Predicted Depths Versus Measured Depths

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psi or a stress that is close to the maximum pressure strength of the pipe steel. This high failurepressure is important as it indicates that the weld seam anomalies were not opened by thehydrotest that was performed on this line, which could have made them much easier to detect.This line was hydrostatically retested in the last several years to a 90% SMYS pressure level.The fact that three weld seam anomalies that have survived a high pressure test have beenfound in this line indicates that the tool is capable of performing an inspection that is better thana high pressure test. More data from other line segments will be needed to completely assessthe capability of the TFI tool.

Figure 8. TFI ERW Seam Flaw Data

A problem with the MFL and TFI tool characterization of anomalies is that the recorded signalheight is not directly related to the percentage of metal loss. Therefore, interpretation of thesignal to define the predicted depth requires the application of an experience factor. This factorhas been defined for the MFL tools but is still in the development stage for the TFI tool.

UT Metal Loss Tools The UT tool was initially run on the 16 inch line and the results werecompared with the MFL tool. The conclusion reached by Olympic was that the MFL tool

provided results that were as good as the UT tool and therefore no further UT runs wereconducted. The data on which that decision was based has not been released and therefore,no comparison can be made of the UT tool capability versus MFL. Inspections with the UTdatafrom other pipelines have been presented in the literature and the results have been good. 9

UT Crack Detection Tools The UT crack detection tool is used to detect and characterize axialcracks in seam welds and stress corrosion cracks in pipelines This has not been run on the

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16 inch diameter X52

Typ. Oper. Pressure

Weld Seam Flaws

Leak - Rupture


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Direct Assessment

Direct assessment as currently developed is presently only applicable for the assessment ofmetal loss. There have been no detailed assessments of the capability of the direct assessmentmethod. The procedure for conducting a direct assessment is also not completely finalized atthis time. Therefore, the capability of this assessment method has yet to be defined.

Comparison of ILI and Hydrostatic Pressure Test

Data is available from the Olympic 16 inch diameter pipeline ILI inspection and the hydrostatic

test that permit comparison of the results of the assessment of metal loss anomalies. The 16inch diameter pipeline segment was pressure tested to a minimum of 90% SMYS. At the timethe hydrostatic pressure test was conducted, the deformation tool and the HR MFL toolinspections had been completed and therefore no metal loss anomalies were expected to fail.During the test, two axial weld seam failures occurred but no metal loss anomalies failed. Thehydrotest was needed to assess the weld seam condition as no ILI tool had been run to inspectthe seam weld for anomalies.

Figure 9 presents a figure similar to Figure 3 but it includes the calculated failure pressure levelsfor the metal loss anomalies detected with the HR MFL tool. The purpose of presenting thisfigure is to compare the capability of a hydrotest to the ILI HR MFL inspection for metal lossdefects. The solid circles represent the ILI MFL detected metal loss anomalies plotted at theircalculated failure pressure levels and measured lengths. Eighty two percent of the ILI (metalloss) data points reflect very small anomalies that were detected by the ILI HR MFL inspectionand they have failure pressures well above 100% SMYS. The data indicate that the HR MFLinspection tool is capable of detecting and characterizing anomalies that lie above the operatingpressure line and extend to the maximum pressure for a zero length defect. The pressure test

is only able to fail defects that are in the size range between the operating pressure and 90%SMYS lines. This figure clearly indicates one of the benefits of in-line inspection overhydrostatic testing is the ability to detect small emerging anomalies.

The two open squares represent the two pressure test axial weld seam failuresm. If the ILI MFLinspection had been conducted after the pressure test an additional two or three failures (thetwo solid data points below the 90% SMYS line and the one just above) would have beenexpected to fail in the pressure test. These data demonstrate that the ILI HR MFL inspectionwas able to detect much smaller metal loss defects than the pressure test.

The pressure test has served the industry and public well for more than 60 years. However, itsability to detect small anomalies is limited to the size that will fail in a test and it can leave largeanomalies that are near failure and which may have been enlarged slightly, which could grow inservice. The pressure test while not as effective in identifying developing anomalies is the oneassessment method that detects a wide range of anomaly types in a single test but overall is not


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are not on a seam or girth weld in a pipeline are not injurious and will not fail in a pressure testand have not caused incidents.)

Figure 9. ILI Versus Hydrostatic Pressure Test Results

In order for ILI tools to be successful in assessing the integrity of a pipeline there are severalconditions that must be met. First, there must be knowledge of the anomaly types that may

exist in a pipeline in order to select the ILI tools that can inspect for them. Table 1 presents alist of the capabilities of the various tools and contrasts their capabilities to the hydrotest. Table1 indicates that no one ILI tool is capable of duplicating the integrity assessment of a hydrotestas indicated earlier. This leads to the second condition, which is that more than one type of ILItool is typically needed to completely inspect a pipeline.

As an example, if a pipeline is suspected of having corrosion and mechanical damage defectsthen as a minimum a deformation tool and an MFL tool would have to be run to duplicate theflaw detection capabilities of a hydrotest. Additionally, if the pipe is ERW or FW, a tool will beneeded with the capability to detect defects in the weld seam. This means that a TFI tool mightbe substituted for the MFL tool. Presently, the inspection capabilities of the TFI tool are beingdetermined as its use increases. One way to determine the efficacy of the TFI tool is to use it toinspect a line that has known seam anomalies and then hydrotest the line segment todemonstrate absence of anomalies or alternatively inspect a line segment that has beenhydrotested as described earlier

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because some of these tools, i.e. TFI, etc. are not fully developed their capabilities are notcompletely known. What is needed is for pipeline companies to use them to define theircapabilities and to learn how to use them. This is expensive and time consuming but is neededfor the future, as pressure testing becomes more and more difficult and expensive to performbecause of the cost of removing the line from service and obtaining and disposing of water.

In summary: Advantages of Pressure Testing

o One test detects all but girth weld flaws that can cause service incidents.o The one type of anomaly not detected (girth weld flaws) has a low probabilility of

causing a leak or rupture.

o A high pressure test can be beneficial in that it loads the pipe steel to a higherlevel than in service and leaves the steel in a condition that is more resistant toSCC formation.

Disadvantages of Pressure Testingo Requires taking the line out of service for an extended time. This is the length of

time to remove products, fill, test, repair ruptures or leaks, dewater, and return toservice.

o The test cannot find small flaws or developing conditions. Advantages of ILI

o Generally does not require taking the pipeline out of service. Although thismethod takes longer and the cost of conducting an ILI inspection may be higherthan a pressure test, these costs can be offset because the line can remain inservice continuing to generate revenue.

o Once an ILI base line (established by the first inspection) has been established, itis feasible to rerun inspection tools at appropriate intervals to monitor forchanges in anomalies or new anomalies.

o Small to large flaws or developing conditions can be detected that could lead to a

service incident. This is a major benefit over and above a hydrotest. Disadvantages of ILI

o Flaws may be missed due to the complex nature of the log interpretation. This isexpected to decrease as experience is gained with the tools. Olympic Pipelinespressure test of an ILI inspected pipeline with only seam failures indicates thatthe ILI did not miss any serious anomalies.

o The type of defect expected in a pipeline must be known or suspected so that theproper ILI tools can be selected for the inspection.

o Several types of tools generally have to be run in order to inspect the pipeline forall of the potential types of defects.

Conclusions:

Presently a pressure test provides the most complete assessment of a pipeline in a single test


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pipelines. These are in order of severity: dents with gouges or metal loss, corrosion, weld seam defects, stress corrosion cracks, and fatigue cracks.

Acknowledgement

The author is indebted to Olympic Pipeline Company for their permission to use the ILI resultsfrom their pipeline for this paper. The data are a necessity to show the advantages and

disadvantages of pressure testing compared to ILI.

References

1 Goedeke, Hartmut, Ultrasonic or MFL Inspection, which technology is better for you, Pipeline and Gas

Journal, Oct 2003, pp 34-41.2 Crouch, A.E., New NDE technology detects, characterizes dent, gouge defects, Oil and Gas Journal,

Aug 4, 2003, pp. 52-58.3 Crouch, A.E., In-Line Inspection of Natural Gas Pipelines, GRI-91/0365, Gas Research Institute, May1993.4 Maxey, W.A., Mesloh, R.E., and Kiefner, J.K., Use of the Elastic Wave Tool to Locate Cracks along the

DSAW Seam Welds in a 32 inch OD Products Pipeline, 1998 ASME International Pipeline Conference,Vol 1, pp 595-604, Calgary, Canada.5 Ashworth, B, Willems, H, and Uzelac, N., Detection and Verification of SCC in a Gas Transmission

Pipeline, 2000 ASME International Pipeline Conference, Vol. 2, pp 717-723, Calgary, Canada.6C. L. Blair, and Madi, M.S., Crack Detection Program on the Cromer to Gretna, Manitoba Section of

Enbridge Pipeline Inc. Line 3, 2000 ASME International Pipeline Conference, Vol. 2, pp 1435-1438,

Calgary, Canada.7 Krishnamurthy, R.M., et al, Liquid Pipeline Stress Corrosion Cracking, 2000 ASME International

Pipeline Conference, Vol. 2, pp1439-1449, Calgary, Canada.8 Eiber, R. J., Bubenik, T. A, and Maxey, W.A., Fracture Control for Natural Gas Pipelines, A.G..A. NG-

18 Report 208, December 1993.9 Scott, B.R., Jolivette, D.K., and Sjerve, E.M., Automated Ultrasonic Testing for Mapping and

Correlation with ILI Internal Pitting Measurements, 2002 ASME International Pipeline Conference, paperIPC2002-27312, Calgary, Canada.


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Table 1. Matrix of ILI vs Hydrotest Capabilities

Presure Test

Seam

Type

Defect Types Frequency of

Occurrence

Origin Deformation/

Geometry

Gaging Line

Position

Curvature HR

MFL

HR

TFI (a)

UT-

ML

UT-

Axial

Crack

EMAT Pressure

Test (b)

LF ERW &

FW

Stitched weld high mill x, ? x ? x

Hook crack high mill x, ? x ? x

Unbonded weld

region

high mill ? x ? x

Selective

corrosion

medium field x x x ? x

HF ERW Hook crack medium-low in

pipe since 1970

mill x, ? x ? x

Selective

corrosion

low field x x x ? x

All &

Seamless

Dents medium field x x ?

Gouges medium field ? x

Axial cracks

open to the

surface

low field x x ? x

Gouges in a dent high field ? ? x

Corrosion high field x x x ? x

Hi pH SCC low field ? x ? x

Low pH SCC low field x, ? x x ? x

Settlement/soil

slides

low field x x

Girth Weld

cracks/lack of

penetration

low field x ?

DSAW Seam Weld

cracks

low mill ? x ? x

Toe cracks low mill ? x ? x

Shipping fatigue

cracks

low since 1970 transport from mill x x ? x

Notes:

ILI

(a) The question marks are associated with types of anomalies that should be detectable with the tool but have yet to be verified that the tool can detect them. What is

needed is for a line segment of ERW pipe to be examined with the TFI tool, anomalies removed or repaired and a pressure test conducted to verify that all injurious

anomalies have been detected.

(b) The pressure test will cause the following types of defects to fail if they are large enough. The size of flaw detected is a function of the test pressure level. The

higher the test pressure level, the smaller the remaining flaw.

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