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                          CRACK GROWTH RATE
 Mohammad Hassan               Weixing Chen               Richard Kania
       Marvasti*                Department of              TransCanada
     Department of              Chemical and             Pipelines Limited
     Chemical and           Materials Engineering      Calgary, AB, Canada
 Materials Engineering      University of Alberta
  University of Alberta        Edmonton, AB,
    Edmonton, AB,                  Canada
        Robert Worthingham                       Gregory Van Boven
   TransCanada Pipelines Limited             Spectra Energy Transmission
         Calgary, AB, Canada                           Limited
                                               Vancouver, BC, Canada
Corrosion fatigue and fatigue crack growth in air tests were comparatively
conducted on an X52 pipelines steel. Fatigue crack growth rates in air were
lower than corrosion fatigue crack growth rates due to the absence of
hydrogen and mechanical dormancy arisen from low temperature creep at low
cyclic frequencies. Mechanical dormancy can commonly occur during
operation of both oil and gas pipelines. Crack growth in near neutral pH
environments can be well rationalized by a combined loading factor,
(ΔK)2Kmax/fα, which reflects the synergistic interaction between the
mechanical driving force and the hydrogen effects. Hydrogen plays a decisive
role in terms of crack growth in pipelines steels exposed to near neutral pH

                                   Shaohui JIA
                          PetroChina Pipeline R&D Center
                           Langfang, Hebei, China
In annual summer monsoon, geo-hazard is common. Monsoon-caused
casualties and economic losses throughout the year accounted for 70% ~ 80%
of the total annual losses. Also, geo-hazard is a serious threat for pipeline
operators to manage. Over 12,000 kilometers of pipelines with crude oil, gas,
and refined oil are operated by PetroChina Pipeline Company. The pipelines,
through sixteen provinces and cities, have been operated for over forty years.
Geographic Information System (GIS) technology, as an effective spatial
analysis tool, provides advanced analysis for pipeline geo-hazard prediction
and early warning during summer monsoon based on field data and historical
precipitation records.
After many years of research and applicaton of our prediction model of pipeline
geo-hazard, an important link between geo-hazard and rainfall is understood.
Rainfall is the main triggering factor of geo-hazards such as landslide and
debris flow leading to heavy losses, especially rainstorm and heavy rainstorm.
We use GIS technology to perform spatial analysis with predicted rainfall data
the next twenty-four hours and the data of pipeline geohazard susceptibility,
and predict the severity of pipeline impacts caused by geo-hazards during the
next twenty-four hours. Finally, the result is modified by existed geo-hazards
data. The pipeline geo-hazard early warning is divided into five ranks which
are displayed by different colors, and pipelines damaged by geo-hazards and
protection measures are also proposed.
During July 16 and 17 of 2009 years, we released geo-hazard early warning
four rank of Lanzhou-Chengdu- Chongqing Oil Pipeline through PetroChina
Pipeline Company web page(http://www.gdgs.petrochina) and the
communication software of IM. The Lanzhou-Chengdu-Chongqing Oil Pipeline
Company acted promptly with a detailed deployment and emergency plan to
ensure pipeline safety.

        Lei Guo                    Lijian Zhou                 Shaohui Jia
 PetroChina Pipeline R&D     PetroChina Pipeline R&D     PetroChina Pipeline R&D
         Center                      Center                      Center
  Langfang,Hebei,China        Langfang,Hebei,China         Langfang,Hebei,China
          Li Yi                   Haichong Yu                 Xiaoming Han
 PetroChina Pipeline R&D     PetroChina Pipeline R&D     PetroChina Pipeline R&D
         Center                      Center                      Center
  Langfang,Hebei,China        Langfang,Hebei,China         Langfang,Hebei,China
Pipeline segmentation design is the first step to design alignment sheet. In this
step, several rectangular boxes are used to cover pipeline and each box will
become the basic unit of alignment sheet design. After studying various
pipeline alignment sheet mapping technologies, the author found that
traditional manual design method, which can take advantage of designers'
subjectivity, causes low work efficiency. By reviewing and studying existing
works at home and abroad, the author believed that it is possible and feasible
to develop an automatic segmentation algorithm based on existing curve
simplification algorithms to improve to improve the efficiency of pipeline
section design and alignment sheet mapping. Based on several classical curve
simplification algorithms, the author proposed the automatic segmentation
algorithm, which automatically adjusts the location of rectangular boxes
according to the number of pipeline/circle intersection points and pipeline/
rectangular box intersection points. Finally, through comparing time and result
with the traditional manual
method, the author proved the algorithm’s effectiveness and feasibility.

                  IN-LINE INSPECTION DATA
       Luc Huyse                Albert van Roodselaar             John Onderdonk
      Chevron ETC                  Chevron ETC                 Chevron Thailand E & P
    Houston, TX, USA             Houston, TX, USA                Bangkok, Thailand

       Boonchouay                  Jackson Baker                   Thomas Beuker
    Wimolsukpirakul            Chevron Thailand E & P             Rosen Inspection
 Chevron Thailand E & P          Bangkok, Thailand                Lingen, Germany
    Bangkok, Thailand
            Johannes Palmer                                Nija Amri Jemari
            Rosen Inspection                               Rosen Inspection
            Lingen, Germany                             Kuala Lumpur, Malaysia
The cost for repair or replacement of subsea pipelines is much higher than for
onshore pipelines. To a large extent, the repair or replacement decision hinges
on the outcome of fitness-for-service analyses that are in turn based on the
results of in-line inspections. It is therefore of utmost importance to obtain
in-line inspection data that are as accurate as possible. It has been reported in
the literature that MFL tools may significantly exaggerate the localized wall
loss for wet gas lines subject to top of the line corrosion.
This paper reports the results of a study on a Chevron asset that was initiated
to compare the performance of various inspection methods. Upon completion
of the in-line inspections, a section of the pipeline was recovered off the ocean
floor and subsequently replaced. The defect population of the recovered
pipeline section together with the high-definition automated ultrasonic testing
(AUT) results built the reference of the performance test of several inline
inspection techniques like magnetic flux leakage (MFL), ultrasonic (UT) and a
recently developed technology for accurate measurement of shallow internal
corrosion (SIC) that is based on eddy current (EC) technology. The
improvements in defect sizing that resulted from this investigation are
               Bing Han                                          Jianbin Hao
     PetroChina Pipeline R&D Center                   School of Petroleum Engineering
         Langfang, Hebei, China                 Southwest Petroleum University, Chengdu,
                                                      PetroChina Pipeline R&D Center
                                                            Langfang, Hebei, China
     Hongyuan Jing                     Jianping Liu                   Zhangzhong Wu
 PetroChina Pipeline R&D          PetroChina Pipeline R&D         PetroChina Pipeline R&D
         Center                           Center                           Center
 Langfang, Hebei, China           Langfang, Hebei, China           Langfang, Hebei, China

The integrity of oil and gas pipelines is seriously impacted by landslides in
tough terrain in western China. The quantitative assessment technology is an
effective method for pipelines risk management under threat of geohazard. In
order to establish the vulnerability assessment indexes system of pipelines
subjected to landslides, the numerical simulation based on the finite element
method is adopted to study the pipeline axial stresses. There are five kinds of
calculation schemes considered by changing the geometrical sizes and
inclination angles of landslide, the pipeline length passing through landslide
and buried depth of pipeline, and the axial stresses and bending moments of
pipeline can be obtained by means of numerical simulation for different
calculation conditions under the every kind of scheme. In the study, regression
analysis method is used to derive the axial stress equation of pipeline from
calculation results of numerical simulation by taking into consideration the
above five indexes. The feasibility and practicality of this equation are verified
by the given example of a pipeline passing through a certain landslide in
southwest China. The comparison analysis between the monitoring data and
calculation results shows that the calculation values agree well with the
monitoring data of pipeline axial stresses.
Key words: landslide; pipeline; stress analysis; numerical simulation;
regression analysis

Jaime Fariñas
Transierra S.A.                             Gary Nuñez
Integrity Management Program & Corrosion    Transierra S.A.
Responsible                                 Mechanical Maintenance Responsible
Cristo Redentor Ave. Km. 4 ½, PO Box 6800   Cristo Redentor Ave. Km. 4 ½, PO Box 6800
Santa Cruz de la Sierra, Bolivia            Santa Cruz de la Sierra, Bolivia
Phone: +591-3-3146229                       Phone: +591-3-3146167
Fax: +591-3-3410066                         Fax: +591-3-3410066
email: jfarinas@transierra.com.bo           email: gnunez@transierra.com.bo
Transierra is a gas transportation company that owns and operates the
Yacuiba - Rio Grande pipeline (GASYRG), 432 kilometers in length and 32
inches in diameter, which transports natural gas from southern Bolivia to the
Rio Grande compression station (Santa Cruz), and is part of the gas export
system to Brazil.
In September 2008 amid a scene of political upheaval, social protests and
roadblocks, Transierra suffered an intrusion that resulted in damage to the
pipeline, fire in the safety block valve SDV-03, environmental damage and
reduced transportation capacity.
With all the disadvantages of blocked roads, closed airports and lack of spare
parts, fuel and equipment; the damage was repaired and the pipeline was up
and running again in 60 hours. Given these circumstances, it became clear
that there are sensitive points in the pipeline that are highly vulnerable to the
actions of third parties.
This paper overviews the actions taken to the light of this new dynamic of
social environment in the affected area of the pipeline. Alternatives were
analyzed in order to make improvements in the protection of installations and
to guaranty operational continuity.
This incident forced us to take action to prevent, anticipate and mitigate any
malicious action of third parties. The purpose of this paper is to show our
experience in the approach, conceptualization, design and fabrication of a
prototype that would prevent and obstruct undesired access of third parties to
improperly manipulate or damage the proper functioning of the safety valves
elements, actuator and its
instrumentation, seeking to decrease the degree of risk exposure and
increasing the level of safety of facilities.
KEYWORDS: Pipeline, Pipeline Integrity, Third Party Actions, Facilities
Integrity, Facilities Improvements, Security.

Narasi Sridhar
Det Norske Veritas         Feng Gui                    John Beavers
Research & Innovation      Det Norske Veritas -        Det Norske Veritas -
– USA                      Columbus                    Columbus
Dublin, OH – USA           Dublin, OH – USA            Dublin, OH – USA
Future biofuel mix may contain ethanol from cellulosic materials, butanol, and
biodiesel from diverse sources. The anticipated variable mix introduces
technical and business uncertainties to pipeline companies requiring a flexible
risk management framework. The technical issues are outlined in this paper
along with approaches to risk management. The bow tie approach is
discussed as a method to assess overall risk and communicate it throughout
an organization. Direct assessment methods and their applicability to biofuel
pipelines are also discussed.
Keywords: biofuel, corrosion, stress corrosion cracking, steel, non-ferrous
metals, elastomers.

     Narasi Sridhar
   Det Norske Veritas                Feng Gui                     Elizabeth Trillo
 Research & Innovation –        Det Norske Veritas -            Southwest Research
          USA                        Columbus                         Institute
    Dublin, OH – USA             Dublin, OH – USA              San Antonio, TX – USA
                                  Preet M. Singh
                           Georgia Institute of Technology
                                 Atlanta, GA – USA
The stress corrosion cracking (SCC) susceptibility of carbon steel in fuel grade
ethanol varies as a function of major and minor constituents in ethanol. The
results of a round-robin testing on six different ethanol batches are presented.
Significant variations in test results between the laboratories may result from
apparently minor differences in test procedures. The variation in SCC
susceptibility of different ethanol chemistries appear to be small.
Keywords: Fuel grade ethanol, stress corrosion cracking, steel.

                     SUPERCRITICAL CO2
    Francois Ayello             Det Norske Veritas -              USA
   Det Norske Veritas                Columbus                Dublin, OH – USA
 Research & Innovation –         Dublin, OH – USA
          USA                     Narasi Sridhar
    Dublin, OH – USA            Det Norske Veritas
    Kenneth Evans            Research & Innovation –
                                Ramgopal Thodla
                           Det Norske Veritas - Columbus
                                 Dublin, OH – USA
The increasing urgency to mitigate global warming has driven many efforts to
control green house gas emissions. One solution among many is carbon
capture and storage. However, CO2 emitters are not necessarily in the close
vicinity of potential geologic storage sites. In consequence CO2 will be
transported from generation site to storage sites under high pressures. This
will necessitate a network of pipelines gathering supercritical CO2 from diverse
sources and transporting it through transmission lines to the storage sites.
These pipelines will be under corrosion risks, particularly because of possible
carryover of trace impurities produced from the different sources, such as
water, chloride, NOx, SOx, and O2. The effects of impurities on corrosion in
supercritical CO2 have yet to be evaluated systematically. Corrosion of carbon
steel associated with water and impurities in supercritical CO2 was studied by
Electrochemical Impedance Spectroscopy in autoclaves. Five impurities were
studied by introducing them in the liquid condensed phase: water, amine, HCl,
HNO3 and NaOH. Results were analyzed in terms of the phase behavior and
Keywords: Amine, CO2 supercritical, corrosion, HCl, HNO3, impurities,


            Ashish Khera           Abdul Wahab Al-Mithin
          Allied Engineers     Kuwait Oil Company- Inspection &
       213 New Delhi House,                Corrosion
       27 Barakhamba Road,         P.O. Box 9758, Ahmadi
      New Delhi-110001,India           610008, Kuwait
     Phone: +91-11-23314928        Phone: +965-23981304
    akhera@alliedengineer.com        amithin@kockw.com
           James E. Marr               Calgary, Alberta
     TransCanada Pipeline Ltd.        T2P 5H1, Canada
        450- 1st Street S.W.,      Phone: +403-920-5410
    jim_marr@transcanada.com                  P.O. Box 9758, Ahmadi
          Shabbir T. Safri                       610008, Kuwait
  Kuwait Oil Company-Inspection &             Phone: +955-23861527
              Corrosion                         ssafri@kockw.com
                             Saleh Al-Sulaiman
                Kuwait Oil Company- Inspection & Corrosion
                           P.O. Box 9758, Ahmadi
                              610008, Kuwait
               Phone: +965-23984392 ssulaima@kockw.com

More than half of the world's oil and gas pipelines are classified as
non-piggable1. Pipeline operators are becoming aware there are increased
business and legislative pressures to ensure that appropriate integrity
management techniques are developed, implemented and monitored for the
safe and reliable operation of their pipeline asset.
The Kuwait Oil Company (KOC) has an ongoing “Total Pipeline Integrity
Management System (TPIMS)” program encompassing their entire pipeline
network. In the development of this program it became apparent that not all
existing integrity management techniques could be utilized or applied to each
pipeline within the system. KOC, upon the completion of a risk assessment
analysis, simply separated the pipelines into two categories consisting of
piggable and non-piggable lines. The risk analysis indicated KOC‟s pipeline
network contains more than 200 non-piggable pipelines, representing more
than 60% of their entire pipeline system. These non-piggable pipelines were to
be assessed by utilizing External Corrosion Direct Assessment (ECDA) for the
threat of external corrosion. Following the risk analysis, a baseline external
corrosion integrity assessment was completed for each pipeline.
The four-step, iterative External Corrosion Direct Assessment (ECDA) process
requires the integration of data from available line histories, multiple indirect
field surveys, direct examination and the subsequent post assessment of the
documented results. This case study will describe the available correlation
results following the four steps of the DA process for specific non-piggable
lines. The results of the DA program will assist KOC in the systematic
evaluation of each individual non-piggable pipeline within their system.

A case study of the crack sizing performance of the Ultrasonic Phased Array
combined crack and wall loss inspection tool on the Centennial pipeline, the defect
evaluation, including the defect evaluation, field feature verification and tool
performance validation (performed by Marathon Oil, DNV and GE Oil & Gas).
T. Hrncir.                                 539 South Main St
Marathon Pipe Line LLC                     Findley, OH 419/306-4087
S. Turner                                    539 South Main St
Marathon Pipe Line LLC                       Findley, OH 419/306-4087
SJ Polasik                                   P. Vieth
DNV Columbus, Inc                            BP E&P
5777 Frantz Rd                               501 Westlake Park Blvd MS 20.127C
Dublin, OH 43017                             Houston, TX 77079-8696
D.Allen                                      I.Lachtchouk
GE Oil & Gas PII Pipeline Solutions          GE Oil & Gas PII Pipeline Solutions
Lorenzstrasse 10,                            Lorenzstrasse 10,
D-76297 Stutensee, Germany                   D-76297 Stutensee, Germany,
P. Senf                                      GE Oil & Gas -PII Pipeline Solutions
GE Oil & Gas PII Pipeline Solutions          4908 – 52nd Street SE
Lorenzstrasse 10,                            Calgary, Alberta T2B 3R2, Canada
D-76297 Stutensee, Germany,                  Tel: +1 403 204 5255
G. Foreman                                   Email: geoff.foreman@ge.com
GE performed an ultrasonic phased-array (USCD DUO) in-line inspection (ILI)
survey of a 24-inch and 26-inch products pipeline. The primary purpose of this
ILI survey was to detect and characterize stress corrosion cracking (SCC). A
dig verification was subsequently performed throughout 2008 in order to
establish a higher level of confidence in the detection and depth-sizing
capabilities of this technology. Presented herein is an overview of the USCD
technology and experience, the method used for validating the ILI survey
results, enhancements to the ILI data analysis, and the impact on managing
the integrity of the subject line section.

Jim Marr, TransCanada                        Solutions

450 – 1st Street S.W.,                       Lorenzstrasse 10,

Calgary, Alberta T2P 5H1                     D-76297 Stutensee, Germany,

Phone ++1-403- 920-5410,                     Phone ++49-7244/732-185,

jim_marr@transcanada.com                     stephan.tappert@ge.com

Stephan Tappert, GE Oil & Gas PII Pipeline

Elvis San Juan Riverol, TransCanada
450 – 1st Street S.W.,

Calgary, Alberta T2P 5H1

Phone ++1-403- 920-6361,


Andy Mann, GE Oil & Gas PII Pipeline Solutions

Atley Way,

NE23 1WW Cramlington, Great Britain,

Phone ++44-191/247-3463,


Jörg Weislogel, GE Oil & Gas PII Pipeline Solutions

Lorenzstrasse 10,

D-76297 Stutensee, Germany,

Phone ++49-7244/732-469,


Sun Jiangang, GE Oil & Gas PII Pipeline Solutions

1003 11th Street S.W..,

Calgary, Alberta T2R 1G2

Phone ++1-403-298-0227,


TransCanada typically manages the integrity of sections of gas transmission
pipelines that are susceptible to stress corrosion cracking (SCC) by
periodically performing hydrostatic testing.
Interest in an alternative approach to manage pipeline integrity in the presence
of SCC and other forms of longitudinally oriented defects resulted in the
endorsement of the latest generation of dry coupled in-line inspection tool.
GE´s EMAT In-Line Inspection (ILI) tool uses the electromagnetic acoustic
transducer technology to meet this requirement.
This paper will summarize field experience results of the latest generation
Emat In-Line inspection tool, which is commercial available since September
2008. It demonstrates, that the challenges have been overcome, the targets
have been achieved, and the tool delivers the information of a distinguished
ability of detection, sizing and discrimination performance, key parameters to
conduct an effective pipeline integrity program.

                                                                 IPC 2010-31095
                    Abu Rafi, Jorge Silva, Sara Kenno, Sreekanta Das
                     Department of Civil and Environmental Engineering
                                   University of Windsor
                     401 Sunset Avenue, Windsor, ON, Canada N9B 3P4
        Tel: (519) 253 3000 Ext. 2507; Fax: (519) 971 3686; e-mail: rafia@uwindsor.ca
                          Richard Kania and Rick Yahua Wang
                                   TransCanada Pipelines
                               Calgary, AB, Canada T2P 4K5
Pipeline industry and various research organizations have been undertaking
studies to understand how the pressure strength of line pipes reduces as the
defects in the line pipes grow. Defect in pipe lines can be in the form of
corrosion, dent, wrinkle, gouge, crack, and combinations of these. A large
number of
studies have been completed in developing methods for determining the
pressure strength of line pipes with dent and gouge defects and also in the
form of combined dent-gouge defect. Some of these studies were undertaken
with the intention of determining the pressure strength of line pipes when a
combined dent and crack (dent-crack) defect has formed. However, in these
studies no cracks were simulated in
the test pipe specimens; instead, a gouge (machined cut or notch) was
produced and considered as a crack. Therefore, it is not realistic to call this
defect a dent-crack defect; rather, it should be called dent-gouge defect.
Hence, the current project is being undertaken at the University of Windsor to
study how the dent-crack defect influences the pressure strength of line pipes.
In this study, a crack in true sense was introduced in the pipe wall. Two
different techniques were used to simulate the crack in the pipe wall. This
paper discusses the procedures used in this study to simulate crack and dent.
In addition, the test procedure and test data obtained from denting and
pressure tests are discussed.
              David J. Miles                                   Tim J.M. Bond
             Pipestream Inc.                                   Pipestream Inc.
          Houston, Texas, USA                               Houston, Texas, USA
           Raymond N. Burke                                 Ruben van Schalkwijk
             Pipestream Inc.                                  RvS-Engineering
          Houston, Texas, USA                              Huizen, The Netherlands
A new technology for external rehabilitation of pipelines, known as XHab™,
has been developed. This method involves wrapping multiple layers of
ultra-high strength steel strip (UHSS) in a helical form continuously over an
extended length of pipeline using a dedicated forming and wrapping machine.
The reinforcement afforded by the strip can be used to bring a defective
section of pipe (e.g. externally corroded or dented) back to its original
allowable operating conditions, or even to increase the allowable operating
pressure if the desired operating conditions exceed the original pipeline design
This paper describes the full scale burst testing and analysis of defective pipes
which have been repaired using the XHab process. The full scale test sections
are 30” × 0.5” API 5L X52 DSAW pipe and include the following specimens:
• Bare pipe with no defects;
• Bare pipe with single machined defect;
• Wrapped pipe with single machined defect and designed reinforcement;
• Wrapped pipe with single machined defect and insufficient reinforcement;
• Wrapped pipe with interacting defect array and designed reinforcement
The above full scale burst tests are supplemented by FEA models using
ABAQUS. The material models for the steel pipe, UHSS strip, defect patch
material and strip adhesive are based on measured data from the batch tests
and tuned against the control burst test results. The structural behavior in the
individual metallic and non-metallic elements can therefore be examined more
closely, particularly in the region of the defect and where the wrapped strip
crosses seam and girth welds.

N Martin Zaleski    Tom Greaves        Jan Bracic
BGC Engineering Inc.            Pembina Pipeline Corp.          Pembina Pipeline Corp.
Vancouver, British              Calgary, Alberta, Canada        Calgary, Alberta, Canada
Columbia, Canada
The Canadian Standards Association’s Publication Z662-07, Annex N
provides guidelines for pipeline integrity management programs. Government
agencies that regulate pipelines in Alberta, British Columbia and other
Canadian jurisdictions are increasingly using Annex N as the standard to
which pipeline operators are held.
This paper describes the experience of Pembina Pipeline Corporation
(Pembina) in implementing a geohazards management program to fulfill
components of Annex N. Central to Pembina’s program is a ground-based
inspection program that feeds a geohazards database designed to store
geotechnical and hydrotechnical site information and provide relative rankings
of geohazard sites across the pipeline network. This geohazard management
program fulfills several aspects of the Annex, particularly: record keeping;
hazard identification and assessment; risk assessment and reduction; program
planning; inspections and monitoring; and mitigation.
Pembina’s experience in growing their geohazard inventory from 65 known
sites to over 1300 systematically inspected and catalogued sites in a span of
approximately two years is discussed. Also presented are methods by which
consultants and Pembina personnel contribute to the geohazard inspection
program and geohazard inventory, and how the ground inspection
observations trigger follow-up inspections, monitoring and mitigation activities.

                   Lalinda Weerasekara and Dharma Wijewickreme*
                    University of British Columbia, Vancouver, B.C.
The performance of pipelines in areas prone to ground deformations is a major
concern for utility owners since the failures of such pipeline systems could
cause property damage and even human losses, in addition to business
disruption. An analytical solution to determine the response of plastic pipelines
subject to abrupt relative ground movement occurring perpendicular to the
pipe axis is presented herein. The method accounts for the combined impacts
of tension and bending in a pipe segment. Furthermore, the model considers
the nonlinear stress-strain behavior of the pipe material and employs an
advanced analytical model to calculate the frictional force development along
the pipeline. The results obtained from this analytical approach are validated
by comparing with the results obtained from a numerical model using
soil-spring analysis and the actual viscoelastic material behavior for the pipe

James R. Walker              Paul Mallaburn                Derek Balmer
GE Oil & Gas, PII Pipeline   GE Oil & Gas, PII Pipeline    GE Oil & Gas, PII Pipeline
Solutions                    Solutions                     Solutions
Houston, Texas               Cramlington, UK               Cramlington, UK
Historically, pipeline operators have tended to place more weight on inline
inspection tool specifications than on the inherent design and reporting
capabilities of the service providers themselves. While internal collection of
integrity data is very important, it’s imperative that vendors, also, have high
levels of expertise and effective quality control systems in place to successfully
analyze exceedingly high volumes of inspection data. The quality of inspection
information is vital to assessing if a pipeline is fit for purpose now and/or into
the future.
Integrity managers attempting to reduce overall operating risk by making
decisions based on inaccurate or poor quality reporting are in fact exposing
their networks to greater safety and financial risk.
Recognizing these risks and that inline inspection (ILI) is an overall system that
needs to be formally qualified, operators and ILI service providers have
collaborated to develop several international standards. The most recent is the
umbrella API- 1163 industry consensus standard, which is now being widely
adopted, primarily in USA. This standard provides requirements and
recommended practices for qualification of the entire ILI process. Two
companion standards: ASNT In-line Personnel Qualification and Certification
Standard No. ILI-PQ and NACE Recommended Practice In-Line Inspection of
Pipelines RP0102 combine to address specific requirements for personnel
who operate and analyze the results of ILI systems. In Europe, the Pipeline
Operators Forum (POF) has, also, established specific requirements for ILI
reporting processes and data formats.
However, these standards do not define how operators and vendors must
meet these requirements. To follow will be a story about how an ILI service
provider embraced a holistic approach to address these standards’
requirements, in particular in the areas of data analysis, reporting, and dig
verification due to their significant importance in assuring the final quality of its
deliverables. A key outcome desired will be to provide operators with greater
insight into what best practices and technologies ILI service providers should
have embraced and invested in to insure reliable service delivery.

Neil Bates, P.Eng          David Lee, EIT             Cliff Maier
DNV Canada Ltd.            DNV Canada Ltd.            DNV Canada Ltd.
Calgary, Alberta, Canada   Calgary, Alberta, Canada   Calgary, Alberta, Canada
     This paper describes case studies involving crack detection in-line inspections and
     fitness for service assessments that were performed based on the inspection data.
     The assessments were used to evaluate the immediate integrity of the pipeline
     based on the reported features and the long-term integrity of the
     pipeline based on excavation data and probabilistic SCC and fatigue crack growth
     Two different case studies are analyzed, which illustrate how the data from an
     ultrasonic crack tool inspection was used to assess threats such as low frequency
     electrical resistance weld seam defects and stress corrosion cracking. Specific
     issues, such as probability of detection/identification and the length/depth accuracy
     of the tool, were evaluated to determine the suitability of the tool to accurately
     classify and size different types of defects.
     The long term assessment is based on the Monte Carlo method [1], where the
     material properties, pipeline details, crack growth parameters, and feature
     dimensions are randomly selected from certain specified probability distributions to
     determine the probability of failure versus time for the pipeline segment. The
     distributions of unreported crack-related features from the excavation program are
     used to distribute unreported features along the pipeline.
     Simulated crack growth by fatigue, SCC, or a combination of the two is performed
     until failure by either leak or rupture is predicted. The probability of failure
     calculation is performed through a number of crack growth simulations for each of
     the reported and unreported features and tallying their respective remaining lives.
     The results of the probabilistic analysis were used to determine the most effective
     and economical means of remediation by identifying areas or crack mechanisms
     that contribute most to the probability of failure.

                                                                       IPC2010 - 31116
Qingshan Feng                              Jeff Sutherland                Bill Gu
Director, Pipeline Integrity               Chief Engineer                 Country Manager - China
PetroChina Pipeline Company                GE PII Pipeline Solutions      GE PII Pipeline Solutions
Langfang, China                            Calgary AB Canada              Beijing, China
With an overall objective for broad and confident integrity management of the
PetroChina Pipeline Company's pipeline network, we illustrate the impact of a
collaborative effort between PetroChina and GE Oil & Gas for the inspection and
mitigation of spiral weld anomalies, particularly for new advanced assessments of
features oriented along and within the spiral weld.
Tool configuration, sensor types and the role of novel data analysis techniques
including magnetic vector component measurements, is presented as a set to
address a broader variety of spiral weld threats, while ensuring a high level of
operational robustness and reliability.
This paper describes some of the science behind the art, and describes the
fundamentals of MFL magnetics and it's evolution as an ILI technology into the 21
century for spiral weld anomaly inspection.

                                         Henryk G Pisarski
                                               TWI Ltd
                       Granta Park,Great Abington,Cambridge, CB21 6AL,UK
This paper reviews the basis for the use of SENT or SE(T) specimens as described
in DNV RP F108, their limitations and aspects about specimen preparation testing
and analysis procedures that need to be addressed in order to standardise the test
better. Examples are given comparing the effect of crack tip constraint in a SE(T)
specimen with a circumferential crack in a pipe subjected to axial straining and axial
strain plus internal pressure. The variations in crack front straightness, the effect of
specimen geometry on the J resistance curve as well as the accuracy of the J
estimation procedure are presented. The use and limitations of CTOD estimation
procedure based on measurement of crack mouth opening displacement as a
fracture toughness parameter is discussed.

       Jeff Sutherland, Chief Engineer                            4908 – 52nd Street SE
 PII Pipeline Solutions Business of GE Oil &                 Calgary, Alberta T2B 3R2, Canada
                    Gas                                            Tel: +1 403 204 5255
       Email: jeff.sutherland@ge.com              Cramlington, Northumberland, NE23 1WW,
      Martin Bluck, Product Manager                                   UK
 PII Pipeline Solutions Business of GE Oil &                Tel: +44 191 247 3429
                    Gas                                  Email: martin.bluck@ge.com
 Atley Way, North Nelson Industrial Estate,
   Justin Pearce, COE Leader, Magnetics               Eric Quick, Regional Sales Manager
 PII Pipeline Solutions Business of GE Oil &      PII Pipeline Solutions Business of GE Oil &
                    Gas                                               Gas
 Atley Way, North Nelson Industrial Estate,               7105 Business Park Road
 Cramlington, Northumberland, NE23 1WW,                           Houston, TX
                    UK                                        Tel: +1 713 849 6311
           Tel: +44 191 247 3200                          Email: eric.quick@ge.com
       Email: justin.pearce@ge.com
In 1996, the Pipeline Operators Forum (POF) published its first version of an In Line
Inspection Specification to standardize how an operator and vendor would
undertake a pipeline inspection. Within the POF specification, anomalies have been
classified into categories as a function of their length and width in order to allow
vendors to state their Probability of Detection and sizing tolerances for each
classification. In the latest 2009 revision, there is an increased visibility for all
corrosion categories Previously, when utilizing conventional MFL tools, ILI vendors
were not capable of supplying probability of detection and sizing specifications for
several categories such as Pinholes and Axial Slotting. Recent advancements with
MFL technologies have allowed performance improvements to be made detection
and sizing for Pinholes, Pitting, Axial Grooving and Axial Slotting.
This paper will summarize experience gained from both pull through and field
results of the latest generation MFL Technology leveraging data from a high density
array of axial, radial, & transverse sensors. The data will show there is a
distinguishable improvement in the Probability of Detection and Sizing tolerances
for many of the POF categories which will allow pipeline operators make more
informed pipeline integrity decisions.

        Carlos Nieves Cáceres                  Mauricio Pereira Ordoñez
       Oleoducto Central S.A.                  SOLSIN S.A.S
       Bogotá, Cundinamarca, Colombia          Bogotá, Cundinamarca, Colombia

The OCENSA pipeline system is exposed to different geotechnical problems,
including faults, landslides and/or creeping slopes. These problems are typical of
the Andes Mountains, especially in tropical countries like Colombia. Due to the fact
that the system was constructed buried, the pipe interaction with the surrounding
soil is a very important factor that must be taken into account in these unstable
places in order to guarantee the pipe integrity. In this paper, a methodology to
evaluate the pipe response under soil displacements in slow landslides is proposed.
This methodology consists of three different cases of analysis, according to the
characteristics of the place in study. It starts using a simplified analytical model and
ends with 3D finite element numerical simulations using the real geometry of soil
and pipe. The 3D continuum finite element models are made using the general
purpose nonlinear software ABAQUS/Standard. These models are calibrated and
validated with soil displacement data acquired from geotechnical instrumentation
and pipeline geometry information obtained from in-line inspection tools. The
models are used to predict the pipe behavior, estimating the moment at which the
pipe overpasses the allowable strains. Based on the calculated strains, relief
procedures are programmed and executed. These activities allow the pipeline to
relieve the strain caused by soil movements, avoiding the occurrence of failures.
For this reason, the proposed methodology is a very important tool in the OCENSA
pipeline integrity program, which has been used successfully to assess the pipe
condition in unstable areas and to take the appropriate remediation and mitigation


      CASE STUDYPablo
                                    Samarth Tandon                Ming Gao
                                 Blade Energy Partners       Blade Energy Partners
      Blade Energy Partners
                                  Houston, Texas, USA        Houston, Texas, USA
       Houston, Texas, USA
                                   Romina Peverelli
       Ravi Krishnamurthy                                       Esaú Diaz Solís
                                    PIMS of London
      Blade Energy Partners                                    Pemex Refinación
                                      London, UK
       Houston, Texas, USA                                   Cd de México, México

Stress corrosion cracking (SCC) is a major concern for most gas and oil pipeline
operators. Extensive efforts continue to be made to develop strategies for a better
management of the problem. The quantification of the life cycle and risk of SCC
rupture for a post inspection integrity assessment requires knowledge of (1) Quality
of Inspection, namely POD (Probability of Detection), POI (Probability of
Identification) and Actual Sizing Tolerance (2) Material and Metallurgy; (3)
Appropriate Assessment Methods; and (4) Crack Growth Rates                   Previous
experience gained from the crack detection inspections showed POD and POI for
deep cracks are generally high, with sizing limited up to 40% wt. The uncertainty in
sizing for shallow cracks is usually higher, and may not meet the specified tolerance
at a specified certainty and confidence level. POD, POI and sizing accuracy can be
affected by the inspection operation including speed, other defects and geometry
irregularity along the pipeline. Therefore, the qualification of the tool inspection
performance directly impacts on the reliability of the assessment and serves as the
basis for a reliable assessment.
In this paper, an approach for managing high pH SCC in a 30” x 340 Km oil pipeline
in Mexico is presented. The approach consists of a comprehensive verification
excavation plan, a strict in-ditch NDT investigation protocol, statistical models for
POD, POI and sizing tolerance analyses, and an appropriate assessment
methodology supported by the material testing program. With all the results
obtained from application of the approach, the integrity management strategies are
developed. An action plan for future integrity is established and being refined from
time-to-time prior to next inspection.

                   FAILURES HAVE OCCURRED
                 John F. Kiefner                                 Kolin M. Kolovich
            Kiefner and Associates, Inc.                   Kiefner and Associates, Inc.
             Worthington, OH, U.S.A.                           Worthington, OH, U.S.A.
                                       Shahani Kariyawasam
                                       TransCanada Pipelines
                                     Calgary, Alberta, Canada
     The retesting of pipelines for integrity management purposes often involves
     testing of pipelines where multiple test failures can be expected. Multiple
     failures are most likely to occur when an existing pipeline is tested to a hoop
     stress level in excess of those used in prior tests of the pipeline. A major cause
     of such failures is seam manufacturing defects, but other types of defects such
     as mechanical damage or stress corrosion cracking may cause numerous
     failures as well. The occurrence of multiple failures can be costly in terms of
     the time the pipeline must remain out of service. Multiple failures
     sometimes involve pressure reversals that may affect confidence in the level of
     integrity sought by the pipeline operator. The study described in this paper
     involved a review of five actual cases of hydrostatic tests where multiple test
     failures occurred. On the basis of these cases a method was developed for
     predicting the ultimate number of failures required to reach a desired test level
     from the pressure levels of the first few failures. In addition, an improved
     method for estimating the probability of a pressure reversal of a given size was
     developed. Pipeline operators could use these techniques to decide when to
     terminate a hydrostatic test and to assess the effectiveness of the test in terms
     of a level of confidence that an integrity-threatening pressure reversal will not
        Ali Hosseini                       Duane Cronin
      University of Waterloo               University of Waterloo
      Waterloo, Ontario, Canada            Waterloo, Ontario, Canada
        Alan Plumtree                       Richard Kania
      University of Waterloo                TransCanada Pipelines
      Waterloo, Ontario, Canada             Calgary, Alberta, Canada

The retesting of pipelines for integrity management purposes often involves
testing of pipelines where multiple test failures can be expected. Multiple
failures are most likely to occur when an existing pipeline is tested to a hoop
stress level in excess of those used in prior tests of the pipeline. A major cause
of such failures is seam manufacturing defects, but other types of defects such
as mechanical damage or stress corrosion cracking may cause numerous
failures as well. The occurrence of multiple failures can be costly in terms of
the time the pipeline must remain out of service. Multiple failures sometimes
involve pressure reversals that may affect confidence in the level of integrity
sought by the pipeline operator. The study described in this paper involved a
review of five actual cases of hydrostatic tests where multiple test failures
occurred. On the basis of these cases a method was developed for predicting
the ultimate number of failures required to reach a desired test level from the
pressure levels of the first few failures. In addition, an improved method for
estimating the probability of a pressure reversal of a given size was developed.
Pipeline operators could use these techniques to decide when to terminate a
hydrostatic test and to assess the effectiveness of the test in terms of a level of
confidence that an integrity-threatening pressure reversal will not occur.


                   SALINE CONDITIONS
Brent W.A. Sherar Peter G.          5B7, Canada                Nanaimo, BC, V9T 1K2,
Keech Zack Qin David W.                                                Canada
 Department of Chemistry,            Fraser King               Robert G. Worthigham
The University of Western         Integrity Corrosion        TransCanada Pipelines Ltd
 Ontario London, ON, N6A           Consulting Ltd.              Calgary, AB, T2P 5H1,
This paper investigates the long term corrosion behaviour of pretreated carbon
steel under alternating anaerobic to aerobic cycles over 238 days. Changes in
steel behaviour were observed electrochemically by monitoring the corrosion
potential, and calculating changes to corrosion rate from linear polarization
resistance. With increasing cycle number the corrosion process becomes
localized at a small number of locations, consistent with the formation of
tubercles. Periods of aerobic corrosion were associated with more positive
potentials (between _500 mV to _350 mV) and high corrosion rates (70 to 120
μm yr-1); whereas anaerobic corrosion yielded more negative potentials (<
-650 mV) and lower corrosion rates (40 to 50 μm yr-1). Upon termination of the
experiment, corrosion product deposits were characterized by several
techniques: scanning electrochemical microscopy to detect morphology;
focused ion beam and cross sectioning to judge film thickness and film
porosity; and Raman Spectroscopy to identify iron phases.


Fraser King, Integrity Corrosion Consulting Ltd., Nanaimo, BC, Canada
Mark Piazza, Pipeline Research Council International, Falls Church, VA, USA
Robert Worthingham, TransCanada Pipelines Ltd, Calgary, AB, Canada

A significant amount of research and development has been carried out on the
mechanism of the stress corrosion cracking of underground pipelines. This
paper describes the results of a study, co-funded by PRCI, the US DOT, and
pipelines companies, to bring together the results of these various studies in
the form of a set of guidelines that will assist companies in identifying the most
likely SCC locations on their systems and in predicting how frequently
inspection or other mitigation is required.
The guidelines have been developed along mechanistic lines, and are divided
into four “steps” representing: susceptibility to SCC, crack initiation,
early-stage growth and dormancy, and crack growth to failure. For each step, a
series of Research Guidelines has been derived from the results of individual
research papers or studies. These Research Guidelines may or may not be
easily validated against field data. The SCC Guidelines were then developed
based on one or more Research Guidelines. Wherever possible, the SCC
Guidelines have been validated against field data, but in some cases currently
un-testable SCC Guidelines were defined because they offer a potentially
unique opportunity to identify where and when SCC might occur.
                     PART-THROUGH DEFECT
                                       Orynyak I.V.
       G.S. Pisarenko Institute for Problems of Strength, National Ac. Sci. of Ukraine
                                       Lokhman I.V.
                               SC Ukrtransgas, Kyiv, Ukraine
                                     Okhrimchuk S.O.
                               SC Ukrtransgas, Kyiv, Ukraine
Pipe bend is very complicated element for the structural integrity assessment. Up to
day there is no conventionally adopted technique for limit load calculation of pipe
bend even without any defect. The problem is that at application of outer bending
moment the pipe bend cross section ovalizes and the process of deformation can be
described only with accounting for the geometrical nonlinearity.
The paper deal with limit load calculation for pipe bend with axial part-through defect
for particular case when circumferential stresses originated both from inner pressure
and outer bending moment dominate over axial stresses from the moment and axial
Two extreme cases are considered at start. First one is the action of the inner pressure
only. The “Institute for Problems of Strength limit load model” (IPS model) can be
applied here without any restrictions. The second case is consideration of
circumferential bending stresses which have appeared due to ovalization from the
outer bending moment. The model of the transmission of stresses from the defected
region to the undamaged regions is suggested and the resulting formula for the stress
concentration (or strength reduction) coefficient is obtained.
At last the simultaneous action of both loadings is considered. As result the analytical
formula for the reference stress calculation which is similar in appearance to that of
API 579 for accounting for membrane stress as well as bending stress is suggested.
The only difference is that strength reduction coefficients are considered for both the
membrane stresses from inner pressure and bending stress from ovalization. This
differs from API 579 approach where the influence of the defects length on the
bending stresses is not taken into account.


                   INITIATION MECHANISM(S)
               Abdoulmajid Eslami, Mohammadhassan Marvasti,
                          Weixing Chen, Reg Eadie
  Department of Chemical and Materials Engineering, University of Alberta,
                      Edmonton, Alberta, Canada
                             Richard Kania,
                           Bob Worthingham
         TransCanada Pipeline Limited Calgary, Alberta, Canada
                            Greg Van Boven
                            Spectra Energy
                  Vancouver, British Colombia, Canada

In order to improve our understanding of near-neutral pH SCC initiation
mechanism(s), a comprehensive test setup was used to study the
electrochemical conditions beneath the disbonded coatings in cracking
environments. In this setup the synergistic effects of cyclic loading, coating
disbondment, and cathodic protection were considered. Our previous results
showed that there can be a significant variation in the pH of the localized
environment under the disbonded coating of pipeline steel. The pH inside the
disbondment can change significantly from near-neutral to high pH values,
strongly depending on the level of cathodic protection and CO2 concentration.
Both of these variables affected the electrochemical conditions on the steel
surface and therefore the initiation mechanisms. This work highlights the role
of electrochemical conditions in near-neutral pH SCC initiation mechanisms.

                             Hong Lu
                      Visser Consulting Ltd
                     Calgary, Alberta, Canada
                          Allison Denby
                      Visser Consulting Ltd
                     Calgary, Alberta, Canada
The pipeline risk assessment has been more and more widely used in the
industry because of economic factors and regulatory requirements. The three
most popular risk assessment methods are qualitative method (simple
decision making matrix method), semi-quantitative method (score index
method) and quantitative method. The decision-making matrix method greatly
depends on expert’s opinion, and does not provide much information to
optimize the mitigation program. The quantitative method provides details of
mitigation options, mitigation criteria, and prioritizations, but requires a lot of
input data that the pipeline operators usually do not have. The score index risk
assessment is widely used in the pipeline industry. The input data is relatively
easy to acquire. The method provides details of mitigation options and relative
risk values.
The score index risk assessment is a relative method. Upstream pipeline
operators often have questions, such as “Which is the most effective mitigation
option to use with my limited resources?” and how the index scores relate with
the actual failure frequencies and failure consequence. In order to effectively
answer these questions, this paper outlines a method to correlate the
probability of failure score with actual failure probability, and leak impact factor
score with actual failure consequence in monetary units. Rather than using the
final risk score, this method applies the monetarily calibrated consequence
factor to the probability of failure so that a normalized and calibrated risk in
monetary unit is obtained. By comparing the cost of an estimated mitigation
program, the decision can be made based on relative risk. This process is
straightforward and practical for industrial application, especially for upstream
companies where operators have limited resources to run an in-depth risk
assessment. A case study is presented using this method based on upstream

                         S.A. Timashev, A.V. Bushinskaya
        Science and Engineering Center “Reliability and Safety of Large Systems”
                      Ural Branch Russian Academy of Sciences
                             Ekaterinburg, 620049,Russia

Predictive maintenance (PdM) is the leading edge type of maintenance. Its
principles are currently broadly used to maintain industrial assets [16]. Yet
PdM is as yet not embraced by the pipeline industry. The paper describes a
comprehensive practical risk based methodology of predictive maintenance of
pipelines for different criteria of failure. For pipeline systems the main criterion
is integrity.
One of the main causes of loss of containment is pipe wall defects which grow
in time. Any type of analysis of pipeline state (residual life time, probability of
failure (POF), etc.,) is based on the sizes of discovered defects, which are
assessed during the ILI or DA.
In the developed methodology pipeline strength is assessed using one of the
five internationally recognized design codes (the B31G, B31mod, DNV,
Battelle, Shell 92). The pipeline POF is calculated by the comprehensive
Gram-Charlier-Edgeworth method [14]. Having in mind that the repair actions
are executed on particular cross-sections of the pipeline, the POF are
 calculated for each defect present in the pipeline. When calculating POFs, the
 defect sizes (depth, length and width), wall thickness and pipe diameter,
 SMYS of the pipe material, the radial and longitudinal corrosion rates, and
 operating pressure (OP) are considered random variables each distributed
 according to its PDF.
 In the proposed method of PdM of pipelines the remaining life time can be
 assessed using following criteria: POF = Qth; dd = 80%wt; SMOP = МAОР;
 ERF = MAOP/SMOP, if ERF ≥ 1, the pipeline needs immediate repair; dd =
 100%wt. Here Qth is the ultimate permissible POF, dd is the depth of the most
 dangerous defect, wt is pipe wall thickness, SMOP is the maximal safe
 operating pressure SMOP = DF·Pf, MAOP is the Maximum Allowable
 Operating Pressure, Pf is the failure pressure, DF is the design factor (for
 B31Gmod DF = 1.39), ERF is the Estimated Repair Factor. The above criteria
 are arranged in descending order according to the growing level of their
 severity in time.
 The prediction of future sizes of growing defects and the pipeline remaining life
 time are obtained by using consistent assessments of their corrosion rates
 CRs. In the PdM methodology these CRs may be considered as deterministic,
 semi-probabilistic or fully stochastic values. Formulas are given for assessing
 the CRs using results of one ILI, two consecutive ILI, with or without
 verification measurements, and for the case when several independent types
 of measurements are used to assess the defect sizes.
 The paper describes results of implementation of the developed methodology
 on a real life pipeline. The time to reach each of the limit states given above
 was calculated, using results of two consecutive ILI divided by a three year
 interval. Knowledge of these arrival times permits minimizing the maintenance
 expenditures without creating any threats to its integrity and safety.

                                     Qingshan Feng
              Pipeline Research Center of PetroChina,Langfang, Hebei,China
             School of Material Science and Engineering,BUAA, Beijing, China
                                        Yi-han Lin
              Pipeline Research Center of PetroChina,Langfang, Hebei,China
             Dept. of Mechanics and Engineering Science Fudan Univ.,Shanghai, China
                                          Bin Li
                 China Nuclear Power Engineering Co.,Ltd. Beijing, China
                                      Hanchen Song
              Pipeline Research Center of PetroChina,Langfang, Hebei,China
This paper studies some key issues of fitness-for-service assessment for
pipelines constructed in 1970s in Northeastern China, which were found to have
large amount of weld defects resulting in leakage and rupture accidents. The
mechanical behaviors of tensile strength, Charpy V-notch impact energy and
fracture toughness are tested for the spiral weld metal and pipeline steel,
showing that the state standards of steel for pressure vessel are still met after
serving for more than 30 years. The safety limit line of the failure assessment
diagram(FAD) is derived according to BS7910: level 2B assessment, based on
the obtained stress-strain curve of weld metal.
The chemical composition of pipeline steel analyzed by the energy spectrum
method indicates the pipeline was made of 16Mn steel. The metallographic
examination reveals that the metallurgical structure of weld metal was
composed of ferrite and pearlite with five different zones. The morphology of
tensile fractured surface shown by ductile dimples indicates the tensile fracture
is of ductile type, which implies the weld metal and pipeline steel after long time
service have not yet become brittle.
The stress magnification factor for the bulge effect of through-wall girth defect is
extracted from the stress intensity factor evaluated by the finite element
simulation method, indicating the applicable ranges of Kastner solution and
Schulze et al solution. The stress magnification factor caused by the bending
stress of the misalignment imperfection of girth weld joint is calculated by FEM
to review the applicability of relevant formulas given in BS7910 for engineering
critical assessment. Finally, it is concluded by FE simulation that though the
stress magnification effect of shallow cracks in weld toe zone is significant, it
may be insignificant in its fracture failure assessments.
  pipeline defect, girth weld, stress magnification factor, misalignment, weld toe

                                          B. Fang
                   RES Integrity Services, Calgary, AB, Canada,T2P 1A1
                     Environmental Corrosion Center, Institute of Metal
                        Research, Chinese Academy of Sciences,
                                Shenyang, 110016, China
                                         R. Eadie
                       Dept. of Chemical and Materials Engineering,
                University of Alberta, Edmonton, Alberta, Canada,T6G 2G6
                                      M. Elboujdaini
                        CANMET Materials Technology Laboratory,
                  Natural Resources Canada, Ottawa, Canada,K1A 0G1
Specimens from a failed X-52 pipeline that had been inservice for 34 years
were pitted using the passivation/immersion method developed by the authors
to simulate pitted pipelines observed in service. The resulting pitted samples
were then cyclically loaded in an aqueous near-neutral pH environment
sparged with 5% CO2 / balance N2 gas mixture at high stress ratios (minimum
stress/maximum stress), low strain rates and low frequencies which were
close to those experienced in service. It was found that the majority of cracks
initiated from
the corrosion pits and were less than 0.5 to 0.6 mm deep and were generally
quite blunt. These cracks were transgranular in nature and designated as
Stage I cracks and were typical of cracks found in most crack colonies.
However, the further growth of these short, blunt cracks was significantly
influenced by the distribution of the nearby non-metallic inclusions.
Inclusions enhanced the stress-facilitated dissolution crack growth, which is
the crack growth method proposed by the authors in a related paper. When the
orientation of the inclusions was at a small acute angle to the orientation of the
pits or cracks, and the inclusions were in the same plane as crack initiation or
advance, these inclusions would enhance crack growth, or even trap hydrogen
which further resulted in the formation of clusters of tiny cracks, which
appeared to be caused by hydrogen. The hydrogen-produced cracks could be
eaten away later by the stress-facilitated further dissolution of the blunt cracks.
If these cracks can grow sufficiently however they pose an integrity risk, as
they can initiate long cracks (nearneutral
pH SCC). These hydrogen-caused cracks in Stage I were rare. It was
nevertheless suggested that cracks deeper than 0.5 to 0.6 mm in the field
should be removed to reduce or avoid the threat of rupture. If active corrosion
and hydrogen generation can be prevented then smaller cracks are innocuous.

                    Jong-hyun Baek* , Young-pyo Kim* , Cheol-man Kim*,
                    Woo-sik Kim*, Jae-mean Koo** and Chang-sung Seok**
                       * R&D   Division, KOGAS, Ansan, 425-150, Korea
** Department   of Mechanical Engineering, Sungkyunkwan University, Suwon, 440-746 Korea
The objective of this study was to investigate the effect of the dent magnitude
on the collapse behavior of dented pipe subjected to a combined internal
pressure and in-plane bending.
The plastic collapse behavior and bending moment of the dented pipe with
several of dent dimensions were evaluated by using elastic–plastic finite
element (FE) analyses.
The indenters used to manufacture the dents on the API 5L X65 pipe were
hemispherical rod type with diameter of 40, 80, 160 and 320 mm. Dent depths
of 19, 38, 76, 114 and 152 mm were introduced on the pipe having a diameter
of 762 mm and a wall thickness of 17.5 mm in analyses. A closing or opening
inplane bending moment was applied on the dented pipes pressurized under
internal pressure of the atmospheric pressure, 4, 8 and 16 MPa. The FE
analyses results showed that the plastic collapse behavior of dented pipes was
considerably governed by the bending mode and the dent geometry.
Momentbending angle curves for dented pipe were obtained from computer
simulation and evaluated with a variety of factors in FE analyses.
Load carrying capacity of dented pipes under combined load was evaluated by
TES (Twice Elastic Slope) moments.
Load carrying capacity of pipe having up to 5% dent depth of outer diameter
was not reduced compared with that of plain pipe. Opening bending mode had
a higher load carrying capacity than closing bending mode under combined
load regardless of dent depth. TES moment was decreased with increasing the
dent depth and internal pressure regardless of bending modes.

                             Guangli Zhang Jinheng Luo
     Tubular Goods Research Center of CNPC Tubular Goods Research Center of CNPC
                              XI’AN, China XI’AN, China
                               Xinwei Zhao Hua Zhang
     Tubular Goods Research Center of CNPC Tubular Goods Research Center of CNPC
                              XI’AN, China XI’AN, China
                                Liang Zhang Yi Zhang
     Tubular Goods Research Center of CNPC Tubular Goods Research Center of CNPC
                              XI’AN, China XI’AN, China
The fatigue character of electric resistance weld (ERW) seams in API X65
grade line pipe steel at the stress ratio of 0.1 and 0.6 have been investigated.
Repeated loading was applied to compact tension specimen, and the fatigue
crack propagation rate and threshold of X65 ERW pipe seam are tested using
high-frequency fatigue testing machine. Radiographic inspection has shown
that the crack caused by the cold welding is the main weld defect in the ERW
pipe. Based on the failure assessment diagram (FAD) recommended in the
API 579-2007 and the Miner’s linear cumulative damage model, considering
the influence of stress ratio to the fatigue life, the fatigue life assessment
method for the ERW pipe containing seam defects is established.
Keywords: ERW welding Pipe, fatigue character, fatigue life assessment,
Miner linear cumulative damage model.
Adriana Forero                José A. da Cunha              Ivani de S. Bott
Ballesteros                   Ponciano                      Associate Professor, PhD
Researcher, Dr                Associate Professor, Dr       PUC-Rio
PUC-Rio                       PEMM-UFRJ                     Rio de Janeiro, Brazil
Rio de Janeiro, Brazil        Rio de Janeiro, Brazil
The growing demand for natural gas and oil, as energy sources, has driven
industry’s need for ever-increasing strength levels in oil and gas transmission
pipeline materials in order to achieve safe and economic transportation. The
current world trend points to the use of pipes with larger diameters and thinner
wall thicknesses, operating under high pressure. In addition, pipeline steels for
sour service must exhibit good Hydrogen Induced Cracking (HIC) and
Sulphide Stress Corrosion Cracking (SSCC) resistance. This study evaluates
the susceptibility of API 5L-X80 girth welds to SSCC and Hydrogen
Embrittlement (HE). Slow strain rate tensile (SSRT) tests and Hydrogen
Permeation tests were performed at room temperature, in different acidic
environment containing sodium thiosulfate solutions. Most of the SSRT tests
undertaken in solution, showed a loss of ductility and a decrease in the
reduction of area, as compared with tests conducted in air. The susceptibility
to HE and potentially SSCC was evidenced by a reduction in ductility in the
SSRT tests and an increase in the hydrogen permeation current values, for
almost all welded joints. This was observed with greater intensity for the more
acidic test solutions (pH= 3.4), while for the less acidic test solutions (pH= 4.4)
little loss of ductility was observed and the hydrogen permeation current
remained at values close to zero, indicating little or no permeation of hydrogen
through the metal for the testing times applied. The behaviour exhibited by the
samples tested in the more acidic solutions was attributed to the dissolution of
material from the sample together with hydrogen embrittlement. These results
confirmed that the use of sodium thiosulfate solutions to generate H2S,
permits the study of phenomena related to SCC in environments containing

                 Husain Mohammed Al-Muslim
      King Fahd University of Petroleum & Minerals,Dhahran, Saudi Arabia
                                 Abul Fazal M. Arif
      King Fahd University of Petroleum & Minerals,Dhahran, Saudi Arabia
Mechanical damage in transportation pipelines is a threat to its structural
integrity. Failure in oil and gas pipelines is catastrophic as it leads to personal
fatalities, injuries, property damage, loss of production and environmental
pollution. Therefore, this issue is of extreme importance to Pipeline Operators,
Government and Regulatory Agencies, and local Communities. As mechanical
damage can occur during the course of pipeline life due to many reasons,
appropriate tools and procedures for assessment of severity is necessary.
There are many parameters that affect the severity of the mechanical damage
related to the pipe geometry and material properties, the defect geometry and
boundary conditions, and the pipe state of strain and stress. The main
objective of this paper is to investigate the effect of geometry, material and
pressure variability on strain and stress fields in dented pipelines under static
and cyclic pressure loading using probabilistic analysis. Most of the published
literate focuses on the strain at the maximum depth for evaluation which is not
always sufficient to evaluate the severity of a certain case. The validation and
calibration of the base deterministic model was based on full-instrumented
full-scale tests conducted by Pipeline Research Council International as part of
their active program to fully characterize mechanical damage. A total of 100
cases randomly generated using Monte Carlo simulations are analyzed in the
probabilistic model. The statistical distribution of output parameters and
correlation between output and input variables is presented. Moreover,
regression analysis is conducted to derive mathematical formulas of the output
variables in terms of practically measured variables. The results can be used
directly into strain based design approach. Moreover, they can be coupled with
fracture mechanics to assess cracks, for which the state of stress must be
known in the location of crack tip, not necessarily found in the dent peak.
Furthermore, probabilities derived from the statistical distribution can be used
in risk assessment.
KEYWORDS dented pipe, integrity assessment, variability, strain, stress, FEA,
probabilistic analysis.


  Mark Slaughter, Global Product Line Manager      Kevin Spencer, Integrity Consultant, PII
                Crack Inspection                            1003 11 Street SW,
   PII Pipeline Solutions, a GE Oil & Gas and Al          Calgary, T2R 0T4, Canada
            Shaheen joint venture (PII)                     Tel: +1 403 298 0231
     4424 West Sam Houston Parkway North,                      Fax: +1 403 237 9693
               Houston, TX. USA 77041                     Email: kevin.spencer@ge.com
                Tel: +1 713805 6927
                Fax: +1 713937 0740
         Email: mark.slaughter@ge.com
     Jane Dawson, Principal Consultant, PII       Petra Senf, Technical Leader Ultrasonics, Global
     Atley Way, North Nelson Industrial Estate,                    Analysis, PII
   Cramlington, Northumberland, NE23 1WW, UK                      Lorenzstrasse 10
                Tel: +44 191 247 3429                        76297 Stutensee, Germany
               Fax: +44 191 247 3461                           Tel: +49 7244 732 386
          Email: jane.dawson@ge.com                            Fax: +49 7244 732 123
                                                             Email: petra.senf@ge.com

Ultrasonic inline inspection (ILI) tools have been used in the oil and gas
pipeline industry for the last 14 years to detect and measure cracks. The
detection capabilities of these tools have been verified through many field
investigations. ILI ultrasonic crack detection has good correlation with the
crack layout on the pipe and estimating the maximum crack depth for the crack
or colony. Recent analytical developments have improved the ability to locate
individual cracks within a colony and to define the crack depth profile.
As with the management of corroding pipelines, the ability to accurately
discriminate active from non-active cracks and to determine the rate of crack
growth is an essential input into a number of key integrity management
decisions. For example, in order to identify the need for and timing of field
investigations and/or repairs and to optimize re-inspection intervals crack
growth rates are a key input. With increasing numbers of cracks and crack
colonies being found in pipelines there is a real need for reliable crack growth
information to use in prioritizing remediation activities and planning
re-inspection intervals. So as more and more pipelines containing cracks are
now being inspected for a second time (or even third time in some cases), the
industry is starting to look for quantitative crack growth information from the
comparison of repeat ultrasonic crack detection ILI runs.
This paper describes the processes used to analyze repeat ultrasonic crack
detection ILI data and crack growth information that can be obtained.
Discussions on how technical improvements made to crack sizing accuracy
and how field verification information can benefit integrity plans are also

Paul Laursen                                      InvoDane Engineering Ltd.
Toronto, Ontario, Canada                    The Northeast Gas Association
Daphne D’Zurko                              Needham, MA, USA
Dr. George Vradis                           Brooklyn, NY, USA
Department of Mechanical Engineering        Craig Swiech
Polytechnic Institute of New York           National Fuel
University                                  Buffalo, NY, USA
The present paper presents the development effort and precommercial
deployment of Explorer II – a semi-autonomous, self-powered, tetherless
robotic platform, carrying a Remote Field Eddy Current (RFEC) sensor, for the
inspection of unpiggable natural gas transmission and distribution pipelines in
the 6 to 8 inch (152 to 203 mm) range, including those that feature multiple
diameters, short radius and mitered bends, and tees. The system is based on
a modular design that allows the system to be deployed in various
configurations to carry out visual inspection and/or non-destructive evaluation
(NDE) of a pipeline. The heart of this system is a RFEC sensor able to
measure the pipeline’s wall thickness. In addition, two fisheye cameras at each
end of the robot provide high quality visual inspection capabilities for locating
joints, tee-offs, and other pipeline features. The system can operate, including
launching and retrieval, in live pipelines with pressures up to 750 psig (50 bars).
The system is currently being offered for precommercial deployments and is
expected to be commercially available in the Fall of 2010.

                    ENERGY PIPELINES
                  Sam Hall                                  Steve Fischer
              U.S. DOT/PHMSA                           U.S. DOT/PHMSA
             Washington, DC, USA                      Washington, DC, USA
Over the past 20 years, excavation damage has caused approximately
one-third of energy pipeline incidents resulting in fatalities or in-patient
hospitalizations in the U.S. While excavation damage to pipeline facilities has
declined in recent years, reducing excavation damage to energy pipelines
remains a top priority for the United States. The Pipeline and Hazardous
Materials Safety Administration (PHMSA) of the U.S. Department of
Transportation is undertaking several initiatives to reduce excavation damage
to energy pipelines. This paper summarizes several of these initiatives,
including: PHMSA’s strong support of the 1999 Common Ground Study, the
Common Ground Alliance (CGA), and the continued development of damage
prevention best practices for all damage prevention stakeholders; the
documentation of State damage prevention programs to understand where
programs can be strengthened; support of State damage prevention programs
in the form of funding and other assistance to states for implementation of the
“nine elements” of effective damage prevention programs; a focused damage
prevention research and development program; the coordination of the
Pipelines and Informed Planning Alliance (PIPA), which is an effort to develop
and foster the use of recommended practices for local land use in the vicinity
of transmission pipelines; and the development of a rule for federal
enforcement of damage prevention laws when appropriate. PHMSA believes
comprehensive damage prevention programs are essential to energy pipeline
safety and must have the right balance of incentive and enforcement for
preventing damage to pipelines.

   Hamood Rehman                   Intelligent Optical               TransCanada.
     Applus-RTD.                     Systems, Inc.                Calgary, AB, Canada
  Houston, TX, U.S.A.          Los Angeles, CA, U.S.A.
     Marvin Klein                   Richard Kania
      Steve Rapp                    Rick McNealy                   Martin Fingerhut
    Spectra Energy                    Applus-RTD                      Applus-RTD
  Houston, TX, U.S.A.            Houston, TX, U.S.A.              Houston, TX, U.S.A.
                                  Homayoon Ansari
                            Intelligent Optical Systems, Inc.
                               Los Angeles, CA, U.S.A.
Integrity management decisions related to operating energy transmission pipelines
affected by Stress Corrosion Cracking (SCC) represent a formidable challenge to the
pipeline industry. Effective management of SCC damage requires the development of
tools and technology to identify the occurrence of SCC and to assess the impact of the
SCC on pipeline integrity. Development of practical non-destructive evaluation (NDE)
solutions for the measurement and evaluation of SCC, including crack depths, is
difficult due to the complexity of crack shapes and their inter-relationship and
distribution within crack colonies.
Laser ultrasonics is an inspection technology using laser beams to generate and detect
ultrasonic waves in the pipeline wall to be inspected. Unlike conventional ultrasound,
it has a large bandwidth and the beams have a very small (~0.5mm) footprint. These
characteristics make it ideally suited for application as a depth sizing tool for SCC in
Through a collaborative research project jointly funded by the US Department of
Transportation, Pipeline and Hazardous Materials Safety Administration (PHMSA)
and PRCI, Applus RTD and its research partners have conclusively shown that laser
ultrasonic inspection technology using the Time of Flight Diffraction (TOFD)
technique reliably and accurately measures the depth of SCC. In addition, this
technique may also be applicable to measuring the depth of other cracks such as seam
weld anomalies. The project included the development of a prototype NDE inspection
tool for measurement of SCC, and recently culminated with a series of full-scale
demonstrations of the tool.
This paper describes the detailed technical work conducted to support the
development of the tool and validation of the TOFD technique for sizing the depth of
SCC. In addition, this paper presents the preliminary results of work on a closely
related project that builds on the technology described above to produce an integrated
approach and tool for mapping, sizing, and evaluating SCC that filters significant (i.e.,
deep) cracks from more benign cracks within an SCC colony.

Marc Baumeister                 Nourreddine Bouaoua              Frank Woltermann
RTRC                            RTRC                             RTRC
Lingen, Germany                 Lingen, Germany                  Lingen, Germany
Thomas Hennig                   Maria Berlekamp                  Thomas Beuker
RTRC                            RTRC                             ROSEN
Lingen, Germany                 Lingen, Germany                  Lingen, Germany
Ultrasonic crack detection represents a reliable and accepted inline inspection
technology for the application in liquid media.
The technology is long standing and considered as industry standard [1-3]. As a result
of various demands, e.g. increased temperature levels above 70°C, high pressures
exceeding 100 bars and medium types (e.g. heavy crude oil) with inherently high
damping and temperature dependency of the damping characteristic the complexity
can be primarily found within the bounding conditions. The reduction of inner
pipeline diameter, e.g. below 120 mm, represents a further increase of degree of
complexity. This paper gives access to the design and development approach chosen
by ROSEN for ultrasonic crack detection tools and the case of pipelines with an outer
diameter ranging from 6” to 8”. All previously mentioned issues and requirements are
considered. The mechanical design of the ultrasonic crack detection tools is described.

       Jane Dawson, Principal Consultant                Martin Bluck, Product Manager
  PII Pipeline Solutions, a GE Oil & Gas and Al   PII, Atley Way, North Nelson Industrial Estate,
           Shaheen joint venture (PII)              Cramlington, Northumberland, NE23 1WW, UK
    Atley Way, North Nelson Industrial Estate,                Tel: +44 191 247 3429
 Cramlington, Northumberland, NE23 1WW, UK                 Email: martin.bluck@ge.com
             Tel: +44 191 247 3429
         Email: jane.dawson@ge.com
     Ian Fisher, Senior Integrity Engineer               Jeff Sutherland, Chief Engineer
  PII, Atley Way, North Nelson Industrial Estate,            PII, 1003 11th Street SW,
 Cramlington, Northumberland, NE23 1WW, UK                  Calgary, T2R 0T4, Canada
             Tel: +44 191 247 3200                             Tel: +1 403 204 5255
           Email: ian1.fisher@ge.com                       Email: jeff.sutherland@ge.com

     Recent enhancements in the Magnetic Flux Leakage (MFL) in-line inspection (ILI)
technology has enabled more reliable detection and more accurate reporting of a
greater range of anomaly types than ever before, though the true value rests with what
the integrity engineering specialists are able to do with the enhanced information to
translate it into an actionable Integrity Management Plan. This paper describes how
the enhanced information can be used in engineering criticality assessments and the
benefits this brings to the operator in the form of integrity management
decision-making with higher confidence, reduced investigation and repair costs and
less operational disruption from ILI activity.
This paper demonstrates how the new holistic data approach brings a seamless
transition from raw inspection data to an actionable integrity report, with more
advanced assessment of metal loss and mechanical damage data. Engineering
criticality assessments are used to illustrate how the enhanced ILI information is used
and how the results benefit integrity management decision-making. For example:
 • Fitness for Service corrosion assessment determines the immediate and future
     integrity needs by evaluating the criticality of corrosion anomalies identified
     during an ILI. Taking account of the reduced ILI uncertainty associated with the
     new MFL technology, the immediate and short-term response schedules can be
     developed with higher confidence than before and long term remediation activities
     and re-inspection intervals can be truly optimized.
 • For re-inspections, the focus is on the determination of accurate corrosion growth
     rates. Using signal-matching techniques, active corrosion sites can be identified
     and the corrosion growth rates estimated with high confidence. This provides the
     basis for optimizing the long-term remediation activities and re-inspection
 • The ability to account for coincidental anomalies and loading conditions, e.g., the
     occurrence of bending strains resulting from loss of ground support coincident
     with girth weld anomalies, circumferential corrosion or denting/buckling are
     important integrity considerations that influence how the anomalies are assessed.
 • Improved Caliper sensor resolution enables the dent profile to be visualized more
     accurately leading to improvements in the way dents are assessed, i.e. using
     strain-based methods. Reliable detection of gouging within dents is an essential
   component for establishing the cause and assessing the severity of dents and has
   always been challenging for conventional MFL ILI tools. This enhanced MFL
   technology enables metal loss within dents to be detected and viewed via a
   Triaxial magnetic sensor system, providing more information of the nature of the
   metal loss within the dent.

              Stijn Hertelé                              Stijn.Hertele@UGent.be
         FWO Flanders Aspirant                               Wim De Waele
            Laboratory Soete                                Laboratory Soete
            Ghent University                                Ghent University
             Gent, Belgium                                   Gent, Belgium
              Rudi Denys                                 Jeroen Van Wittenberghe
            Laboratory Soete                                Laboratory Soete
            Ghent University                                Ghent University
             Gent, Belgium                                   Gent, Belgium
                                   Matthias Verstraete
                                    Laboratory Soete
                                    Ghent University
                                     Gent, Belgium

Curved wide plates are a valuable tool in the assessment of defective pipeline girth
welds under tension. Throughout the years, Laboratory Soete collected an extensive
database of curved wide plate test results. In an effort to investigate these results
through FAD analysis, the authors recently developed a reference stress equation for
curved plates. The approach followed is similar to the development of the Goodall
and Webster equation for flat plates. This paper elaborates finite element analyses of
the equation‟s capability to predict plastic collapse. It is found that, although
overestimated, the influence of plate curvature is correctly predicted in a qualitative
way. For all simulations, the curved plate reference stress equation produced
conservative estimations. This indicates that the proposed equation is suited to safely
predict the plastic collapse of defective pipeline girth welds. An experimental
validation is underway.

 Early Generation Pipeline Girth Welding Practices and Their Implications for
             Integrity Management of North American Pipelines
                                    Bill Amend. P.E.
                                  DNV Columbus, Inc.
                                 Yorba Linda, CA, USA
The characteristics of early generation pipelines (i.e., “vintage pipelines”) reflect the
rapid evolution of pipeline materials, welding, and inspection practices that occurred
during the first half of the twentieth century. The diverse range of welding and
inspection practices and the unique characteristics of early
generation pipeline welds can influence pipeline segment risk ranking and integrity
assessment. This paper summarizes some of the key findings regarding girth weld
fabrication, performance and integrity assessment determined during the course of a
literature review performed as part of a recently completed PRCI project.
Some of the key findings include:
1. The failure rate of early generation girth welds is low, particularly for welds made
by arc welding and for welds made after 1930. This is especially true when
considering the rate of catastrophic failures (ruptures or nearly full circumference
breaks). Welds are typically reported to be responsible for no more than about 6% of
significant pipeline failures.
2. Pipeline girth welds are unlikely to fail unless subjected to axial strains that far
exceed the strains related to internal pressure alone. Girth welds containing significant
workmanship flaws are likely to be resistant to failure at stresses less than the pipe
yield strength unless the welds are undermatched and/or are susceptible to brittle
fracture initiation. Common mechanical tests, such as Charpy impact testing or CTOD
tests may result in grossly conservative indications of the likelihood of brittle fracture
occurring in vintage girth welds.
3. A diverse range of early generation girth weld joint designs exist, some of which
hamper effective inspection using ILI or represent challenges to effective assessment
using conventional fitness-for-service or engineering critical assessment methods
(ECA). Effective probabilistic ECA is further hampered by wide variations in
workmanship and difficulty in determining mechanical property distributions.
4. Pipeline vintage is a poor indicator of girth weld integrity. Pipeline girth weld
integrity is more likely related to projectspecific inspection and testing practices than
to pipeline age. Welding and inspection practices evolved very quickly in the 1920s
through the 1940s and a wide range of practices were used on different pipelines that
were constructed in the same time period. Girth weld integrity is typically highest for
post 1930s pipelines that were subjected to radiographic inspection.

       Peter D. Chan, M.Sc., P.Eng.                        David Webster, P.Eng.
        WorleyParsons Canada Ltd.                        WorleyParsons Canada Ltd.
         Calgary, Alberta, Canada                         Calgary, Alberta, Canada
In-line inspection (ILI) gives pipeline operators a snapshot of the condition of their
pipelines. Unfortunately, accuracy limitations exist with all ILI tools. It is therefore
judicious for pipeline operators to support their pipeline integrity maintenance
planning by employing Probability of Exceedance (POE) methodology that accounts
for the inexact nature of the ILI data.
A new method is needed that can be used to assist pipeline operators make rational
and defensible integrity decision when faced with very poor pipeline conditions with
numerous interacting metal loss defects. The normal method of using RSTRENG with
Monte Carlo Simulation (MC) for probabilistic assessment of corroded pipeline
pressure is unsuitable and unmanageable. The new method employs DNVRP- F101
with Point Estimate Method (PE) and the MC to efficiently apply the POE
methodology to severely corroded pipelines.

      Kevin Spencer, Integrity Consultant          Shahani Kariyawasam, Principal Engineer
 PII Pipeline Solutions Business of GE Oil & Gas            TransCanada Pipelines
                      th                                             st
              1003 11 Street SW,                               450 1 Street SW,

           Calgary, T2R 0T4, Canada                       Calgary, T2P 5H1, Canada
              Tel: +1 403 298 0231                           Tel: +1 403 920 6502
          Email: kevin.spencer@ge.com                                Email:
  Cathy Tetreault, Pipeline Integrity Specialist     Jon Wharf, Senior Pipeline Integrity
 PII Pipeline Solutions Business of GE Oil & Gas                   Specialist
                      th                           PII Pipeline Solutions Business of GE Oil &
              1003 11 Street SW,
           Calgary, T2R 0T4, Canada                                       th
                                                              1003 11 Street SW,
              Tel: +1 403 298 0238
         Email: cathy.tetreault@ge.com                     Calgary, T2R 0T4, Canada
                                                             Tel: +1 403 298 0266
                                                           Email: jon.wharf@ge.com

Corrosion growth rates are an essential input into an Integrity Management Program
but they can often be the largest source of uncertainty and error. A relatively simple
method to estimate a corrosion growth rate is to compare the size of a corrosion
anomaly over time and the most practical way to do this for a whole pipeline system
is via the use of In-Line Inspection (ILI). However, the reported depth of the anomaly
following an ILI run contains measurement uncertainties, i.e., sizing tolerances that
must be accounted for in defining the uncertainty, or error associated with the
measured corrosion growth rate. When the same inspection vendor performs the
inspections then proven methods exist that enable this growth error to be significantly
reduced but these methods include the use of raw inspection data and, specialist
software and analysis.
    Guidelines presently exist to estimate corrosion growth rates using inspection data
from different ILI vendors. Although well documented, they are often only applicable
to “simple” cases, pipelines containing isolated corrosion features with low feature
density counts. As the feature density or the corrosion complexity increases then
different reporting specifications, interaction rules, analysis procedures, sizing models,
etc can become difficult to account for, ultimately leading to incorrect estimations or
larger uncertainties regarding the growth error.
This paper will address these issues through the experiences of a North American
pipeline operator. Accurately quantifying the reliability of pipeline assets over time
requires accurate corrosion growth rates and the case study will demonstrate how the
growth error was significantly reduced over existing methodologies. Historical
excavation and recoat information was utilized to identify static defects and quantify
systemic bias between inspections. To reduce differences in reporting and the analyst
interpretation of the recorded magnetic signals, novel analysis techniques were
employed to normalize the data sets against each other. The resulting uncertainty of
the corrosion growth rates was then further reduced by deriving, and applying a
regression model to reduce the effect of the different sizing models and the identified
systemic bias. The reduced uncertainty ultimately led to a better understanding of the
corrosion activity on the pipeline and facilitated a better integrity management
decision process.

                                    Robert A. Denzine
                               Det Norske Veritas - Columbus
                                    Dublin, OH - USA
                                   Davion M. Hill Ph.D.
                       Det Norske Veritas Research & Innovation, USA
                                    Dublin, OH – USA
Composites have seen increased usage for repair of pipelines. The performance of the
entire metal-composite system has not been extensively addressed with regard to
corrosion of the substrate and adhesion loss when the conditions are wet and the
substrate is cathodically protected.
In this work we have investigated the influence of corrosive environments on the
performance of composite repair systems for pipelines. Earlier in this work we used
FEA models to evaluate a composite patch for pipelines and the present research
includes the experimental results for both patch and full-wrap composite repairs in
simulated and field environments. The effect of impacts, cathodic protection, long
term immersion, and soil corrosivity have been investigated by monitoring variables
related to potential and conductivity of the electrolyte. We have also tested
mechanical properties via four point bend on specimens intentionally exposed to
ASTM cathodic disbondment tests. We have also evaluated the performance of these
repairs in a modified ASTM G8 cathodic disbondment test with the addition of high
pressure cyclic loading. By monitoring these variables, loss of adhesion and integrity
in the composite-metal system is addressed.
Keywords: Composite repair, cathodic disbondment, nonmetallic repair, carbon fiber,
fiberglass, mechanical testing.

James Simek                    Jed Ludlow                      Phil Tisovec
T.D. Williamson Inc            T.D. Williamson Inc             T.D. Williamson Inc
Salt Lake City, Utah, USA      Salt Lake City, Utah, USA       Salt Lake City, Utah, USA
InLine Inspection (ILI) tools using the magnetic flux leakage (MFL) technique are the
most common type used for performing metal loss surveys worldwide. Based upon
the very robust and proven magnetic flux leakage technique, these tools have been
shown to operate reliably in the extremely harsh environments of transmission
pipelines. In addition to metal loss, MFL tools are capable of identifying a broad
range of pipeline features. Most MFL surveys to date have used tools employing
axially oriented magnetizers, capable of detecting and quantifying many categories of
volumetric metal loss features. For certain classes of axially oriented features, MFL
tools using axially oriented fields have encountered difficulty in detection and
subsequent quantification. To address features in these categories, tools employing
circumferential or transversely oriented fields have been designed and placed into
service, enabling enhanced detection and sizing for axially oriented features. In most
cases, multiple surveys are required, as current tools do not incorporate the ability to
collect both data sets concurrently. Applying the magnetic field in an oblique
direction will enable detection of axially oriented features and may be used
simultaneously with an axially oriented tool. Referencing previous research in
adapting circumferential or transverse designs for inline service, the concept of an
oblique field magnetizer will be presented.
Models developed demonstrating the technique are discussed, shown with
experimental data supporting the concept. Efforts involved in the implementation of
an oblique magnetizer, including magnetic models for field profiles used to determine
magnetizer configurations and sensor locations are presented.
Experimental results are provided detailing the response of the system to a full range
of metal loss features, supplementing modeling in an effort to determine the effects of
variables introduced by magnetic property and velocity induced differences. Included
in the experimental data results are extremely narrow axially oriented features, many
of which are not detected or identified within the axial data set.
Experimental and field verification results for detection accuracies will be described
in comparison to an axial field tool.

                     VARIABLE GAP
                                     Fengmei Song
                                 Mechanical Engineering
                              Southwest Research Institute
                              San Antonio, TX, USA 78238
A model is developed to predict the chemistry, corrosion potential and rate of pipeline
steels in a coating disbanded region. The gap of the disbonded region is assumed to
vary with distance from the holiday. The effect of this gap variation on the chemistry
and corrosion rate in the coating disbanded region is not well understood and
investigated in this study through modeling. The preliminary model results suggest
that overall, the variation of the disbondment gap with distance has an insignificant
effect on the pH, corrosion potential and rate in the disbonded region. This may be
explained as that unlike some conventional crevice corrosion often associated with a
large cathode-to-anode area ratio, the area ratio here is rather relatively small and the
pH commonly falls in the neutral or alkaline range. Within this pH range, even if the
pH varies within a few units across the crevice length, the variation of the crevice
corrosion rate is not significant. In this paper, the fundamental principles used for the
model, some key model results and practical implications of the results are reported
and discussed.

                      CORROSION DEFECTS
Mohamed R. Chebaro                              Wenxing Zhou
C-FER Technologies                              University of Western Ontario
Edmonton, Alberta, Canada                       London, Ontario, Canada
Currently, there exist various models that predict the burst capacity of a pipeline
containing corrosion defects. Recent studies have indicated that these models tend to
be overly conservative for long corrosion defects. This paper, based on a
PRCI-sponsored study, aims at minimizing this conservatism
through a series of steps. First, different definitions for long corrosion defects
prevalent in the literature were examined and compared, and the most suitable
criterion was implemented.
Next, three existing burst pressure models for general corrosion defects were
identified and evaluated: ASME B31G-modified, a model developed at C-FER and a
model developed at the University of Waterloo. The suitability of these models for
long corrosion defects was assessed using a database of 50 full-scale burst test
specimens containing natural long corrosion defects. Finally, based on this evaluation,
the most apposite burst pressure prediction model for long corrosion defects was
selected and a corresponding model error factor was derived.

                                                           IPC 2010-31336
     Udayasankar                   Samarth Tandon               Blade Energy Partners
      Arumugam                  Blade Energy Partners           Houston, Texas, USA
 Blade Energy Partners          Houston, Texas, USA
 Houston, Texas, USA                  Ming Gao
  Ravi Krishnamurthy                 Ben Hanson                   Hamood Rehman
 Blade Energy Partners               Applus RTD                      Applus RTD
 Houston, Texas, USA             Houston, Texas, USA            Houston, Texas, USA
                                   Martin Fingerhut
                                     Applus RTD
                                 Houston, Texas, USA
Traditionally, the pipeline industry and government regulations used a depth
based assessment criteria to identify and prioritize dents in the order of
severity. This depth based criteria had limitations and could potentially
underestimate dent severity. In recent years, strain parameter has been used
to characterize dent severity in a pipeline. Dent strain analysis requires dent
profile information.
In-Line Inspection (ILI) caliper tools provide both longitudinal and
circumferential dent profiles that can be used to evaluate strain. However, no
comparable technologies are available for in-ditch dent profile measurement.
The currently used profile-gauge technology only measures dent profile
through its deepest point, which may not capture the maximum strain in the
dent and could result in underestimating the severity. A recent study showed
that LaserScan 3D mapping technology provides an accurate dent 3D profile
that can easily be extracted for “point-to-point” strain analysis and is an ideal
tool for verification of ILI performance. Furthermore, LaserScan 3aD mapping
accurately measures other associated anomalies such as gouge and metal
loss. Most importantly, the advantage of employing dent LaserScan is that
strain analysis can be conducted at the excavation site and simultaneously,
strain based mitigation decision can be made in real time.
In this paper, a portable LaserScan 3D mapping technology for measurement
of dents and dents associated with other anomalies in pipelines is introduced.
Fundamentals of the technology are briefly discussed in terms of accuracy,
resolution and appropriateness for pipeline application. Examples of 3D
mapping for dent and dent with other anomalies are presented. Extraction of
dent profile and subsequent strain analysis are further demonstrated.

               Peter Song                                       J. J. Roger Cheng
         Enbridge Pipelines Inc.                               University of Alberta
       Edmonton, Alberta, Canada                            Edmonton, Alberta, Canada
             Scott Ironside                                     Darren Skibinsky
         Enbridge Pipelines Inc.                              Alliance Pipeline Ltd.
       Edmonton, Alberta, Canada                             Calgary, Alberta, Canad

Field experience showed that repairing wrinkles developed on energy pipelines using
steel sleeves is an efficient and cost effective method. Based on the previous
successful numerical simulations of a field wrinkle sleeve repair work, a parametric
study was conducted by using Finite Element (FE) method to further investigate the
effectiveness of the sleeve repair technique. The FE package ABAQUS 6.4 was
utilized in conducting the parametric study. The parameters studied include the length,
the thickness, and the material properties of the sleeve, and the thickness of the collar,
which is used to fit between the wrinkled pipe and the repairing sleeve. The range of
the parameters studied covers the most commonly used typical values in the pipeline
industry. Two phases were used in carrying out the parametric study. In Phase I, the
parameter that plays the most important role in determining the behavior of the
wrinkle sleeve repair system (WSRS) was studied. It is found this parameter is the
length of the repairing sleeve. Brief discussion was given regarding the way this
parameter affects the behavior of the pipe using the WSRS. In Phase II, based on the
results from the Phase I study, the effects of other parameters were investigated
through a series of FE analyses. Conclusions were drawn and recommendations for
future wrinkle sleeve repair work were given based on the results of the parametric

                 AND WITHOUT COATINGS
        Andrew Washabaugh, Shayan Haque, David Jablonski, Neil J. Goldfine
                                     JENTEK Sensors, Inc.
                                   Waltham, MA, 02453-7013
Coatings are used on pipelines throughout the oil and gas industry for a variety of
applications including corrosion protection, temperature maintenance, and weight
These coatings also present a barrier to inspections for damage and typically need to be
removed prior to inspection with nondestructive evaluation (NDE) methods. This has
led to the development of improved NDE methods for detection and characterization of
damage without removing the coatings or insulation.
This paper describes adaptations of JENTEK‟s Meandering Winding Magnetometer
(MWM®)-Array technology for improved NDE in pipelines, including rapid and
reliable imaging of damage, such as external corrosion, external mechanical damage,
and stress corrosion cracking (SCC). The MWM-Array technology uses magnetic
fieldbased sensor arrays and model-based inverse methods to determine
electromagnetic and geometric properties of the pipeline material, which are then
related to specific damage conditions of interest. This technology has been successfully
applied in the aerospace and manufacturing industries and provides substantially
improved performance for imaging surface and buried damage through coatings and for
curved surfaces compared to conventional NDE methods.
Several representative applications are described.
These include: 1) imaging of near surface material loss through moderate thickness
coatings (less than 1.5-in. (38 mm)); 2) imaging of mechanical damage through thin
(less than 0.25-in. (6.35 mm)) coatings; 3) imaging of SCC through very thin (less than
0.030-in. (0.76 mm)) and thin (less than 0.25-in. (6.35 mm)) coatings. For SCC, digital
imaging of damage regions and automated analysis tools for assessing individual
cracks has the potential to be a replacement for magnetic particle inspection (MPI).
Initial work has demonstrated these capabilities in a laboratory environment with some
field testing and ongoing work is transitioning this technology into field environments.

                           GROWTH RATES
           Grant A. Coleman                                  Scott J. Miller
     BJ Pipeline Inspection Services                 BJ Pipeline Inspection Services
           4839 90th Ave SE                                4839 90th Ave SE
     Calgary, AB, Canada,T2C 2S8                     Calgary, AB, Canada,T2C 2S8
         Phone: 403.531.5300                             Phone: 403.531.5300
        gcoleman@bjservices.ca                           smiller@bjservices.ca
The knowledge of the rate at which corrosion grows in a given pipeline could be used
to determine the time between inspections, find hot spots of high corrosion growth,
and possibly prevent catastrophic failure of the pipeline. For these reasons many
pipeline companies employ some method to calculate the growth between inspections
years apart. This calculation may be on two sets of inspection data from different
vendors using different technologies. This paper discusses normalization of data
which is necessary for a fair data comparison. Growth rates are calculated for the
normalized data for the complete population of anomalies, as well as individual
anomalies. Analysis of tool tolerance and repeatability is then used to put the results
into perspective.

     Herbert Willems, Beate Jaskolla,                        Frank Niese
    Thorsten Sickinger, Alfred Barbian                   FRAUNHOFER IZFP
        NDT Systems & Services                               Campus E3 1
           Friedrich-List-Str. 1                         D-66123 Saarbrücken,
           D-76297 Stutensee                                   Germany
The two prevailing technologies in in-line inspection (ILI) of pipelines used for
metal loss detection are magnetic flux leakage (MFL) and ultrasonic testing
The ultrasonic method provides a more precise depth sizing as a direct
measurement of the remaining thickness of the pipe wall is obtained. The
advantage of providing more precise defect data leads, in turn, to a more
accurate and reliable defect assessment thus reducing follow-up costs for the
pipeline operator.
As conventional ultrasonic tools, which are based on piezoelectric transducers,
require a liquid coupling medium to couple the ultrasonic energy into the pipe
wall, this technology is readily applicable to the majority of liquids pipelines, but
not to gas pipelines (unless a batch of liquid is used). In order to apply
ultrasonic ILI technology for metal loss inspection to gas pipelines directly, a
new tool was developed based on the EMAT (electro-magnetic acoustic
transducer) principle by which ultrasound is generated in the surface of the
pipe wall through electromagnetic interaction.
EMAT sensors utilize coils for sending and receiving ultrasound. Since coils
can also be used to pick up MFL signals and eddy current signals, the sensors
were designed such that, apart from the ultrasonic signals, these additional
signals are recorded simultaneously.
The availability of three simultaneous, independent measurements allows for
considerable improvement with regard to both defect sizing and feature
In the paper, the new sensor concept and the setup of the ILI tool are
described. First results are presented and discussed.

                                    PIPELINE STEEL
           J. H. Espina-Hernández                       F. Caleyo, J. M. Hallen
   ESIME – Zacatenco, SEPI – Electrónica       DIM-ESIQIE, Instituto Politécnico Nacional
        Instituto Politécnico Nacional                   México D. F., México
            México, D. F., México

                           A. López-Montenegro, E. Pérez-Baruch
                        Pemex Exploración y Producción, Región Sur
                                Villahermosa, Tabasco, México

These days, in-line inspections based on the magnetic flux leakage (MFL) principle
are routinely used to detect and size metal loss and mechanical anomalies in operating
oil and gas pipelines. One of the characteristics of the MFL technology is that after
the inspection, the pipeline wall shows a remanent magnetization. In this work, the
influence of the magnetic field on pitting corrosion in pipeline steel is studied. Pitting
corrosion experiments have been carried out on samples of an API 5L grade 52 steel
under a magnetization level of the same order of magnitude of the remanent
magnetization in the pipeline wall after the MFL inspection. The samples were
magnetized using rings of the investigated steel. The closed magnetic circuit
configuration used in this study survey guaranteed that the samples kept the same
magnetization level during the complete duration of the conducted experiments. This
experimental setup was used in order to reproduce the conditions observed in
MFL-inspected pipelines in which the magnetic field was confined to the pipe wall
thickness. Immediately after magnetization, the investigated samples were subjected
to pitting by immersing them in a solution with dissolved Cl and SO42 ions. The pitting
                                                                −        −

experiments were conducted for exposure times of 7 days. Non-magnetized
specimens were used as control samples. The depths of the pits induced in the
investigated samples were measured using optical microscopy. The maximum pit
depth of each sample was recorded and used to conduct extreme value analysis of the
pitting process in the magnetized and non-magnetized specimens. The results of this
investigation indicate that the magnetic field confined within the pipeline wall has a
significant influence on the pitting corrosion process. The statistical assessment of the
pitting corrosion data collected during this study shows that the magnetic field
reduces the average depth of the pit population. It also reduces the extreme pit depth
values that can be predicted from the maximum values observed in the magnetized
samples, with respect to the non-magnetized control samples. Scanning electron
microscopy observations show that the magnetic field alters the pit morphology by
increasing the pit opening (mouth). It is shown that the observed reduction in the pit
depth when a magnetic field is confined to the volume of the corroding material can
be explained based on the behavior of the paramagnetic corrosion products under the
influence of the local magnetic field gradients produced inside and within the
immediate vicinity of stable pits.
                                                         IPC2010 – 31392
Detection and In-Field Verification of Potential Pipeline Expansion Due to
           Low Yield Strength Pipe in High Strength Line Pipe
    Jill Braun                              Stuart Clouston
   Kern River Gas Transmission Company      BJ Pipeline Inspection Services
   2755 E. Cottonwood Parkway,              4839 90th Ave SE
   Salt Lake City, Utah 84121               Calgary, AB, Canada,T2C 2S8
   Phone: +1 801 9376365                    Phone: +1 403 531 5300
   jill.braun@kernrivergas.com              sclouston@bjservices.ca

On May 21, 2009, the Pipeline & Hazardous Materials Safety Administration
(PHMSA) issued an Advisory Bulletin (PHMSA-2009-0148) entitled, “Potential for
Low and Variable Yield, Tensile Strength and Chemical Compositions in High
Strength Line Pipe” [1] recommending that pipeline operators investigate whether
recently constructed pipelines contain pipe joints not meeting the minimum
specification requirements (74FR2390). Based on PHMSA‟s technical reviews, high
resolution deformation tool inspection combined with comprehensive infield
verification has been recommended in accordance with the “Interim Guidelines for
Confirming Pipe Strength in Pipe Susceptible to Low Yield Strength,” issued by
PHMSA in September 2009[2].
Kern River Gas Transmission Company (Kern River) underwent a detailed program
of engineering and assessment in order to proactively demonstrate compliance with
the interim guidelines.
This paper discusses the process, inspection results and in-field verifications
performed by the pipeline operator. In particular, detailed consideration to the
methodology of detection and assessment of potential pipeline expansions is
presented with discussion on the special considerations needed for low level anomaly
identification, reporting and verification of expansions as defined in the PHMSA
guidelines. High resolution caliper analysis approaches developed for this particular
application are discussed and appropriate techniques are recommended that consider
the effects of possible asymmetry of expansions and impact of other deformations
such as ovality. Field verification practices and findings are reviewed in detail with
particular focus on the challenges facing the pipeline operator in resolving both tool
and in-field measurement errors that can significantly impact the number of
identifiable candidate expansions for verification. In conclusion, an overview of the
assessment criteria and field activity to comply with the PHMSA interim guidelines
are presented along with the lessons learned from the analysis, verification and
remediation steps that may assist other pipeline operators as they address these newly
established regulatory requirements.

                    ENERGY PIPELINES
           Peter Song                   Doug Lawrence                     Sean Keane
     Enbridge Pipelines Inc.         Enbridge Pipelines Inc.         Enbridge Pipelines Inc.
   Edmonton, Alberta, Canada       Edmonton, Alberta, Canada       Edmonton, Alberta, Canada

Liquids pipelines undergo pressure cycling as part of normal operations. The source
of these fluctuations can be complex, but can include line start-stop during normal
pipeline operations, batch pigs by-passing pump stations, product injection or delivery,
and unexpected line shut-down events. One of the factors that govern potential growth
of flaws by pressure cycle induced fatigue is operational pressure cycles. The severity
of these pressure cycles can affect both the need and timing for an integrity
assessment. A Pressure Cycling Monitoring (PCM) program was initiated at Enbridge
Pipelines Inc. (Enbridge) to monitor the Pressure Cycling Severity (PCS) change with
time during line operations. The PCM program has many purposes, but primary focus
is to ensure the continued validity of the integrity assessment interval and for early
identification of notable changes in operations resulting in fatigue damage.
In conducting the PCM program, an estimated fatigue life based on one month or one
quarter period of operations is plotted on the PCM graph. The estimated fatigue life is
obtained by conducting fatigue analysis using Paris Law equation, a flaw with
dimensions proportional to the pipe wall thickness and the outer diameter, and the
operating pressure data queried from Enbridge SCADA system. This standardized
estimated fatigue life calculation is a measure of the PCS. Trends in PCS overtime
can potentially indicate the crack threat susceptibility the integrity assessment interval
should be updated. Two examples observed on pipeline segments within Enbridge
pipeline system are provided that show the PCS change over time. Conclusions are
drawn for the PCM program thereafter.

            Guy Desjardins Desjardins Integrity Ltd. Calgary, Alberta, Canada
 Repeated in-line inspections (ILI) of transmission pipelines have been used for many
years to estimate corrosion rates. However, the calculation of a corrosion rate from a
direct comparison of ILI anomalies is often dominated by the ILI measurement error.
As an alternative to assessing a corrosion rate, it may be possible to use repeated
in-line inspections to simply detect the presence of active corrosion. This paper
presents the application of various statistical measures to detect active corrosion with
a high- level of confidence. From a pipeline integrity management perspective, this
method will enable the operator to address each location where there is a high
probability of active corrosion. Furthermore, despite there being no explicit
calculation of corrosion rates, the advantage of the method is that it can yield an upper
bound on the corrosion rate of anomalies left unexcavated on the pipeline.

Mark Stephens                 Maher Nessim                  Albert van Roodselaar
C-FER Technologies            C-FER Technologies            Chevron ETC
Edmonton, Alberta, Canada     Edmonton, Alberta, Canada     Houston, Texas, USA

Quantitative analysis based on structural reliability methods is ideally suited to
managing corrosion and cracking damage in pipelines as identified through in-line
An ongoing industry-sponsored initiative has laid out a reliability-based process that
is intended to form the basis for an industry-accepted approach to assessing and
managing pipeline integrity with respect to these damage mechanisms, with an initial
focus on metal-loss corrosion. The process combines appropriate failure prediction
models, in-line inspection data, the physical and operational characteristics of the
pipeline, and corrosion growth rate projections, within a probabilistic analysis
framework, to estimate the likelihood of corrosion failure as a function of time. It also
provides the means to assess the beneficial impact of selective and staged defect
remediation and to evaluate candidate remediation strategies to determine the most
cost-effective approach.
This paper summarizes the reliability-based assessment and integrity management
process. It also illustrates how the results provided can be used to determine the most
cost-effective maintenance strategy in terms of the number of features to be
remediated and the preferred time to next inspection.

 An Approach for Evaluating and Prioritizing Dents for Remediation as
                       Reported by ILI Tools
Udayasankar Arumugam                            David Z. Kendrick
Blade Energy Partners                           Williams-Northwest Pipeline
Houston, Texas, USA                             Salt Lake City UT, USA
Sergio Limón-Tapia                              Ming Gao
Williams-Northwest Pipeline                     Blade Energy Partners
Salt Lake City UT, USA                          Houston, Texas, USA
Analytical and experimental methods exist to help in the determination of critical
strain levels for plain dents.
Government regulations and industry standards require ranking the severity of dents
reported by ILI tools for excavation primarily based on depth. These requirements
also allow the use of engineering critical analysis methods to demonstrate that critical
strain levels are not exceeded.
This paper discusses the use of a laser mapping tool in conjunction with a modified
method for determining static strains for prioritization and remediation of plain dents.
The development of a correlation factor based on the examination of 6 dents and their
respective ILI reports is presented and discussed. The application of the severity
correlation factor to the remaining dents reported in the pipe section for their
prioritization for remediation is also presented.

 Investigate Performance of Current In-Line Inspection Technologies For Dents
             and Dent Associated with Metal Loss Damage Detection
               Ming Gao                                      Ravi Krishnamurthy
         Blade Energy Partners                              Blade Energy Partners
          Houston, Texas, USA                               Houston, Texas, USA
Integrity management of dent and dent associated with metal loss requires knowledge
of in-line inspection (ILI) technologies, government regulations and industry codes,
prescriptive requirements, and most importantly assessment models to estimate
severity of the mechanical damage. The assessment models have greatly relied on the
assumed capabilities of current ILI technologies to detect, discriminate and size the
mechanical damage. Therefore, an investigation of the current ILI technologies and
validation of their capabilities are practically important.
In this paper, the current status of ILI technologies for dent and dent with metal loss is
reviewed. Validation data provided by ILI inspection vendors and pipeline operators
are analyzed in terms of probability of detection (POD), probability of identification
(POI), probability of false call (POFC), and sizing accuracy using binomial
probability distribution and confidence interval methods. Linear regression analysis is
also performed to determine sizing error bands. High resolution pull test data
validated with LaserScan 3-D mapping technology is used to demonstrate a better
evaluation of ILI performance with minimized in-ditch measurement errors and the
effect of change in dent geometry and dimension due to re-bounding and rerounding.
Issues associated with field measurement and improvement are discussed.


                                    Khalid A. Farrag
                                 Gas Technology Institute
                     1700 S. Mount Prospect Rd, Des Plaines, IL USA
                                  Phone: 847-768-0803

External corrosion growth rate is an essential parameter to establish the time interval
between successive pipe integrity evaluations. Actual corrosion rates are difficult to
measure or predict. NACE Standard RP0502 [1] recommends several methods
including comparison with historical data, buried coupons, electrical resistance (ER),
and Linear Polarization Resistance (LPR) measurements.
This paper presents a testing program and procedure to validate the use of the LPR
and ER methods to enhance the estimation of corrosion growth rates and improve the
selection of reassessment intervals of gas transmission pipelines.
Laboratory and field tests were performed using the LPR and ER technologies. The
evaluation of soil parameters that affect localized corrosion included its type, moisture
content, pH, resistivity, drainage characteristics, chloride and sulfite levels, and soil
Redox potential.
The results show that the LPR device provides instantaneous measurement of
corrosion potential and it may be used to reflect the variations of corrosion rates with
the changes of soil conditions, moisture, and temperature. However, LPR
measurements are more efficient in saturated soils with uncertainty about its validity
in partially and totally dry soils. Consequently, seasonal changes in soil conditions
make it difficult to estimate total corrosion growth rate. On the other hand, the
measurements using the ER method provided consistent estimates for long-term
corrosion growth rates.
Corrosion growth rates were also evaluated from a previous study by the National
Institute of Standards (NIST) [2]. A procedure was developed to correlate soil
properties to corrosion rates from the ER measurements and NIST data. The
procedure was implemented in a computer program to provide an estimate of
corrosion rate based on the soil input data and allows the operator to use the ER
probes to improve the reliability of corrosion rate estimates.

                    Khalid A. Farrag                                  Robert B. Francini
                Gas Technology Institute                              Kiefner & Associates
      1700 S. Mt Prospect Rd, Des Plaines, IL USA         585 Scherer Court, Worthington, OH USA
                 Phone: 847-768-0803                               Phone: 614-888-8220
            Khalid.farrag@gastechnology.org          bfrancini@kiefner.com
The paper presents the results of a testing program to characterize mechanical damage
(dents and gouges) to pipelines at low operating pressures (i.e., at stress levels below
40% of the Specified Minimum Yield Strength, SMYS of the pipe material). The
testing program was performed on pipelines of different sizes and grades; and the
pipes were subjected to various gouges and dents when pressurized at 40% SMYS.
The results of rupture tests on the pipes were compared with the „European Pipeline
Research Group (EPRG) Simplified Model‟ criterion.
The results show that the model is sufficiently conservative to be used for evaluating
mechanical damage of low-stress gas pipelines. The results provide guidelines for gas
utilities to assess the damage at these stress levels. These guidelines allow a pipeline
operator to assess the repair needs of a pipeline based on its operating pressure and
damage level.

Rick McNealy                   Sergio Limon-Tapia                Richard Kania
Applus-RTD                     Williams Gas Pipeline             TransCanada.
Houston, TX                    Salt Lake City, UT                Calgary, AB
                    Martin Fingerhut     Harvey Haines
                    Applus-RTD           Kiefner & Associates, Inc.
                    Houston, TX          Vienna, VA

In-Line Inspection (ILI) surveys are widely employed to identify potential threats by
capturing changes in pipe condition such as metal loss, caused by corrosion. The
better the performance and interpretation of these survey data, the higher the
reliability of being able to predict the actual condition of the pipe and required
remediation. Each ILI survey has a certain level of conservatism from the assessment
equations such as B31G and sensitivity to ILI performance for measurement
uncertainty. Multiple levels of conservatism intended to limit the possibility of a
non-conservative assessment can result in a significant economic penalty and
excessive digs without improving safety. A study was undertaken to evaluate the
reliability of responses to ILI corrosion features through multiple case studies
examining the effects of failure criteria and data analysis parameters. This paper
discusses the effect of validated ILI performance on safety, and addresses the risk of
false acceptance of corrosion indications at a prescribed safety factor. The cost of
unnecessary excavations due to falsely rejecting ILI predictions is also discussed.

                                   PIPE MATERIAL
              Kimberly Cameron                                 Alfred M. Pettinger
           kcameron@exponent.com                          apettinger@exponent.com
   Exponent, Failure Analysis Associates            Exponent, Failure Analysis Associates
           Menlo Park, CA 94025, USA                          Irvine, CA 92618, USA
Pipeline systems are typically subjected to hydrostatic testing to help ensure pipeline
integrity. It can be desirable to use the highest feasible test pressure to eliminate as
many defects as possible. It is widely accepted that safe control of yielding can be
achieved during hydrostatic testing and that the hydrostatic testing does not create a
stress state that is less safe from the standpoint of pre-existing flaws. For a small
percentage of cases, however, hydrostatic testing can produce flaws that were longer
than the ones removed. In these few cases, the flaws can then fail at a lower test
pressure than the original hydrostatic test. The low probability of these events,
however, means that the effectiveness of the hydrostatic test is not significantly
diminished in this case.
Because crack growth from a pre-existing flaw is retarded in a plastically deformed
material, it is also typically assumed that hydrostatic testing should not lead to
accelerated crack growth. However, this does not take into account that the
hydrostatic testing itself can cause some increment in crack growth and that for many
higher strength pipe materials significantly large defects can survive hydrostatic
These longer defects can potentially grow after surviving a hydrostatic test. This
paper discusses this difference in crack growth rates for cracks that have survived
hydrostatic testing in different grade pipeline steels and the implications for
hydrostatic testing.

 Afolabi T. Egbewande            AbdoulMajid Eslami                  Weixing Chen
Chemical and Materials           Chemical and Materials              Chemical and Materials
Engineering, University of       Engineering, University of          Engineering, University of
Alberta,                         Alberta,                            Alberta,
Edmonton, Alberta, Canada        Edmonton, Alberta, Canada           Edmonton, Alberta, Canada

Near-neutral pH stress corrosion cracking (NNPHSCC), which occurs when ground
water penetrates under the pipe coating, causes longitudinal cracks to develop on the
surface of pipelines. Such cracks grow over time and can ultimately lead to pipeline
failure. NNPHSCC is currently managed by in-line inspection or hydrostatic testing
for oil and gas pipelines respectively. These procedures are enormously expensive and
have to be repeated at predetermined intervals. Re-inspection intervals are currently
determined by empirical models, which have been found rather imprecise.
A major flaw in currently applied models is that they assume that once a NNPHSCC
crack is formed, it grows at a constant rate that is independent of pipeline operating
variables and both pre- and in-service history of the pipeline material. This is not
necessarily true as pipeline history, the nature of the service environment and
operating factors, among several other factors, have a strong influence on the rate of
NNPHSCC crack propagation. Most existing models also treat NNPHSCC cracks as
long through thickness cracks rather than surface type cracks typically observed in the
This research proposes to provide an empirical model that more accurately predicts
the growth rate of near-neutral pH SCC cracks in near-neutral pH environments by
studying the growth rate of surface type flaws while also accounting for the influence
of operating factors, environmental factors, coating disbondment and cathodic
protection on the rate of crack propagation.
This paper reports some preliminary test results obtained using a long specimen with
three semi elliptical surface flaws located in three reduced sections to simulate field
observed NNPHSCC cracks. Preliminary results suggest that:
1) crack grows much faster at the open mouth, which was attributed to hydrogen
2) crack dormancy can occur under certain combined mechanical factors
3) although the benign mechanical loading cannot lead to a direct crack growth (crack
dormancy), it causes damage to the crack tip, which makes the crack more susceptible
to crack growth upon a more aggressive condition is encountered.

                      CORROSION DEFECTS
Adilson C. Benjamin              Catholic University of Rio          Catholic University of Rio
PETROBRAS R&D Center             de Janeiro                          de Janeiro
Rio de Janeiro, RJ, Brazil       Rio de Janeiro, RJ, Brazil          Rio de Janeiro, RJ, Brazil
José Luiz F. Freire              Ronaldo D. Vieira
                                       Jorge L. C. Diniz
                             Catholic University of Rio de Janeiro
                                  Rio de Janeiro, RJ, Brazil
Circumferential defects are the ones in which the width w is greater than the length L
(w > L).
In this paper the burst tests of three tubular specimens are presented. In these tests the
tubular specimens were loaded with internal pressure only. The specimens were cut
from longitudinal welded tubes made of API 5L X80 steel with a nominal outside
diameter of 457.2 mm (18 in) and a nominal wall thickness of 7.93 mm (0.312 in). Each
of the three specimens had one external circumferential corrosion defect, machined
using spark erosion. Measurements were carried out in order to determine the actual
dimensions of each tubular specimen and its respective defect. Tensile specimens and
impact test specimens were tested to determine material properties.
The failure pressures measured in the burst tests are compared with those predicted by
five assessments methods, namely: the ASME B31G method, the RSTRENG 085dL
method, the DNV RP-F101 method for single defects (Part B), the RPA method and the
Kastner equation.
Keywords: corroded pipeline, circumferential corrosion,defects, burst tests

                                                              IPC2010 – 31451
    Li Yan                     Robert Worthingham
   NOVA Research & Technology Centre          TransCanada PipeLines Limited
   Calgary, AB, Canada                        Calgary, AB, Canada

The Permeable Coating Model (PCM) is a mathematical model which has been
developed to predict the generation and evolution of environments under a disbonded
permeable coating as a consequence of the action of CP. The early version of the
PCM was presented at IPC 2004, which focused on the prediction of the environment
under a disbonded permeable coating in a fully water-saturated soil without including
the generation of CO2 in the soil. As a consequence, the model predicted the
generation of a high-pH environment for NaOH-based solution rather than a
concentrated HCO3-/CO32- trapped water. The advanced version of PCM takes into
account the generation of CO2 in soil by both microbial activity and plant roots
respiration. Also, the concept of degree of saturation was introduced, which enables
the PCM to predict the pipe surface conditions for situations in which the pipeline is
either permanently above or below the water table.
The simulation results from the advanced version of PCM show that the concentrated
carbonate (i.e, 0.1 to 1 M) and high pH (> 9) environment required for high pH SCC,
can be developed within 10 years with a CP level of -1.5VCSE and T > 25oC. For
low temperatures (i.e., T ≤ 25oC) a time longer than 10 years is necessary to establish
this concentrated carbonate and high pH environment. The results also suggest that
although the necessary environment can be generated through the application of CP =
-1.5 VCSE, the selected CP level does not cause the potential on the pipe surface to
reach the critical potential range (i.e., -750 mVCSE to -600 mVCSE) required for
high pH SCC. As expected, the loss of CP after an application of CP for 10 years
could provide the environment needed for near-neutral pH SCC to occur.

  Effects of Cathodic Protection on Cracking of High-Strength Pipeline Steels
                         M. Elboujdaini, R. W. Revie, and M. Attard
                 CANMET Materials Technology Laboratory - 568 Booth Street
                                 Ottawa, Ontario K1A 0G1
                               {email: melboujd@nrcan.gc.ca}

A comparison was made between four strength levels of pipeline steels (X-70, X80,
X-100 and the X-120) from the point of view of their susceptibility to hydrogen
embrittlement under cathodic protection. The main aim was to determine whether the
development of higher strength materials led to greater susceptibility to hydrogen
embrittlement. This was achieved by straining at 2x10-6 s-1 after cathodic charging in
a simulated dilute groundwater solution (NS4) containing 5% CO2/95% N2 (pH
approximately 6.7). The results showed quantitatively the loss of ductility after
charging, and the loss of ductility increases with strength level of the steel. All four
steels exhibited a loss of ductility at overprotected charging potential and an
increasing amount of brittleness on the fracture surface.
Ductility in solution was measured under four different levels of cathodic protection,
ranging from no cathodic protection to 500 mV of overprotection with respect to the
usually accepted criterion of −850 mV vs. Cu/CuSO4 reference electrode.
Experiments were carried out by straining during cathodic polarization in a simulated
dilute ground water solution (NS-4 solution). Strain rates used were 2×10−6 s−1.
After failure, the fracture surfaces were characterized by examination using scanning
electron microscopy (SEM).
Under cathodic protection, all four steels showed loss of ductility and features of
brittle fracture. The loss of ductility under cathodic polarization was larger the greater
the strength of the steel and the more active (i.e., more negative) the applied potential.
The Ductility Reduction Index (DRI) was defined to quantify the reduction in

   Robert M Andrews1            BP Exploration Operating           GL Noble Denton Ltd
BMT Fleet Technology Ltd                  Co Ltd                    Loughborough, UK
Mountsorrel, Loughborough,         Sunbury-on-Thames,
           UK                           Middlesex,
 bandrews@fleetech.com               United Kingdom
     James Johnson                   Julie Crossley
As part of an ongoing pipeline technology program for BP Alaska, a 1 km, 48-inch
diameter, X100 demonstration pipeline was constructed and operated for a period of
two years.
Artificial defects were introduced into one of the two test sections. These defects were
intended to demonstrate that current assessment methods could be used to predict the
behaviour of pipeline defects in a very high strength steel under realistic conditions
including accelerated pressure cycling and a range of cathodic protection levels. The
defects included in the trial were volumetric corrosion, mechanical damage, arc strikes
and girth weld defects. The volumetric corrosion defects included both isolated defects
and pairs of interacting defects.
All the defects and details such as the girth welds were assessed for fatigue failure in
addition to failure at the Maximum Operating Pressure.
This paper describes the design of the defects for the trial. The defects were designed to
be close to failure, so as to provide a realistic test of the predictive methods. Current
methods were used including the Pipeline Defect Assessment Manual (PDAM) and
ongoing work sponsored by PRCI.
Pipeline; X100; Defects; PDAM; High Strength Linepipe; Corrosion; Mechanical
Damage; Weld Defects.

Harvey Haines                  Rick McNealy                  M.J. Rosenfeld, PE
Kiefner & Associates, Inc.     Applus-RTD                    Kiefner & Associates, Inc.
Vienna, VA                     Houston, TX                   Worthington, OH
When evaluating corrosion ASME B31G recommends an upper limit of 80 percent of
the wall thickness for evaluating metal loss depth. Although corrosion deeper than
this can still be acceptable for maintaining a safe pipeline, the primary concern was
for the effect of error in the corrosion depth measurement and the need to offer
conservative criteria. If the measurement error is understood and the treatment of
these errors can be handled in a routine and practical manner, then corrosion depths
greater than 80 percent could potentially be acceptable. Examples of well understood
measurement error are ILI tools where published values exist for commercial tools, in
addition the error can be reassessed using in-the-ditch measurements when
remediating occurs. The 80 percent maximum is
also limiting for low pressure applications such as barge and tank lines, or natural gas
distribution lines, where the pressure on a system is often only a fraction of the
pressure carrying capability of full wall thickness pipe. This paper will demonstrate a
method for assessing deep corrosion which is acceptable for low pressure lines and
accounts for measurement error using other known sources of measurement error.

                         Samuel T. Ariaratnam, Ph.D., P.E., P.Eng.
                                  Arizona State University
                                Tempe, Arizona USA
                           Muthu Chandrasekaran, P.Eng.
                              Pure Technologies Limited
                               Calgary, Alberta Canada
Significant financial and environmental consequences often result from line leakage
of oil product pipelines. Product can escape into the surrounding soil as even the
smallest leak can lead to rupture of the pipeline. From a health perspective, water
supplies may be tainted by oil migrating into aquifers. A joint academic-industry
research initiative funded by the U.S. Department of Transportation‟s Pipeline and
Hazardous Materials Safety Administration (PHMSA) has lead to the development
and refinement of a free-swimming tool called SmartBall®, which is capable of
detecting leaks as small as 0.03 gpm in oil product pipelines. The tool swims through
the pipeline being assessed and produces results at significantly reduced cost to the
end user compared to current leak detection methods. GPS synchronized GIS-based
above ground loggers capture low frequency acoustic signatures and digitally log the
passage of the tool through a pipeline. This paper presents the development,
laboratory and field validation testing of the SmartBall for oil pipeline integrity.

         Terry Boss – Interstate Natural Gas Association of America (INGAA)
  David Johnson – Panhandle Energy (Chair of INGAA Pipeline Safety Committee)
            Bernie Selig – Process Performance Improvement Consultants
            John Zurcher – Process Performance Improvement Consultants
The requirement to perform Integrity Management Programs (IMP) in the U.S.
was mandated by Congress at the end of 2002. Actual inspections began in
2004. The Interstate Natural Gas Association of America, (INGAA), began a
program to measure the effectiveness of the IMP (Integrity Management
Program) with some of its member companies, representing approximately
120,000 miles of transmission pipeline. The U.S. has 295,000miles of on shore
gas transmission piping. This paper provides 6 years of gathered data on IMP
activities and compares them to PHMSA data.
The INGAA participating companies have inspected more than 80% of their
High Consequence Areas (HCAs) while the total for all PHMSA miles is more
than 90% by the end of 2009. The number of PHMSA reported immediate and
scheduled repairs being made in HCAs is 0.17 repairs/mile of assessed HCA
averaged over the 6 year period. The total number of all repairs reported for
the INGAA companies is an average of 0.11 repairs per mile of HCA inspected.
There were 6 reportable incidents in HCAs in 2009 for all onshore gas
transmission piping, 5 of which were due to third party caused damage.
Reassessments, re‐inspection of pipe that already had a baseline inspection,
are reported for the INGAA program. For calendar years 2007 through 2009, a
total of 641 HCA miles of pipeline have been reassessed. There were 19
repairs made in the reassessed pipe, equating to 0.03 repairs/mile, a 73%
reduction in the number of repairs in reassessed pipeline.

Qishi Chen                                      Heng Aik Khoo
C-FER Technologies                              Carleton University
Edmonton, Alberta, Canada                       Ottawa, Ontario, Canada
                                      Roger Cheng
                                   University of Alberta
                               Edmonton, Alberta, Canada
                                        Joe Zhou
                              TransCanada Pipelines Limited
                                 Calgary, Alberta, Canada
This paper describes a multi-year PRCI research program that investigated the local
buckling (or wrinkling) of onshore pipelines with metal-loss corrosion. The
dependence of local buckling resistance on wall thickness suggests that metal-loss
defects will considerably reduce such resistance. Due to the lack of experimental data,
overly conservative assumptions such as a uniform wall thickness reduction over the
entire pipe circumference based on the defect depth have been used in practice.
The objective of this research work was to develop local buckling criteria for pipelines
with corrosion defects. The work related to local buckling was carried out in three
phases by C-FER and the University of Alberta. The first phase included a
comprehensive finite element analysis to evaluate the influence of various corrosion
defect features and to rank key parameters. Based on the outcome of Phase 1 work, a
test matrix was developed and ten full-scale tests were carried out in Phase 2 to collect
data for model verification. In Phase 3, over 150 parametric cases were analyzed using
finite element models to develop assessment criteria for maximum moment and
compressive strain limit. Each criterion includes a set of partial safety factors that were
calibrated to meet target reliabilities selected based on recent research related to
pipeline code development. The proposed criteria were applied to in-service pipeline
examples with general corrosion features to estimate the remaining load-carrying
capacity and to assess the conservatism of current practice.

         �� ��
IPC2010-�� �� ��
 Three-Dimensional Response of Buried Pipelines Subjected To Large
Soil Deformation Effects- Part I: 3D Continuum Modeling Using ALE and
                                   SPH Formulations
                                    Abdelfettah Fredj
                    BMT Fleet Technology Limited, 311 Legget Drive
                               Kanata, Ontario, K2K 1Z8
                                    Aaron Dinovitzer
                    BMT Fleet Technology Limited, 311 Legget Drive
                               Kanata, Ontario, K2K 1Z8
Understanding the effect of soil-pipeline interactions in the event of large ground
movement is an important consideration for the pipeline designer. Both experimental
investigation and computational analyses play significant roles in soil-pipeline
research. As part of this effort, a framework incorporating continuum soil mechanics
and advanced finite element approach (i.e., ALE and SPH method) for modeling soil
pipe interaction was constructed.
The overall objective of this work is to develop, validate and apply 3D continuum
modeling techniques to assess the performance of pipeline systems subjected to large
soil displacements. The numerical models produced may subsequently be used to
predict the wrinkle formation and post formation behavior of the pipeline considering
the effect of the soil confinement. The aim is to develop a comprehensive wrinkle
integrity assessment process.
This is the first paper (Part I) in a series of two papers. In this paper a
three-dimensional Continuum models using MMALE (Multi-material Arbitrary
Eulerian Lagrangian) and SPH (smooth particle hydrodynamics) approaches are
developed and employed using LS-DYNA. The results are compared with published
experimental data of large-scale tests to verify the numerical analysis methods.
In the second paper (Part II) the effects of soil restraint on the response of the
pipe/soil systems (e.g., pipeline wrinkle and buckle, strain demand) are discussed.

  Three-Dimensional Response of Buried Pipelines Subjected To Large
   Soil Deformation Effects- Part II: Effects of the Soil Restraint on the
                    Response of Pipe/Soil Systems
           Abdelfettah Fredj                               Aaron Dinovitzer
BMT Fleet Technology Limited, 311 Legget       BMT Fleet Technology Limited, 311 Legget
                 Drive                                           Drive
        Kanata, Ontario, K2K 1Z8                        Kanata, Ontario, K2K 1Z8
                Canada                                          Canada

Understanding the effect of soil-pipeline interactions in the event of large ground
movement is an important consideration for pipeline designer. Both experimental
investigation and computational analyses play significant roles in this research.
As part of this effort, a framework incorporating continuum soil mechanics and
advanced finite element approach (i.e., ALE and SPH method) for modeling soil pipe
interaction is developed.
The overall objective is to develop, validate and apply 3D continuum modeling
technique to assess the performance of pipeline system subjected to large soil
displacement. The numerical models than may be used to predict the wrinkle formation
and post formation behavior of the pipeline considering the effect of the soil
confinement, and develop a comprehensive wrinkle integrity assessment process.
This is the second paper (Part II) in a series of two papers. In the first paper a
three-dimensional Continuum models using MM-ALE (Multi-material Arbitrary
Eulerian Lagrangian) and SPH (smooth particle hydrodynamics) approaches are
developed and run using LS-DYNA. The results are compared with published
experimental data of large-scale test to verify the numerical analysis methods.
In this paper (Part II) the effects of soil restraint on the response of the pipe/soil systems
(e.g., pipeline Wrinkle and buckle, strain demand) are discussed.

                Brian Leis                                      Andrew Cosham*
         Battelle Memorial Institute                              Atkins Boreas
           Columbus, Ohio, USA                               Newcastle upon Tyne, UK
                                          Xian-Kui Zhu
                                  Battelle Memorial Institute
                                       Columbus, Ohio, USA
                                          Paul Roovers
                                        Brussels, Belgium
It has long been recognized that a defect in a pipeline, such as a crack, or a gouge, or a
dent and gouge, can fail at a constant pressure after some period of time has elapsed,
which is commonly referred to as a time-delayed failure. Modern line-pipe steels are
more defect tolerant than the earlier vintages, but can be more susceptible to
time-delayed failures by virtue of their higher toughness and tolerance for larger
Nowadays many pipelines are subjected to in-line inspection such that many more
defects that previously went undetected are now found. However, because metal-loss
due to external interference could be inferred as external corrosion, whereas a feature
associated with a dent could lead to more immediate response, it is not clear that ILI
will expose this threat. Thus, the defects prone to time-delayed failures could remain in
the pipeline even where ILI is used. To prevent timedelayed failures and minimize the
risk to first-responders, it is important that the operator quantify the potential response
defects relative to the line-pipe steel, the pressure history since detection or presumed
date of contact, and the damage size, while initially making the conservative
assumption that the metal-loss is a gouge.
This paper describes work undertaken to develop these guidelines to direct
first-responders, and highlights the remaining work to complete their validation.
KEY WORDS: defect, time-dependent growth, delayed failure, first-responder

                   COMPOSITE MATERIALS
                                         Chris Alexander
                         Stress Engineering Services, Inc.,Houston, Texas
                                          Julian Bedoya
                         Stress Engineering Services, Inc.,Houston, Texas
For the better part of the past 15 years composite materials have been used to repair
corrosion in high pressure gas and liquid transmission pipelines. This method of repair
is widely accepted throughout the pipeline industry because of the extensive evaluation
efforts performed by composite repair manufacturers, operators, and research
organizations. Pipeline damage comes in different forms, one of which involves dents
that include plain dents, dents in girth welds and dents in seam welds. An extensive
study has been performed over the past several years involving multiple composite
manufacturers who installed their repair systems on the above mentioned dent types.
The primary focus of the current study was to evaluate the level of reinforcement
provided by composite materials in repairing dented pipelines. The test samples were
pressure cycled to failure to determine the level of life extension provided by the
composite materials relative to a set of unrepaired test samples. Several of the repaired
dents in the study did not fail even after 250,000 pressure cycles were applied at a range
of 72% SMYS. The results of this study
clearly demonstrate the significant potential that composite repair systems have, when
properly designed and installed, to restore the integrity of damaged pipelines to ensure
long-term service.

       Ron Scrivner                       Butch Exley                       Chris Alexander
 Stress Engineering Services,         Williams Gas Pipeline          Stress Engineering Services,
             Inc.                        Houston, Texas                           Inc.
       Houston, Texas              butch.d.exley@williams.com                Houston, Texas
   ron.scrivner@stress.com                                 chris.alexander@stress.com
There have been several recent weld failures either during the initial post
construction hydrostatic tests, or immediately following construction. Girth
welds typically do not fail as a result of internal hoop loads without the
contribution of loads due to out side forces.
External loading should be considered during design, welding procedure
development, construction, and pipeline operations. This paper presents one
example where a girth weld failed as a result of preexisting 1940’s weld
imperfections and recent, 1980’s, external loading. This analysis of the girth
weld failure in the 30-inch pipeline included an initial failure analysis, a fracture
mechanics analysis, and a finite element analysis that integrated the pipe-soil
interaction, as well as localized stresses associated with weld imperfections. A
critical part of this study was to evaluate how changes in soil conditions
associated with a drought followed by soil saturation associated with rainfall,
contributed to lack of local support and increased overburden loads associated
with the saturated soil.
The failure analysis of the ruptured girth weld and surrounding pipe concluded
that the failure of the girth weld was caused by increased bending loads
imposed on the pipeline after recent construction activities, and that the
fracture initiated at a lack-of-penetration/fusion imperfection that was
20¼-inches long and 0.110 inches deep. A coupled investigation using finite
element and fracture mechanics analyses verified numerically that with
reduced-strength soil, stresses were generated in the girth weld of sufficient
magnitude to cause a fracture. Temperature, terrain, and fatigue were
considered, but were not deemed to significant enough to affect the stresses
or other conditions that resulted in the failure.
The overriding observation of this study is that no single factor contributed to
the failure that occurred. Rather, the girth weld failure was the result of weld
imperfections that generated elevated stresses due to excessive loads
imparted to the pipe due to settlement associated with non-compact backfill
associated with excavation work.
Had the pipe not displaced vertically due to localized soil conditions, it is
unlikely that the pipeline would have failed. The recent excavation activities
were adequate for normal soil conditions; however, dry soil at the time of
construction resulted in lack of compaction and excessive moisture just prior to
the failure that generated in differential settlement and heavy overburden,
combined with lack of penetration imperfection in the girth weld in question,
resulted in generating excessive bending stresses that contributed to the
eventual failure of the pipeline.

                                     Chris Alexander
                              Stress Engineering Services, Inc.
                                      Houston, Texas
                                      Eelco Jorritsma
                                  Shell Pipeline Company
                                      Houston, Texas
                                 eelco jorritsma @shell.com
An API 579 Level 3 assessment was performed to determine the stresses in a 2% dent
in a 20-inch x 0.406-inch pipeline. The intent was to determine the stress
concentration factor (SCF) in the dent with a finite element model using geometry
data provided from an in-line inspection caliper run. In addition to the
analytically-derived SCF, data were also evaluated from a recent experimental study
involving a plain dent subjected to cyclic pressure conditions with a profile
comparable to the dent in question. This sample was cycled at a stress range of 70%
SMYS and failed after 10,163 cycles had been applied. Using the DOE-B mean
fatigue curve, combined with the experimental fatigue life, the resulting SCF factor
was derived to be 4.20. This value is within 1% of the calculated FEA-based SCF and
served to confirm the technical validity of the SCF. The operator provided historical
pressure data covering a 12-month period and a rainflow count analysis was
performed on the data. Using this data, along with the API X‟ design fatigue curve,
the estimated remaining life was determined for the dent in question and
conservatively estimated to be 65 years. This paper provides details on the analysis
methodology and associated results, discussions on the empirically-derived SCF with
its use in validating the analytical SCF, and application of the results to estimate the
remaining life of the pipeline system. It is the intent of the authors to provide the
pipeline industry with a systemic approach for evaluating dent severity using caliper
and operating pressure history data.


                                       Carl E. Jaske
                                   DNV Columbus, Inc.
                                    Dublin, Ohio, USA
                                     Melissa J. Rubal
                                   DNV Columbus, Inc.
                                    Dublin, Ohio, USA
Assessing the Fitness for Service (FFS) of deficient pipeline segments or facilities is an
important step in managing the mechanical integrity and safety of pipeline systems.
However, FFS can be determined according to several documents, including API
579-1/ASME FFS-1 2007 Fitness-For-Service (API 579) and the Pipeline Defect
Assessment Manual (PDAM). The document contents and assessment methodologies
of API 579 and PDAM are reviewed and compared for several common damage
API 579 was originally developed for the refining and petrochemical industries but is
currently applied to a broad range of equipment and systems. In contrast, PDAM was
developed under a joint industry project to assess defects specifically in petrochemical
pipelines. While PDAM refers the reader to API 579 for the assessment of several
damage mechanisms, including gouges, manufacturing defects, weld defects, and
cracks, the authors of PDAM claim that API 579 is generic, biased towards pipes in
process plants, and can be overly conservative for the assessment of other pipeline
Understanding and comparing the current FFS documents can lead to an enhanced
allocation of available resources and can improve the level of FFS assessments in the
pipeline industry. The methods used to assess corrosion of components with static
internal pressures, dents, dent-gouge combinations, and cracks are compared.

                Steven J. Polasik                        Michelle LeMesurier
               DNV Columbus, Inc.                      DNV Energy Canada Ltd.
                Dublin, OH, USA                         Calgary, Alberta, Canada

           Tony Alfano                  Burke Delanty                 Tom Bubenik
       DNV Columbus, Inc.           DNV Energy Canada Ltd.          DNV Columbus, Inc.
         Dublin, OH, USA            Calgary, Alberta, Canada         Dublin, OH, USA

The processing and integration of data for direct assessment (DA) and in-line
inspection (ILI) comparisons is critical to making sound integrity-based decisions.
While geographic information systems (GIS) are now commonly used to model
pipeline systems, most day-to-day data processing and integration occurs outside of
the GIS, for example in Microsoft Excel™.
As such, Det Norske Veritas (DNV) developed a data integration tool within Excel™
as part of a large scale stress corrosion cracking direct assessment (SCCDA) program
for a major pipeline operator. Linear based data provided by the client (e.g., in-line
inspections, girth welds, previous excavations, close interval survey, coating, grade
and wall thickness, pressure history, road and water crossings, risk assessments,
landowner information, etc.) is processed, analyzed and incorporated into the overlay.
This tool provides the ability to integrate any linear based data in a graphical
representation of the pipeline along continuous and parallel chainage. The overlay
allows for identifying similar locations using criteria that are difficult to program into
an algorithm and helps engineers to relate complex factors during the decision making
process. The overlay also provides the ability to easily extract data relevant to sites
selected for assessment along the pipeline.
The data integration tool has already found many applications beyond SCCDA since it
provides a robust process to integrate and analyze data in parallel with GIS systems.
The overlay provides engineers with a method to make decisions without learning
complex GIS programs and has the added ability to feed the results back into GIS
systems. Such decision making processes and applications include direct assessment
programs, cathodic protection enhancements, risk reduction programs, in-line
inspection comparisons, and maintenance activities.


                          NATURAL GAS PIPELINE
Byron G. Souza Filho        Gabriel Petry              TBG
Petrobras                   UFRGS/LAMEF                Rio de
Rio de                      Porto Alegre-RS-Brasil     Janeiro-RJ-Brasil
Janeiro-RJ-Brasil           Cristiane S. Frota
                             Walter Schultz Neto
                               Fabio M. Matsuo
The Code ASME B31.8 [1] is well established as a safe Code for all life phases
of Natural Gas Transmission and distribution pipelines, like: design,
construction, operation and maintenance. In the case of mechanical damage,
such as dents, the Code contains maintenance provisions for field acceptance
or repair of dent and dents combined with other defects consisting of stresses
raisers such as gouges, arc burns and welds.
Dents, sometimes, are found in sensitive areas due to urban sprawl upon
pipeline right-of-way or environmental concerns. In addition dents shapes,
sometimes, are not smooth or plain like the code defines as criteria of
This paper presents and describes some full scale pipeline test’s results in
samples containing kinked dents, reproduced in laboratory, in recent vintage
pipelines. This type of defect is usually caused by rock puncturing,
unauthorized excavation or soil-pipeline interaction in an inservice pipeline.
The damaged pipeline samples were repaired by composite reinforcing
sleeves before being submitted to the tests. The dimensions of the defects
were detected and sized by Geometric and MFL PIG, and compared with field
measurements. The studies were conducted concerning internal pressure
fluctuations, which can be covered by fluctuations in the principal stresses in
the pipe wall. The analyses also considered the plastic strain around the
damaged area and effects of rerounding or spring back in case of the defects
were generated in conditions of normal operation or in condition of out of
service pipeline.
Keywords: composite sleeves, kinked dents, buckles, pipeline repair.


                               REGION OF CHILE
E Salinas                    Empresa Nacional del         A. Wilde
Empresa Nacional del         Petróleo (ENAP)              MACAW Engineering
Petróleo (ENAP)              Punta Arenas, Chile          Ltd.
Punta Arenas, Chile                                       Newcastle Upon Tyne,
A. Muñoz                                                  UK
J. Healy                                    M. Bakayeva
MACAW Engineering Ltd.                      ROSEN Europe
Newcastle Upon Tyne,                        Oldenzaal, The Netherlands
Empresa Nacional del Petróleo (ENAP) is an energy company, wholly owned
by the Chilean Government. With regards to overall management, the
company comprises of two Business Divisions: Exploration and Production
(Up-stream) and Refining and Logistic (Down-stream), complemented by
corporate managerial structures.
The objective of ENAP’s Exploration and Production (Up- Stream) business
line is the exploration and exploitation of hydrocarbons (oil and natural gas) in
the South of Chile (Magallanes) and abroad, as well as geo-thermal energy, in
this case, associated with private entities in areas of Northern Chile.
Within the Magallanes region ENAP operates approximately 2,200 km of
natural gas, crude oil and refined product pipelines. These pipelines range in
diameter from 4 to 20 inch and the majority of pipelines are over 30 years old.
Due to operational reliability reasons, since 1998 ENAP has been regularly
inspecting its pipelines using intelligent in-line inspection tools. Furthermore,
since 2006, as part of an overall pipeline integrity management plan ENAP has
been conducting Fitness for Service assessments on selected pipelines
including a risk-based assessment considering pipeline condition and the
impact on the continuity of operation.
The Integrity Management Plan implemented by ENAP in the Magallanes
region has been applied to all pipelines transporting gas, crude oil and refined
products, including those built after 1990. This plan comprises the construction
phase, from which invaluable information is gathered for later use. The primary
aims of ENAP’s integrity management plan are:
- To protect the public
- To protect the surrounding environment by preventing pipeline failures
- To ensure efficient usage of the budget available to conduct maintenance
- To prevent damage to the pipelines, e.g. due to corrosion activity
- To provide clarity of activities being performed by ENAP in order to ensure an
efficient, safe and reliable pipeline system
This paper provides a description of the integrity management strategy
adopted by ENAP and includes a review of a number of the challenges
encountered during its implementation.
Pipeline Integrity Management, Risk Assessment, Corrosion Growth
Assessment, Integrity Assessment, ENAP


                                    Érika S. M. Nicoletti
                                  Petrobras Transporte S.A
                                  Rio de Janeiro, RJ, Brazil
                                   Ricardo D. de Souza
                                  Petrobras Transporte S.A
                                  Rio de Janeiro, RJ, Brazil
Pipeline operators used to map and quantify corrosion damage along their aging
pipeline systems by carrying out periodical in-line metal-loss inspections.
Comparison with the data sets from subsequent runs of such inspections is one of the
most reliable techniques to infer representative corrosion growth rates throughout the
pipeline length, within the period between two inspections. Presently there are two
distinct approaches to infer corrosion rates based on multiple in-line inspections:
individual comparison of the detected defective areas (quantified by more than one
inspection), and comparison between populations. The former usually requires a
laborious matching process between the run-data sets, while the drawback of the latter
is that it often fails to notice hot-spot areas. The object of this work is to present a new
methodology which allows quick data comparison of two runs, while still maintaining
local distinct characteristics of the corrosion process severity. There are three
procedures that must be performed. Firstly, ILI metal-loss data set should be
submitted to a filtering/adjustment process, taking into consideration the reporting
threshold consistency; the possible existence of systematic bias and corrosion
mechanisms similarity. Secondly, the average metal-loss growth rate between
inspections should be determined based on the filtered populations. Thirdly, the
defects reported by the latest inspection should have their corrosion growth rates
individually determined as a function of the mean depth values of the whole
population and in the defect neighborhood. The methodology allows quick and
realistic damage-progression estimates, endeavoring to achieve more cost-effective
and reliable strategies for the integrity management of aged corroded systems. Model
robustness and general feasibility is demonstrated in a real case study.

Brock Bolton1, Vlado Semiga1, Sanjay Tiku1, Aaron Dinovitzer1, Joe Zhou2
[1] BMT Fleet Technology Limited, 311 Legget Drive, Kanata, ON, Canada, K2K 1Z8
Tel.: 613-592-2830; Fax: 613-592-4950; email: adinovit@fleetech.com
[2] TransCanada Pipelines Ltd., 450 - 1 Street SW, Calgary, Alberta, Canada, T2P 5H1
Tel.: 403-920-2000; Fax: 403-920-2200; email: joe_zhou@transcanada.com
Dents in buried pipelines can occur due to a number of potential causes; the pipe resting
on rock, third party machinery strike, rock strikes during backfilling, amongst others.
The long-term integrity of a dented pipeline segment is a complex function of a variety
of parameters, including pipe geometry, indenter shape, dent depth, indenter support,
pressure history at and following indentation. In order to estimate the safe remaining
operational life of a dented pipeline, all of these factors must be accounted for in the
The goal of the full scale experimental program described in this paper is to compile a
database of full scale dent test results that encompasses many of the dent types seen in
the field, including plain dents, dents interacting with girth and long seam welds, and
dents interacting with metal loss features, in both the unrestrained and restrained
condition. The dents are pressure cycled until a fatigue failure occurs in the dent.
Typical data recorded includes indentation load/displacement curves, applied pressures,
pipe wall OD strains along the axial and circumferential centerlines, and axial and
circumferential dent profiles. The full scale tests are being performed on behalf of
PRCI and US DoT.
This paper is intended to show the matrix of dents considered to date and present a
representative summary of the data recorded.
In addition to presenting the full scale test program and resulting data, this paper
summarizes ongoing efforts to develop a validated pipeline dent integrity assessment
model. The model under development makes use of the aforementioned full scale
experimental data, to validate a finite element model of the denting and re-rounding
process for a variety of dent scenarios (i.e. depths, restraints, indenter sizes).
The paper discusses the efforts under way to develop and validate the finite element
model with the goal being to estimate the fatigue life. The paper is an extension of work
discussed in a previously presented IPC paper [1].


                              Xian-Kui Zhu and Brain N. Leis
                                 Battelle Memorial Institute
                                     505 King Avenue
                                  Columbus, Ohio 43201

  ABSTRACT: Accurate prediction of burst pressure in line pipes is critical for their
safety design and operation. Different equations for predicting burst pressure of line
pipes have been proposed over the years, but broad agreements between the
prediction equations did not exist. To this end, the present authors recently developed
a new multi-axial plastic yield theory that is referred to as Average Shear Stress Yield
(ASSY) theory [6]. Based on this theory, a theoretical closed-form solution for
predicting burst pressure was proposed as a function of the pipe diameter, thickness,
ultimate tensile stress and strain hardening exponent. The results showed that the
ASSY-based burst pressure solution predicts generally the average of experimental
data, and gives the best prediction among different models in a comparison of over
100 full-size burst tests for different line pipe geometries and grades. This conclusion
is consistent with the observation by Zimmerman et al. [7]. On the other hand, Law at
al. [1-3] recently proposed a so-called CIS (cylindrical instability stress) model that
can implicitly predict the burst pressure of line pipes, and claimed that the CIS model
is the best one for predicting burst pressure. To clarify the argument and to determine
a truly accurate prediction equation, this paper will reevaluate the available models of
burst pressure using various experimental data used by Law et al. and others. Detailed
comparisons and discussions on the predictions of burst pressure with the
experimental results are performed.
KEYWORDS: pipeline, burst pressure, Y/T ratio, Tresca criterion, von Mises
criterion, ASSY criterion

                      MITERED PIPE JOINTS
 Ioan I. Feier                Brian N. Leis                    Xian-Kui Zhu
Battelle Memorial Institute   Battelle Memorial Institute      Battelle Memorial Institute
Columbus, OH, USA             Columbus, OH, USA                Columbus, OH, USA

 Randall B. Stonesifer        John S. Stavrakas                Daniel D‟Eletto
Computational Mechanics       National Grid                  National Grid
Inc.                          Waltham, MA, USA               Hicksville, NY, USA
Julian, PA, USA

Historic pipeline construction utilized miter joints to enable small directional changes
in pipeline routing, and this legacy construction remains in today‟s pipelines. Current
codes and regulations impose a limit on the maximum miter angle to less than three
degrees of the total pipeline direction change, for pipeline operating with pressure
over 30-percent SMYS (Specified Minimum Yield Stress). In anticipation of an
operational pressure increase, an experimental and simulation effort was undertaken
recently to determine the stress amplification due to miters in 30-inch diameter,
0.5-inch thick gas transmission pipelines. Experiments were conducted on six miter
joints ranging in miter angle from 0° to 8° degrees of total pipeline direction change.
Three of the miter joints were removed from the field (1950‟s original installation),
while the remaining three were specifically fabricated for the testing. All the miters
considered were X42 pipeline steel. The miter pipe joint specimens were tested with
pure pressurization, pure bending, and combined pressure and bending using a custom
designed loading apparatus. Hoop and axial strains were measured using internally
and externally mounted strain gauges. Pressure, as well as four point bending loads
and deflections were recorded. One 3.8º field miter specimen was tested to burst.
Experimental data, analytical solutions, and finite element results are compared at the
miter joint section for the three loading cases. The study is limited to pipe radius to
thickness ratio values of 30, and hence the results presented in this study are useful
near this value. Results showed that miter joints increase stresses in the vicinity of the
miter joint for pressure and/or bending loads. The peak stresses are on the exterior at
the intrados. The pressure induced peak stress values increase proportional to the
miter angle, and bending further increases the miter stress magnitudes. The
ovalization effects significantly compromise the use of linear superposition of
pressure and bending stresses even though material behavior remains elastic.
Findings from this study demonstrate that in-situ miters on the pipeline in question do
not compromise the integrity of the line, and stress additions for small angles over
three degrees are comparable to stress risers occurring from normal pipeline features.
The results of this work are important for performing structural integrity assessments
and for making informed regulatory decisions for mitered pipeline operation.


       Composite Repairs of High Pressure Steel Pipelines
               Shawn Laughlin, ClockSpring, & Keith Leewis, L&A Ltd,
ABSTRACT: This paper provides a review of the performance considerations for
effective mitigation of metal loss defects on high pressure steel pipelines. Special
emphasis is placed on the non-trivial issues which are often not considered by
practitioners of pipeline integrity efforts.


Chad Bunch, E.I.T.                     Glenn Cameron, M. Sc., P.
Calgary, Alberta, Canada               Eng                                     Rafael G. Mora, P. Eng
                                       Calgary, Alberta, Canada                Calgary, Alberta, Canada
The views, judgments, opinions and recommendations expressed in this paper do not necessarily reflect those of
the National Energy Board, its Chairman or members, nor is the Board obligated to adopt any of them
This paper provides guidelines to identify all threats and assess a pipeline’s
susceptibility to those threats in order to select appropriate and effective
mitigation, monitoring, and prevention measures prior to reactivating pipelines.
The intent of this paper is to provide pipeline operators, consultants and
regulatory agencies with a generic threat assessment approach that has to be
customized to the pipeline-specific characteristics and conditions, and the
regulatory requirements of its own jurisdiction.
A literature review and authors’ experiences across the pipeline industry have
identified the need for a generic, yet complete approach that guides pipeline
integrity engineers in the methodologies that adequately and effectively assess
threats prior to reactivation and that can be validated in a timely manner during
the operations.
Pipeline operators may be called on to reactivate pipelines that are facing
challenges such as aging, changes in operational conditions, lack of
maintenance and inconsistent integrity practices while facing constraints from
increasing population density, higher pressure and flow throughput
requirements of a competitive marketplace, and regulatory requirements
insisting on higher levels of safety and protection of the environment.
This paper was structured with the following components to assist the reader
in conducting threat assessments:
• Current regulations and recognized industry standards with respect to
reactivating pipelines;
• Definition of and differentiation between hazard and threat;
• Hazard identification analysis for the known and potential situations, events
and conditions; and
• Threat susceptibility and identification analysis process for the known
categories derived from the hazard identification process
A case study is described as an example of applying the guidelines to conduct
threat susceptibility and identification assessments of a pipeline prior to its
reactivation The results from the threat susceptibility and identification
assessment process can help operators, consultants and regulators in
determining effective inspection, mitigation, prevention and monitoring


   Understanding Strain Performance Considerations in the Composite
                             Repair of Dents and SCC.
                            Keith Leewis & Shawn Laughlin
                      L&A Ltd Chicago IL ClockSpring Houston
Abstract: This paper reviews the keystrain principles behind the technical design
regarding the effect of a repair and reinforcement of steel pipelines with composite
sleeves and composite wraps.
Data is presented for the repair of large strains - dents, and the repair of small localized
strains – SCC cracks.


     Julia M Race                              Jane V Haswell
   School of Marine Science and                Pipeline Integrity Engineers,
   Technology, Newcastle University,           262 Chillingham Road,
   Newcastle-upon-Tyne, UK                     Newcastle-upon-Tyne, UK

        Robert Owen                            Barry Dalus
      National Grid plc,                       Northern Gas Networks Limited
      National Grid House                      7 Camberwell Way
      Warwick Technology Park,                 Moorside Park
      Gallows Hill, Warwick, UK                Sunderland, UK

As in-line inspection tools improve, dents that would have been below the detection
and reporting levels of previous inspections are now being detected and reported to
pipeline operators. Consequently, operators are being faced with large numbers of
dents in ILI reports that require further consideration and are left with the problem of
how to prioritize these dents for further investigation and repair.
Although code guidance is clear on the relative severity of dents associated with other
features or those based on a depth or strain criteria, this may still leave a significant
number of dents in the pipeline which fall within codified static dent assessment
criteria, but which may still pose a threat, particularly from fatigue. Many
transmission pipelines in the UK are now 30-40 years old and fatigue failures at dent
locations are starting to be reported. Such occurrences have raised technical concerns
with regulators regarding the perceived conservatism of current dent assessment
methods as the dents in question were within the code limits and were reported
through standard ILI technologies, however, they were not identified as significant.
There is therefore a requirement to develop best practice guidance for the safe and
economic operation of dented pipelines.
The UK Onshore Pipeline Association (UKOPA) recognized that further guidance
was needed in order that operators could identify dents which can be safely left in the
pipeline and those for which further excavation is required. They have consequently
developed a series of algorithms to allow pipeline operators to prioritize the dents for
repair based on ILI results. This paper describes the background research to these
algorithms as well the algorithms themselves, demonstrating their use with ILI dent
data from operators of onshore oil and gas pipelines. The paper concludes with
comments on the current conservatisms in the analysis of dent fatigue and proposes a
way forward to allow pipeline operators to manage large numbers of dents for which
the dent fatigue life is critical.


                                Vic Keasler, Brian Bennett
                                 Nalco Energy Services
                                   Heather McGinley
                                  Dow Microbial Control
Bacterial proliferation is a severe problem in many oilfield systems, especially
in aging systems with high water cuts. Depending on the types of
microorganisms present, they can cause microbiologically influenced corrosion
(MIC) or biofouling of filters, membranes, and metal surfaces. Common oilfield
bacteria include sulfate-reducing bacteria (SRB) that can generate hydrogen
sulfide (H2S) and iron sulfide (FeS) as a byproduct (iron sulfide can occur in
different structural forms), acid producing bacteria that can secrete organic
acids that lower the pH within the microenvironment of a biofilm, as well as
general heterotrophic bacteria that are often important in biofilm formation and
maintenance, amongst others. To prevent corrosion or biofouling caused by
these organisms, biocides are commonly added to the production fluids.
Some concern has arisen that common oilfield biocides may be inherently
corrosive at high end use concentrations and could cause general corrosion in
the assets they are protecting from MIC. Accordingly, it is important to
understand the risk of MIC, souring, and biofouling versus general corrosion
from the biocides themselves. To examine the killing efficiency of oilfield
biocides versus their corrosive potential, laboratory work was undertaken with
five biocide products including:
Tetrakis (hydroxymethyl) phosphonium sulfate (THPS), glutaraldehyde,
glutaraldehyde / alkyldimethylbenzyl ammonium chloride (ADBAC) mixture,
5-chloro-2-             methyl-4-isothiazolin-3-one/2-methyl-4-isothiazolin-3-one
(CMIT/MIT), and a cocodiamine (quaternary amine).
Each biocide was evaluated at four different concentrations ranging from
10-100,000 ppm of product. Killing efficiency was determined via bacterial kill
studies, while wheelbox and bubble cell testing examined corrosion rates.
Corrosion rates varied quite substantially from one biocide to the next,
especially at high concentrations. Some biocides were found to be only mildly
corrosive even at high dosages, while other biocides were much more
corrosive at high concentrations. In general, it was observed that biocide
corrosivity is directly related to the dosage of the biocide, with higher dosages
correlating with higher corrosion rates. On the other hand, biocides were
shown to be effective at killing common oilfield bacteria at relatively low
dosages. This data suggests that biocides can be effective at killing bacteria at
concentrations that do not cause significant amounts of general corrosion.
Additionally, the common practice of batch treating biocides minimizes contact
time between the biocide and the metal surface, which is in turn expected to
minimize any corrosion that would otherwise be attributed to the biocides
themselves. Taken together, this data would suggest that the benefit of biocide
treatment to prevent MIC and biofouling substantially outweighs any potentially
negative impact on corrosion.

Satish Kulkarni                             Chris Alexander
El Paso Pipeline Group                      Stress Engineering Services, Inc.
Houston, Texas                              Houston, Texas
satish.kulkarni@elpaso.com                  chris.alexander@stress.com
For more than a decade composite materials have been used by pipeline operators to
repair damaged pipelines. To validate the performance of composite repair materials,
numerous research programs have been conducted. The recent introduction of
standards such as ASME PCC-2 and ISO 24817 have provided industry with guidance
in using composite materials concerning factors such as the minimum required repair
thickness, recommended performance tests, and qualification guidance. Up until now,
operators have developed individual requirements for how composite materials can be
used and under what circumstances their use is deemed acceptable. To compliment
these internal guidance standards, several operators have elected to conduct
independent investigations to evaluate the benefits derived in using composite
materials for reinforcing specific anomalies such as gouges, dents, girth welds, and
wrinkle bends. This paper provides insights that can be used by operators in
evaluating the use of composite materials in repairing damaged pipelines with an
emphasis on incorporating the current industry standards.


                               Pussegoda and V Semiga
                               BMT Fleet Technology Ltd
                                Kanata, Ontario, Canada

An in-service failure was associated with an NPS 12, 6.35 nominal wall API 5L X42
grade pipe. This segment of the pipeline had been in service since 1957 and had a tar
coating. The pipe was manufactured by piercing followed by rolling/extrusion to
produce a seamless pipe. The pipeline has always carried refined petroleum products.
The rupture event was captured by pressure history records that recorded an
overpressure experienced during a sudden valve closure event. The section of pipe
removed included portions of the upstream and downstream pipe sections to carryout
a failure investigation. The paper presents the findings from the investigation.
The paper presents the observations from inspection and experimental testing carried
out on the removed pipe section. These included NDE, fracture surface examinations
and destructive examination such as metallography that helped in obtaining
information on the reduction in the resistance of the material to withstand the
in-service pressure conditions. The above observations together with results from
mechanical testing was used to estimate failure pressures based on a “deterministic”
primary flaw size, using assessment methods (ECA) applicable to the failure case
under consideration.
The investigation of the failure indicated that the major contributing factors were: (a)
the corrosion feature at the failure site that reduced the remaining wall thickness
below 2mm, and the overpressure caused by the valve closure down stream in the
vicinity of the failure site. Pipe specification checks from material removed from the
section of the failed pipe, indicate that the pipe meets the API 5L X42 specification

Edgar I. Cote, M.Sc., P. Eng. James Ferguson, P. Eng.       Nauman Tehsin, M. Eng.
Senior Integrity Engineer,    Senior Integrity Engineer,    Intermediate            Integrity
CIMARRON Engineering CIMARRON Engineering Ltd.              Technologist,
Ltd.                          300, 6025 - 11th Street S.E.  CIMARRON Engineering Ltd.
300, 6025 - 11th Street S.E.  Calgary, Alberta, Canada T2H 300, 6025 - 11th Street S.E.
Calgary, Alberta, Canada 2Z2                                Calgary, Alberta, Canada T2H
T2H 2Z2                       James_Ferguson@cimarron.ab.ca 2Z2
Edgar_Cote@cimarron.ab.ca                                   Nauman_Tehsin@cimarron.ab.ca

Pipelines are subjected to both residual and applied tensile stresses, and can form
near-neutral pH SCC (transgranular stress corrosion cracking) if the pipeline is
exposed to a conducive environment and is made from a material that is susceptible to
SCC. This transgranular SCC is an ongoing integrity concern for pipeline operators.
As part of an SCC Integrity Management Program (IMP), it is necessary to perform
integrity assessments and prioritize segments of the pipelines to manage the SCC
Ultrasonic crack detection in-line inspection tools have proven capable of locating
SCC, but reliability of these tools is not absolute and the reduced probability of
detection of subcritical flaws limits options for proactive management.
Hydrostatic retesting is a very effective program for removing near-critical axial
defects, such as SCC, but does not provide useful information as to the location of
SCC along the pipeline.
NACE Standard RP0204-2004 (SCC Direct Assessment Methodology or SCCDA)
outlines factors to consider and methodologies to employ to predict where the SCC is
likely to occur, but the standard acknowledges that there are no well-established
methods for predicting the presence of SCC with a high degree of certainty. The trend
in probabilistic modelling has been to focus on establishing deterministic relationships
between environmental factors, tensile stress and SCC formation, and growth; these
have achieved varying degrees of success.
The Statistical Predictive Model (SPM) was previously developed to predict the
likelihood of occurrence of near-neutral pH Stress Corrosion Cracking (SCC) for the
NPS 10 Alberta Products Pipeline (APPL). SPM Phase 5 uses selected predictor
variables representing tensile stress, environmental, pipe-related, corrosion control
and operational relevant factors to determine the Probability of Occurrence of SCC.
Regression techniques were used to create multivariable logistic regression models.
The results for each model are checked at locations where SCC is known to be present
or absent to assess predictive accuracy, then used to prioritize susceptible segments
for field excavation. The relative strength of individual predictor variables provides
insight into the mechanism of near-neutral pH SCC crack initiation.
A. Q. Fu                                       Y. F. Cheng
Dept. of Mechanical & Manufacturing            Dept. of Mechanical & Manufacturing
Engineering University of Calgary              Engineering University of Calgary
Calgary, Alberta, T2N 1N4, Canada              Calgary, Alberta, T2N 1N4, Canada

The alternating current (AC)–induced corrosion of a cathodically protected X65
pipeline steel was studied in a high pH, concentrated carbonate/bicarbonate solution.
Results demonstrated that the corrosion rate of the steel increases with the AC current
density, and AC interference could increase the pitting corrosion of the steel. In the
absence of AC interference or at a low AC current density, i.e., 20 A/m2, a cathodic
protection (CP) potential of –950 mV(Cu/CuSO4 electrode, CSE), which is 100 mV
more cathodic than –850 mV(CSE) recommended by National Association of
Corrosion Engineers (NACE), provides a full protection over the steel. When the AC
current density is higher than 20 A/m2, the NACE-recommended CP is incapable of
protecting the pipeline from corrosion. A new CP standard is thus developed for
recommendation to industry to avoid AC corrosion of pipelines.

                      PROBE TECHNIQUE
 A. Q. Fu                                      Y. F. Cheng
Dept. of Mechanical & Manufacturing            Dept. of Mechanical & Manufacturing
Engineering University of Calgary              Engineering University of Calgary
Calgary, Alberta, T2N 1N4, Canada              Calgary, Alberta, T2N 1N4, Canada

The coating disbondment and corrosion of a X65 pipeline steel under coating were
studied by scanning Kelvin probe (SKP) measurements. The effects of immersion
time and wet-dry cycle on the Kelvin potential profile and the corrosion behavior of
the steel were investigated. Kelvin potential measured on “intact” area is shifted
negatively with time, indicating an increasing water uptake under the “intact” coating.
There is a more negative Kelvin potential on disbonded area than that on “intact” area,
which is attributed to corrosion reaction of steel occurring under the disbonded
coating. During wet-dry cycle, the thickness of solution layer trapped under
disbonded coating decreases due to evaporation of water, causing a negative shift of
Kelvin potential. It is associated with the reduction of oxygen solubility in the
concentrated solution during drying of electrolyte.
         Understanding Magnetic Flux Leakage Signals from Gouges
      Lynann Clapham , Vijay Babbar*, Jian Dien Chen*, and Chris Alexander**
               *Applied Magnetics Group, Department of Physics, Queen's University,
               Kingston, Ontario, Canada
               Ph. (613) 533-6444, fax (613) 533-6463, email: lynann@physics.queensu.ca
               **Stress Engineering Services Inc., Houston, Texas, U.S.A.

The Magnetic Flux Leakage (MFL) technique is sensitive both to pipe wall geometry
and pipe wall strain, therefore MFL inspection tools have the potential to locate and
characterize mechanical damage in pipelines. The present work is the first stage of a
study focused on developing an understanding of how MFL signals arise from
pipeline gouges. A defect set of 10 gouges were introduced into sections of
12”diameter, 5m long, end capped and pressurized X60 grade pipe sections. The
gouging tool displacement ranged (before tool removal) between 2.5 to 12.5mm.
Gouges were approximately 50mm in length. The shallowest indentation created only
a very slight scratch on the pipe surface, the deepest created a very significant gouge.
All gouges were axially oriented.
Experimental MFL measurements were made on the external pipe wall surface
(pressurized) as well as the internal surface (unpressurized). The early results of the
experimental MFL studies, and a hypothesis for the origin of the MFLaxial signal

“dipole” are discussed in this paper.

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