1. business and industrial
2. energy
3. natural gas

December, 2013
Vol.12, No.4
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incorporating
The Journal of Pipeline Integrity
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Journal of
Pipeline Engineering
Great Southern Press
Clarion Technical Publishers
Journal of Pipeline Engineering
Editorial Board - 2013
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Dr Husain Al-Muslim, Pipeline Engineer, Consulting Services Department, Saudi Aramco,
Dhahran, Saudi Arabia
Mohd Nazmi Ali Napiah, Pipeline Engineer, Petronas Gas, Segamat, Malaysia
Dr-Ing Michael Beller, Rosen Engineering, Karlsruhe, Germany
Jorge Bonnetto, Operations Director TGS (retired), TGS, Buenos Aires, Argentina
Dr Andrew Cosham, Atkins, Newcastle upon Tyne, UK
Dr Sreekanta Das, Associate Professor, Department of Civil and Environmental Engineering,
University of Windsor, ON, Canada
Leigh Fletcher, Welding and Pipeline Integrity, Bright, Australia
Daniel Hamburger, Pipeline Maintenance Manager, Kinder Morgan, Birmingham, AL, USA
Dr Stijn Hertele, Universiteit Gent – Laboratory Soete, Gent, Belgium
Prof. Phil Hopkins, Executive Director, Penspen Ltd, Newcastle upon Tyne, UK
Michael Istre, Chief Engineer, Project Consulting Services,
Houston, TX, USA
Dr Shawn Kenny, Department of Civil and Environmental Engineering, Faculty of Engineering
and Design, Carleton University, Ottawa, ON, Canada
Dr Gerhard Knauf, Salzgitter Mannesmann Forschung GmbH, Duisburg, Germany
Prof. Andrew Palmer, Dept of Civil Engineering – National University of Singapore, Singapore
Prof. Dimitri Pavlou, Professor of Mechanical Engineering,
Technological Institute of Halkida, Halkida, Greece
Dr Julia Race, School of Marine Sciences – University of Newcastle,
Newcastle upon Tyne, UK
Dr John Smart, John Smart & Associates, Houston, TX, USA
Jan Spiekhout, DNV Kema, Groningen, Netherlands
Prof. Sviatoslav Timashev, Russian Academy of Sciences – Science
& Engineering Centre, Ekaterinburg, Russia
Patrick Vieth, President, Dynamic Risk, The Woodlands, TX, USA
Dr Joe Zhou, Technology Leader, TransCanada PipeLines Ltd, Calgary, Canada
Dr Xian-Kui Zhu, Principal Engineer, Edison Welding Institute, Columbus, OH, USA
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4th Quarter, 2013
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Volume 12, No 4 • Fourth Quarter, 2013
Contents
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Dr Robert M Andrews, Harry Kamping, Henk de Haan, Otto Jan Huising, and Neil A Millwood.......................277
Guidance for mechanized GMAW of onshore pipelines
Dr Adilson C Benjamin......................................................................................................................................301
Prediction of the failure pressure of corroded pipelines subjected to a longitudinal compressive force superimposed
on the pressure loading
Peter Tuft and Sergio Cunha..............................................................................................................................313
Comparing international pipeline failure rates
Daniel Sandana, Mike Dale, Dr E A Charles, and Dr Julia Race..........................................................................321
Internal stress-corrosion cracking in anthropogenic CO2 pipelines: is it possible?
Indranil Guha, Beau Whitney, Raúl Flores-Berrones, Aditya Barsainya, and Gaurav Arya.................................. 335
Earthquakes and the Indian pipeline industry
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❖❖❖
OUR COVER PHOTO shows pipeline welding in the field: photo
provided, with thanks, by Lincoln Electric, Cleveland, OH, USA.
The Journal of Pipeline Engineering
has been accepted by the Scopus
Content Selection & Advisory
Board (CSAB) to be part of the
SciVerse Scopus database and
index.
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The Journal of Pipeline Engineering
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HE Journal of Pipeline Engineering (incorporating the Journal of Pipeline Integrity) is an independent, international,
quarterly journal, devoted to the subject of promoting the science of pipeline engineering – and maintaining
and improving pipeline integrity – for oil, gas, and products pipelines. The editorial content is original papers
on all aspects of the subject. Papers sent to the Journal should not be submitted elsewhere while under
editorial consideration.
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Authors wishing to submit papers should do so online at www.j-pipeng.com. The Journal of Pipeline Engineering
now uses the Aires Editorial Manager manuscript management system for accepting and processing manuscripts,
peer-reviewing, and informing authors of comments and manuscript acceptance. Please follow the link shown
on the Journal’s site to submit your paper into this system: the necessary instructions can be found on the
User Tutorials page where there is an Author's Quick Start Guide. Manuscript files can be uploaded in text
or PDF format, with graphics either embedded or separate.
Please contact the editor (see below) if you require any assistance.
The Journal of Pipeline Engineering aims to publish papers of quality within six months of manuscript acceptance.
4. Back issues: Single issues from current and past
volumes are available for US$87.50 per copy.
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1. Disclaimer: While every effort is made to check
the accuracy of the contributions published in The
Journal of Pipeline Engineering, Great Southern Press
Ltd and Clarion Technical Publishers do not accept
responsibility for the views expressed which, although
made in good faith, are those of the authors alone.
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Notes
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5. Publisher: The Journal of Pipeline Engineering
is published by Great Southern Press Ltd (UK and
Australia) and Clarion Technical Publishers (USA):
Great Southern Press, PO Box 21, Beaconsfield
HP9 1NS, UK
• tel: +44 (0)1494 675139
• fax: +44 (0)1494 670155
• email:jtiratsoo@gs-press.com
• web:www.j-pipe-eng.com
• www.pipelinesinternational.com
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2. Copyright and photocopying: © 2013 Great
Southern Press Ltd and Clarion Technical Publishers.
All rights reserved. No part of this publication may
be reproduced, stored or transmitted in any form or
by any means without the prior permission in writing
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as copying for general distribution, for advertising and
promotional purposes, for creating new collective works,
or for resale. Special requests should be addressed to
Great Southern Press Ltd, PO Box 21, Beaconsfield
HP9 1NS, UK, or to the editor.
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Editor: John Tiratsoo
• email: jtiratsoo@gs-press.com
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Clarion Technical Publishers, 3401 Louisiana,
Suite 110, Houston TX 77002, USA
• tel:
+1 713 521 5929
• fax: +1 713 521 9255
• web: www.clarion.org
Associate publisher: BJ Lowe
• email:bjlowe@clarion.org
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3. Information for subscribers: The Journal of Pipeline
Engineering (incorporating the Journal of Pipeline
Integrity) is published four times each year. The
subscription price for 2013 is US$350 per year (inc.
airmail postage). Members of the Professional Institute
of Pipeline Engineers can subscribe for the special
rate of US$175/year (inc. airmail postage). Subscribers
receive free on-line access to all issues of the Journal
during the period of their subscription.
v
6. ISSN 1753 2116
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www.j-pipe-eng.com
is available for subscribers
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Editorial
Why is Australia different from the rest?
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At the recent Joint Technical Meeting held in Sydney
between the Australian Pipeline Industry Association
(APIA), the European Pipeline Research Group (EPRG),
and Pipeline Research Council International (PRCI),
this issue was examined in depth in a paper from
Peter Tuft and Sergio Cunha which is published in
this issue of the Journal (on pages 313-320). The
authors looked at the validity of the Australian data
and then explored reasons for the difference. Some
reasons are obvious, such as the relative youth of
Australian pipelines which results in a negligible rate
of corrosion failure. However, there is no obvious
explanation for the markedly lower rate of failure
due to third-party damage. It is hypothesized that
Australian practices for managing third-party damage
may differ in some way and the authors suggest
that, given the high social and economic cost of
pipeline failures, there should be a comparative study
to identify any beneficial differences between the
third-party damage protection practices in Australia
and those elsewhere.
In their paper, the authors point out that the mostly
likely explanation for the low rate of third-party damage
failures in Australia is a potentially different approach
to managing such interference. Exactly what that
difference might be is not clear and there has been
no study that casts light on this area. They go on
to speculate on the Australian practices which might
contribute to low third-party failure rates, although
they are only very tentative in their explanations for
the different failure rates pending a time when there
is better information on whether practices elsewhere do
in fact differ significantly. Despite these reservations,
the authors suggest several factors that may be
of relevance:
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But in terms of their failure rates, pipelines in Australia
are happily different from other pipelines around the
world, and the reasons for this are by no means
clear. The rates of pipeline failure in Australia are
substantially lower than in the Americas and Europe,
at only 10-20% of the international mean for failures
in onshore transmission pipelines.
Cunha point out that POG members represent 94%
of the total transmission pipeline length in Australia;
each year POG member companies submit a signed
declaration that they have either reported all incidents
or have had none.
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O START with, let us make clear that the above
headline refers to the rate of pipeline failure in
Australia vs that in the rest of the world. The Journal
certainly would not dream of making comparisons
with any other aspect of life or engineering between
that stimulating country (where it is headquartered)
and any other community anywhere else!
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The background to this paper is the significant fact
that that the Australian pipeline industry has been
collecting incident data since about 1965. The lines
for which data are collected are gas and liquid
transmission pipelines that comply with the over-arching
Australian pipeline industry standard AS 2885, and
with a maximum allowable operating pressure above
1050 kPa. The resulting database contains about 100
fields to record data about the pipe itself, the events
causing the incident, details of any damage and repairs,
and operating practices (particularly relating to external
interference protection). Reporting is voluntary, and
data are collected by the APIA from members of its
Pipeline Operators Group (POG). Messrs Tuft and
• Australian pipelines in populated areas tend to
be patrolled frequently, usually on the ground
but sometimes by air. In and around at least
two major cities the transmission pipelines are
patrolled every day – or every weekday – and
in other cities they are patrolled weekly. The
incident database contains about 20 near-miss
events where patrollers have caught third parties
in the act of digging or preparing to dig on the
right-of-way (RoW), and there are many more
instances where work near the pipeline was
forestalled by patrollers before encroaching on the
RoW (such off-RoW activity is not reportable,
but there is ample anecdotal evidence).
• The ‘One-Call’ or ‘Dial-Before-You-Dig’ system
is well used in Australia by third parties with
only rare lapses.
• Pipeline marker signs tends to be frequent,
conspicuous, and explicit in their warning
message.
• Since 1997, AS 2885 has required a safetymanagement study to be undertaken during
design and then reviewed every five years or
whenever the environment around the pipeline
changes (such as for new urban development).
This study is a fine-grained analysis, often
on a metre-by-metre basis, of all possible
causes of pipeline failure. Threats to pipeline
integrity are explicitly identified and mitigated,
with great emphasis on protection against
third-party damage.
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The Journal of Pipeline Engineering
How do earthquakes affect
pipelines?
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Seismic design and engineering of pipelines has advanced
significantly in recent decades, although little has been
accomplished to address the vulnerability of buried
pipelines to seismic hazards. In their paper on pages
335-344, Indranil Guha and his co-authors examine
this proposition from the viewpoint of the Indian
sub-continent which has a record of earthquakes of
varying magnitude and devastation. Since 2003, for
example, there have been 18 major earthquakes in
the country, averaging around 5 on the Richter Scale,
but peaking at over 9. As this paper explains, with
new and proposed cross-country pipelines in India,
it is becoming more important to understand the
effects on buried pipelines of seismic hazards (such
as shaking, liquefaction, and fault surface rupture).
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India, of course, is not alone in suffering from such
tectonic issues. In 1974 the first seismic design code
Technical standard for oil pipelines was developed by
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In summary, the paper by Guha et al. provides an
overview of past performance of buried pipelines during
earthquake events, including fault rupture, liquefaction,
and seismic shaking, and goes on to illustrate the
nascent understanding of earthquake hazards both
around the world and in India. Identification of
seismic sources and geohazard-prone areas during
the early phases of a project allows these data to be
incorporated during the design phase. Appropriate
site-specific seismic design during the engineering
stage can then reduce the risks posed by earthquake
hazards on buried pipeline structures.
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Messrs Tuft and Cunha reiterate that all or none of
these factors may be responsible for the low rates of
Australian failures due to third-party damage, although they
at least suggest possible initial directions for investigation.
As they go on to conclude, the absence of a simple
explanation for the low Australian failure rate is not a
clear-cut and satisfying conclusion. However the objective
of their paper is to initiate discussion of whether others
might benefit from research into the differences between
Australian and international failure rates. The authors
believe it provides a convincing case that Australian
pipeline failure rates are indeed substantially lower than
elsewhere, and hence that investigation of that difference
has potential to provide benefits in reducing failure rates
in other parts of the world.
the Japan Roads Association, and in 1984 the American
Society of Civil Engineers (ASCE) first published
formal guidelines for seismic design of pipeline systems;
however, until 2007, there was no specific standard
for seismic design of pipeline systems. In that year
the Gujarat State Disaster Management Authority
(GSDMA) published a standard for Indian application,
as the State was the worst one affected during the
2001 Bhuj Earthquake, in which over 20,000 people
died; numerous public- and privately-owned oil and gas
companies have pipeline networks within the State. The
first draft of the standard resulted from a project at the
Indian Institute of Technology in Kanpur, sponsored
by GSDMA. An analysis of the effect of earthquakes
on a continuous pipeline in the state of Gujarat in
India was subsequently presented based on the GSDMA
report, in which the authors also discuss the design
and construction methodology to minimize the effect
of loading on the pipeline during ground movement.
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• While the safety-management study is an
engineering process, it may have a cultural side
effect: because it is integral to Australian pipeline
design and operation it may help keep safety
matters – and particularly the consequences of
pipeline failure – in the forefront of pipeline
engineers’ thinking at all times.
The September, 2014, issue of the Journal will
explore these issues at greater depth: under the guest
editorship of Prof. Shawn Kenny – the Wood Group
Chair in Arctic and Harsh Environments Engineering
in the Faculty of Engineering and Applied Science
at the Memorial University of Newfoundland, and a
member of the Journal’s Editorial Board – a special
issue is being planned around the topic of engineering
analysis and design for seismic ground movement. Prof.
Kenny is soliciting contributions for this issue, and
further details can be obtained from him
Shawn.Kenny@carleton.ca or the Journal’s editor
(see page 274).
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Guidance for mechanized
GMAW of onshore pipelines
by Dr Robert M Andrews*1, Harry Kamping2, Henk de Haan2, Otto Jan
Huising2, and Neil A Millwood3
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1 MACAW Engineering, Newcastle upon Tyne, UK
2 Gasunie, Groningen, Netherlands
3 5G Orbital, Loughborough, UK
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NDUSTRY STANDARDS FOR pipeline welding generally had their origins in cellulosic welding of onshore
pipelines, and this is still the dominant process in some regions. Over the years standards have been adapted
to include new material grades, new processes, and more-demanding applications. Even though mechanized
gas-metal-arc welding (GMAW) is now the dominant process for offshore pipelines, and is widely used in
some areas of the world for large-diameter long-distance cross-country pipelines, the industry standards
still do not fully reflect the subtleties of this process. This results in owners and operators having to issue
amending company specifications. Moreover, there have been continual technical developments in equipment
and control technology which makes mechanized GMAW ever more sophisticated.
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The European Pipeline Research Group identified a need to develop guidelines focused on mechanized
GMAW. This paper summarizes a review document produced to form the basis of such guidelines. The
document has reviewed the main industry standards and also had input from company specifications. It
covers typical equipment and consumables, procedure and welder qualification, typical equipment including
ancillaries, production welding, inspection and testing, acceptance criteria, and repair options.
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It is hoped that this work will identify best practice across the industry. Based on the initial work it is
intended to develop a guidance document and input into national and international standards and others
working on pipeline welding requirements.
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HE RATE AT WHICH a pipeline can be
constructed is largely dictated by the time
taken to produce the first pass (i.e. the root pass).
Traditionally, ‘5G’ positional welding of pipeline girth
welds has been accomplished using shielded-metal-arc
welding (SMAW) with cellulosic electrodes, operated
vertically down. This ‘stovepiping’ technique is well
suited to pipeline welding, mostly due to its versatility.
However, with increasing usage of large-diameter
pipelines and higher grades, the effectiveness of the
cellulosic stovepiping method is diminished. For L555
grades, most specifications only permit cellulosic
consumables to be used for the root and hot pass,
with low-hydrogen consumables required for the fill
This paper was presented at the Joint Technical Meeting held between the
APIA, EPRG, and PRCI in Australia in April, 2013, and is reproduced by
kind permission of the meeting’s organizers.
* Corresponding author’s contact details:
tel: +44 191 215 4010
email: bob.andrews@macawengineering.com
and cap passes. For grade L690, cellulosic consumables
are not permitted, since the risk of hydrogen-assisted
cold cracking is too high, and achieving the required
overall strength overmatching becomes even more
problematic. The most widely used process for girth
welding of large-diameter, high-strength steel pipelines
is mechanized gas-metal-arc welding (GMAW). This
process offers high productivity combined with
good mechanical properties at the required design
temperatures. Several systems are available in
the market, but in essence they all rely on the
following features
• precision bevel (narrow gap)
• internal clamping
• one or more welding heads, or ‘bugs’, mounted
on a band
• gas-shielded solid wire
The basic systems use a short-circuit ‘dip’ transfer
mode, with either 100% CO2 shielding gas or an
argon-CO2 mixture. The process is continually being
The Journal of Pipeline Engineering
(b.) PWT Mk-I
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(a.) CRC
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(d.) FCAW
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(c.) Vermaat
(e.) Saturnax dual torch
(f.) Saturne 8 (Photo from Serimax.)
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Fig.1. Some examples of external welding heads for mechanized GMAW/FCAW.
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developed to increase welding speeds and reliability
without sacrificing weld-metal properties. In recent
years, some of the developments have included:
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• dual torch configurations: two torches each
with a single wire mounted on one bug
• pulsed GMAW: globular or spray transfer
• controlled short-circuit transfer, or ‘surface
tension’ transfer (STT): particularly suited to
open-gap root-pass welding
• FCAW (flux-cored arc welding) with a narrow
cap bevel (7°)
• seam tracking: electrical or vision based
• inverter power sources and control systems:
precise control of power waveforms and welding
parameters around the pipe circumference
• (single) tandem wire configurations: two
electrically insulated contact tips in one
torch with both wires feeding into the same
weld pool
• dual tandem torch/wire configurations: two
single-tandem torches mounted on one bug
producing two weld pools.
A mechanized welding system is defined as one which
moves the welding torch along the joint and controls
the welding parameters, but allows the welder to have
some (a few %) control over speed, position of the
torch, and the welding parameters. As systems become
more sophisticated, it is possible to control more of the
parameters and adapt to variations in joint geometry,
and this has resulted in welders having less freedom
to override the set parameters. Some would argue that
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Quality and personnel requirements
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Most welding standards might say something about
the type of bevelling machines and line-up clamps to
be used, but they say very little about the equipment
other than that it ‘shall be of a size and type suitable
for the work and shall be maintained in a condition
that ensures acceptable welds, continuity of operation
and safety of personnel’.
By and large, the onus is placed on the contractor to
supply equipment which is suitable for the intended
task. It is appropriate that the contractor should be
responsible for using the right equipment and ensuring
that it is maintained in good working order. However,
the client should retain the right of inspection and
verification of calibration of the welding equipment
prior to start of production.
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Although the obvious aspects of pipeline girth welding
are the equipment, consumables, and procedures, the
successful application of mechanized GMAW is also
dependent on the implementation of an adequate
quality management system and employing competent
personnel to cover all aspects of the welding process.
In addition to compliance with any general projectwide QA system, it is recommended that the quality
requirements of ISO 3834-2 [6] should be implemented
and the key welding personnel should be competent.
Pipeline construction by conventional welding (manual
welding) is in essence no different from pipeline
construction using mechanized welding equipment,
with regard to personnel, except for two key ‘players:
Equipment
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The EPRG project compared and contrasted the main
standards (API 1104 [1], BS 4515 [2], DNV OS-F101
[3], CSA Z662 [4], and AS 2885.2 [5]). Member
companies provided copies of their amending company
specifications and valuable input was provided by several
welding contractors:
Fig.2. Example of pipe facing machine.
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mechanized GMAW/FCAW is becoming more like
an automatic or robotic process, with less need for
skilled welders to operate the welding heads. There is
a trend in some quarters to employ welding-machine
operators rather than skilled pipeline welders: whilst
this may reduce costs, it is not clear if this is a
welcome development. Mechanized GMAW/FCAW is
best suited to ‘mainline’ pipe-to-pipe welding where the
joint geometry is uniform and an internal clamp can
be used. A selection of photographs of mechanized
welding heads is shown in Fig.1. Mechanized GMAW/
FCAW can be used on pipe-to-flange welds if it is
possible to machine the appropriate bevel onto the
flange weld-neck.
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• Welding technician – responsible for settingup and maintaining welding and ancillary
equipment. The equipment manufacturer’s
training requirements should be followed.
• Welder – qualification of welders will be
discussed later in more detail.
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Professional welding contractors invest a lot of time
and money training welders and technicians in their
workshops prior to construction. The time spent
perfecting a weld procedure beforehand can save a lot
of difficulties later in the field. It is also essential that
the ultimate owner or operator of the pipeline has
an effective quality management system and personnel
in place. Due to the high productivity of these
systems it is important that the quality management
system responds rapidly to any developing problems
to minimize the number of defective welds and the
consequent re-work.
With mechanized welding there is less opportunity
for the welder to overcome any shortcomings of the
equipment, so that the whole system is important –
including technician support. Only items of equipment
which are different from conventional pipeline
construction are discussed in the following sections:
Pipe-facing machines
It is normal practice for steel pipes to be supplied from
the mill with a standard 30° bevel. However, for narrowgap mechanized GMAW welding it is necessary to apply
a bespoke precision bevel designed to suit the particular
welding system. This should be machined immediately
prior to field welding to avoid mechanical damage in
transit or corrosion during long storage periods.
There are many different types of machine for bevelling
pipe ends; however, the type which has been found to
be most suited to pipeline construction (both on- and
offshore) is a hydraulically operated machine which uses
floating-head cutters mounted on a rotating end plate
(Fig.2). The non-rotating body locates firmly in the pipe
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Fig.4. Copper backing shoes in use on a DN1200 internal
line-up clamp.
end ensuring good end squareness. Carbide cutting
tips are set into the floating heads which track the
internal surface of the pipe as the end plate is rotated
(Fig.3). Most contractors fit a cup wire brush onto
the floating head in order clean any loose dirt or
millscale from the internal surface of the pipe prior
to welding.
Some systems combine pipe alignment with internal
root pass welding capability, which obviates the need
for copper backing shoes (Fig.5). The internal welding
machine is fitted with either four, six, or eight
welding heads, each welding a portion of the root in
the vertical-down direction. Clamping and welding is
controlled by an operator at the free end of the pipe.
The power, shielding gas, and control information are
passed along a reach-rod or umbilical to the clamp.
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Internal line-up clamps
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An internal line-up clamp is an essential item of
equipment for mechanized pipeline welding. Generally,
they are used for joining components of equal
thickness, i.e. pipe-to-pipe welds, and are not suitable
for pipe-to-fitting welds which involve a change in
internal diameter across the joint. Internal line-up
clamps are usually capable of passing through a cold
field bend, but not a pulled bend or induction
bend. Internal line-up clamps tend to be
pneumatically operated instead of using hydraulics,
thereby avoiding the risk of oil contamination in the
pipe near the joint preparation. The larger clamps
have a reasonable capability to re-round the pipe
ends (albeit elastically) thus aiding joint fit-up. Most
clamps have motorized wheels to propel themselves
inside the pipe.
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Fig.3. Pipe-facing machine showing rotating plate, floatinghead cutters, cutting tips, and cup wire brush.
Most mechanized GMAW/FCAW welds where
all the passes are deposited from the outside of
the joint rely on internal line-up clamps having
retractable copper backing shoes to provide adequate
support for the molten weld pool of the root pass.
Some recently developed systems are able to weld
a closed root without backing shoes. The radius of
curvature of the shoes is chosen to match that of
the internal surface of the pipe (Fig.4). The merits
and potential issues of copper shoes are discussed
later in this paper.
Welding bands
The welding band is simply a means of transporting
the welding head around the girth weld. One band
per weld is set on one pipe end, usually prior to
‘stabbing-on’ the new pipe. Once the band is set in
place it is usually left there until completion of that
weld joint. The band is placed at a set distance from
bevelled pipe end; it needs to be rigid when fixed
to the pipe and robust enough to cope with being
‘knocked about’, while needing to be lightweight for
routine manual handling. Feet, or pads, provide a
‘stand-off’ from the external pipe surface. The geared
edge which engages with the drive of the welding head
is usually placed on the opposite side away from the
weld to minimize damage from spatter.
In principle the welding bands should be suitable for
the automatic ultrasonic testing (AUT) scanner head
as well, but in practice each system tends to have its
own design and there is limited compatibility.
Welding head or ‘bug’
The main function of the welding head, or bug, is to
carry the welding torch(es) along (or around) the weld
joint. The head incorporates motors for providing travel,
lateral movement, oscillation, and contact-tip-to-work
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281
distance adjustment. Power, shielding gas, filler wire,
and control information are carried via umbilical cables
to the welding head. Most modern mechanized GMAW
systems have a pendant console which allows the welder
to control the run sequence, start/stop commands, lateral
position, and travel speed. There are many variants of
welding head, which can be broadly classified as:
single torch
dual torch
tandem wire
hybrid laser GMAW
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Power source
Early mechanized GMAW systems used constant-voltage
power supplies with dip-transfer mode. Nowadays, most
systems use inverter power supplies which provide a
more stable power characteristic and are more suited
to pulsed GMAW.
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Most modern systems use wall-mounted wire-feed units
which means the wire has to be fed through an umbilical
cable. The advantages of this arrangement are that it
reduces the weight of the welding head and allows
larger, standard, off-the-shelf spools of wire to be used.
For onshore pipeline construction it is normal to use
15-kg spools, whereas on some laybarges much larger
packs of wire are convenient. The larger spools mean
less downtime due to changing of spools.
Fig.5. CRC internal-welding machine (DN1000).
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The wire feed can be either on the welding bug, or
a separate unit mounted on the inside wall of the
welding shack. The main advantage of having the wire
feed motor on the bug is to minimize the distance
between wire feeder and arc, resulting in better wire
speed control and hence arc stability. However, this
does limit the user to small spools or ‘bobbins’ of
wire, which tend to be more expensive and have to
be used with a wire straightener due to the tighter
radius of curvature or ‘cast’.
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Wire-feed unit
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Welding machines need to be properly grounded to
avoid the occurrence of stray arcs. Traditionally, the
earth return for onshore SMAW pipeline construction
was a saddle with spike which was prodded into the
girth weld bevel. This method has been somewhat
refined for mechanized GMAW, but the quality of
the earth return path is often poor. This can be
problematic for high-performance pulsed-GMAW systems
which use measurements of arc voltage to maintain
contact-tip-to-work distance and seam tracking. Some
contractors use bespoke earth-return clamps which
provide a better contact path.
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The smaller ‘bobbins’ tend to make use of 0.9-mm
or 1.0-mm diameter wire, whereas for remote wire
feed units, which rely on having to ‘push’ the wire
for a longer distance, it has been found that 1.2-mm
diameter wires are more successful.
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Modern microprocessor systems enable rapid
communication between power source, wire-feed unit,
and welding head. They can be programmable in the
field, but access needs to be limited to the welding
engineer and/or nominated technicians. Due to the
increasingly large amount of information contained in
each procedure programme, it is normal practice for the
signed, approved, weld procedure to include the name
and unique version number of the control software.
Measurement of welding parameters can be inbuilt or
independent. Generally, for third-party verification, it
is preferred to have independent measurement and
monitoring of parameters.
The welding return cables need to have sufficient crosssectional area to cope with the maximum current and
anticipated duty cycle. It is also important to ensure
the length of cable is minimized and kept constant
so that the voltage drop is a fixed variable. Weldprocedure qualification testing should simulate the cable
lengths that are to be used in the production system.
Consumables
Filler wires
Welding consumables need to be selected to provide
the specified mechanical properties and adequate
resistance to degradation from pipeline contents and
intended operating conditions. This requirement applies
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Handling and storage
It is important to observe the manufacturer’s
recommendations for handling and storage of consumables.
For filler wires this principally involves keeping them
in a humidity-controlled room or container to prevent
moisture pick-up and rusting. Packing and re-packing
boxes of consumables should be avoided to reduce the
risk of mechanical damage. For systems which make use
of small reels (or bobbins) it is important to ensure
reeling is done by the consumable manufacturer. Transfer
in the field from large reels to small reels should be
prohibited due to concerns over process control.
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Surface quality, coating thickness, cast (the diameter of
a loose turn), and helix of the filler wire are important
factors which can affect the ‘feedability’ and contact
resistance. Surface quality can be degraded if the storage
and handling procedures are not adhered to. Most filler
wires are coated with a very thin layer of copper. The
coating thickness is difficult to measure and if it is not
thick enough it will affect the electrical contact between
the wire and the contact tip. The spool size will affect
the amount of straightening required and hence the
amount of physical resistance to the wire-feed motor.
One of the companies surveyed as part of this project
commented on the batch-to-batch variations observed with
flux-cored wires. Its policy is to perform the equivalent
of a weld-procedure qualification test for each batch of
flux-cored wire.
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The standard consumable classification groups tend to be
quite broad allowing considerable variation in chemistry.
For demanding mechanized GMAW applications it is
accepted that small changes in the concentration of
alloying elements and/or residual elements can have a
significant effect on technological properties, hot cracking
susceptibility, bead profile, and arc stability. Some
contractors apply their own additional requirements –
defining steel de-oxidation practice, placing limits on
alloy additions, and ‘tramp element’ concentrations and
setting guaranteed mechanical properties.
having BS EN 10204:2004 type 3.1 certification where
each batch is tested by the manufacturer. For demanding
applications it is also common practice to insist that
production welding is performed using the same batch(es)
that were used for welding-procedure qualification testing
(WPQT): whilst this may be a laudable requirement, in
practice it is not always easy to achieve.
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for any welding process, manual or mechanized, but
there are additional issues for automated GMAW
pipeline welding.
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It is widely agreed that strength overmatching is beneficial
and, in fact, it is a premise for adoption of the EPRG
and most other alternative weld-defect-acceptance criteria, as
discussed below. It is important to base the overmatching
requirement on the narrow gap weld and not the
consumable batch test; this is because the measured
narrow gap all-weld yield strength is usually much higher
(up to 150 N/mm2). The level of overmatching varies
from standard to standard, but most require 5% to 10%
above the SMYS of the parent material. One company
standard requires overmatching of the actual strength
(of all the pipes), which essentially means SMYS plus
150 N/mm2. Overmatching is not really an issue for
low grades, but for high-strength steels (≥ L555) this
can pose significant challenges.
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Batch testing
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Batch testing is usually the responsibility of the consumable
manufacturer. The testing is performed according to a
procedure which minimizes the effects of parent metal
dilution, i.e. in a very wide groove or a built-up ‘pad’ of
weld metal. Whilst these tests are simple and repeatable,
they bear little relation to the properties achievable in a
narrow-gap weld. Guidance on the number and type of
verification tests is given in AWS A5.01 and EN 14532-1.
There are different levels of batch testing and certification
depending on the demands of the application. Most
projects involving mechanized GMAW use consumables
Shielding gas
100% carbon dioxide, or a mixture of argon and carbon
dioxide, are usually used for mechanized GMAW welding
of C-Mn steels. Carbon dioxide is an active gas and
tends to produce a hotter arc: this is good for ensuring
root penetration and sidewall fusion, but more spatter
is formed and weld pool control is not so good for
the cap pass. Pulsed GMAW normally uses an 80%-Ar
20%-CO2 mixture. In addition to effects on weld-pool
fluidity and amount of spatter, several studies have shown
that the mechanical properties are affected by changes
in shielding-gas composition.
Principally for safety reasons, gases must be stored in
the containers in which they were supplied, and no
inter-mixing is permitted in the containers. Pre-mixed
gases are more commonly used for onshore pipeline
construction, and although more expensive, they provide
good reliability with minimal effort. Offshore pipeline
construction barges or vessels tend to mix the gas on
demand, probably because it is easier to permanently
install the pipework and mixer units.
During the WPQT and pre-production phase it is
important to ascertain what operational procedures are
in place to control the storage, handling, and usage
of shielding gases. Similarly, it is important to assess
the competency of the welding technicians with regard
to the shielding-gas systems. Regular checks should be
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283
• arc characteristics – spray arc, globular arc,
pulsating arc, or short-circuit arc;
• contact-tip-to-work distance;
• contact tip – type, and size/dimensions;
• torch angle(s);
• separation distance between wires (for dual-torch
and tandem systems).
performed during production to confirm the actual flow
rate of shielding gas exiting the torch(es). A portable
measuring device, plugged onto the end of the torch-gas
shroud, can be used. It is also important to clean the
torch-gas shroud regularly as the build-up of spatter can
have an adverse effect on the shielding-gas flow pattern.
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A list of the welding parameters seen as essential by the
authors of this paper for mechanized GMAW/FCAW
welding, is given in the Appendix. Also included
in the Appendix are the parameter requirements as
addressed in the codes BS 4515-1:2009, API 1104 20th
edition, and ISO 15614-1/ISO 15609-1. In addition
to the usual variables for a girth-welding procedure
such as preheating, interpass temperatures, thickness,
and chemical composition, the list includes others
specific to the mechanized process. These additional
variables include the information listed in the preceding
paragraph. For multiple-wire (dual-torch and/or tandemwire) systems, the number of wires and their spacing
should also be treated as essential variables.
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Most modern mechanized-welding systems now have
segment control which means parameters can be
changed depending on the angular position around
the joint. Systems like this require a large set of preprogrammed parameters which are not easy to present
on a printed WPD.
Essential variables
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The weld procedure defines the parameters that control
the production of the weld. The question of how much
information to state on the weld procedure document
(WPD) is one which causes discussion amongst welding
engineers from time to time. The simple answer is that
it should contain all the information necessary for the
welder to be able to make welds which are demonstrably
the same as those which were subject to non-destructive
and destructive testing.
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Procedures for mechanized GMAW
This could mean that, for current systems, the WPD
would consist of a program identification, a sketch
of the layer build-up, and the related pre-choices the
welder has to make on his remote. That would be
sufficient for the welder in the field. But all standards
require a minimum set of parameters to be addressed
in the WPD. Some of these are relevant, some less
interesting, but some important values are not required,
as is discussed in the following section.
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Procedures and procedure
qualification
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Another complication is the increased use of pulsed
GMAW, which requires several parameters to define the
waveform, but in most cases the average (mean) parameters
are only reported on the WPD. This information is
almost meaningless. So, without making the WPD overcomplicated, the most sensible approach is to state the
name and version number of the control software.
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The following information specific to mechanized GMAW
welding should be stated:
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• control software – programme and/or software
version;
• list of pre-set welding parameters that cannot
be adjusted by the welder;
• list of pre-set welding parameters that can be
adjusted by the welder (i.e. ‘hot key’ limits);
• wire-feed speed for each pass;
• oscillation width, frequency, and dwell time for
each pass;
• calculated arc energy for each pass using the
recorded values of current, voltage, and travel
speed without the addition of a percentage. For
multiple, electrically isolated, tandem-electrode
welding processes the effective arc energy per run
must be calculated as the sum of the individual
energies for each electrode. For pulsed welding,
the effective arc energy shall be calculated on
the basis of RMS (root mean square) values;
Heat input is controlled, since it influences the
weld profile and incidence of defects such as lack
of fusion. The welding technician is more interested
in arc energy since that is something that can be
controlled. Arc energy is given by voltage multiplied
by current divided by travel speed. The amount of arc
energy ‘absorbed’ by the metal will depend on various
factors, but generally for GMAW it is assumed that
80% of the arc energy is available as heat input; the
rest is dissipated by radiation or convection. Although
other factors also influence the effective heat input,
wire-feed rate also has a large influence on the heataffected zone profile and on the risk of burn-through
or lack-of-fusion defects.
Heat input is a derived parameter, so whilst it is
interesting to limit its fluctuation, it is more important
to control the primary parameters which contribute to
arc energy. The correct way to calculate arc energy is
to use the instantaneous values of arc voltage, current,
and travel speed. The minimum, maximum, and average
values of arc energy can then be reported for each
pass. Minimum heat input has in some cases been
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The Journal of Pipeline Engineering
Procedure qualification
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There is often a question whether inspection methods
and techniques during qualification should be same as
in production or whether they should be more onerous.
For example, during WPQT one usually has access to
the internal surface (root) which would enable magneticparticle inspection (MPI) to be carried out. Similarly
there is more freedom to be able to grind off the root
bead to aid MPI, or to grind off the cap bead to aid
ultrasonic testing (UT).
If automated ultrasonic testing (AUT) is being performed
during WPQT it may be appropriate also to carry out
radiographic testing (RT) in order to provide comparison
inspection data. Test-ring sizes are more manageable,
which means radiography can be performed in a purposemade bunker, or the welds could even be subjected to
immersion UT.
Welder qualification
The purpose of the welder-qualification test is to
demonstrate that the welder is able to make sound
welds using the particular procedure and equipment that
is to be used in production. Although manual control
of the weld pool is not performed by the welder, it is
important to remember the welder will need to have an
insight into weld pool behaviour and the influence of
the movement of the torch on the weld pool. So either
a trained manual welder will be able to be qualified
within a limited period of time, or a considerable time
will be needed to train the operator to get to know the
weld-pool behaviour. The welder-qualification test should
be performed in the required principal position (5G, etc.)
on full pipe joints or pup pieces. API 1104 [1] 20th
edition allows segments or coupons of pipe to be used.
However, this should not be permitted for qualification
of welders on mechanized GMAW/FCAW systems, as
it is not representative of production conditions. For
positional welding, each welder must complete at least
50% of the pipe circumference. The ends must be sealed
until at least the root bead and hot pass have been
completed around the full circumference in order to
prevent draughts interfering with gas shield and possibly
also affecting the weld-cooling rate.
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The purpose of qualifying a weld procedure is to
demonstrate that production welds made in accordance
with that procedure will have the required mechanical
properties and be of sound quality. There are
various approaches which can be taken with regard
to qualification of weld procedures depending on
the specific project application. Australian Standard
AS 2885.2 describes four methods, namely:
(i) qualification by testing, (ii) qualification
by documentation of previous testing and approval,
(iii) qualification by pre-qualification without testing,
and (iv) qualification by the use of supervision.
This is also a possibility with the various
BS EN ISO standards (i.e. BS EN ISO 15607, 15609,
51613, and 15614).
Inspection and testing
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In addition to the essential variables, it is important
to consider whether to impose a time limit on the
validity of a WPD to account for technological advances
in equipment, pipe materials, and consumables which
might render the WPD invalid. Specifically such a
time limit is recommended when welding materials
with a yield strength of 450 N/mm2 and above, where
any changes in the welding consumables might have
a negative influence on the as-welded properties of
the weld metal.
This should also apply to any welds which are made
at a later date for additional testing, for example for
corrosion or full-scale tests.
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erroneously calculated by taking minimum voltage for
the whole pass, multiplying it by minimum current for
the whole pass, and dividing it by maximum travel
speed for the whole pass. Similarly, maximum heat
input has been calculated by taking the maximum
voltage and current and dividing by minimum travel
speed. Clearly, this is physically incorrect and can
give rise to unqualified and impractical extremes of
heat input, and should be avoided.
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For new pipeline projects, the default requirement is
option (i), qualification by testing. Option (ii) may
also be adopted for short pipeline projects, such as
diversions, subject to consideration of essential variable
restrictions. It may also be possible on occasion to
consider the other alternatives.
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Most standards stipulate that a qualified WPD of
a particular contractor is valid for welding only in
workshops or sites under the operational technical
and quality control of that contractor. In other words,
a transfer from one contractor or sub-contractor to
another is not permitted without re-qualification. This
is a good requirement which ensures the in-house
knowledge and expertise which is implicit in a WPD is
maintained. In reality, for mechanized welding systems,
it is not realistic for third parties to use someone
else’s pre-qualified procedure as it is unlikely they
would have all the correct equipment and know-how.
The welder-qualification test should be performed using
the same, or equivalent, equipment as will be used for
production welding. The welder should also be able
to demonstrate competency in the correct use of the
equipment, for example how to set the band on the
pipe, change wire spools, change contact tips, clean the
gas shroud, check wire-feed speed, and use of grinder
4th Quarter, 2013
285
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Mechanized GMAW systems rely on very specific,
precise, narrow-gap bevels which need to be applied
just prior to welding in the field. It is not a good idea
to bevel the pipe ends too far in advance especially if
there is a possibility of the machined surfaces rusting.
Carbide cutting tips can produce very reliable radii in
the preparation, but it is important to check for wear,
especially in higher-grade steels which are harder. If
it is not possible to machine the bevel, for example
at a tie-in, it may not be possible to use mechanized
GMAW welding, and other processes such as FCAW
are often used. Mechanized FCAW processes can be
used either in the ‘traditional’ V-bevel configuration
or in an narrow gap bevel as a fill and cap. In these
cases, a mechanized or manual solid-wire process or
SMAW is utilized to weld the root pass.
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There is a trend in some quarters to employ weldingmachine operators rather than skilled pipeline welders.
However, it can be argued that this downskilling is
not appropriate. All ‘mechanized’ welders should also
be capable of producing good manual welds. Manual
welders control the melting pool by adjusting welding
parameters and have the ability to look into the pool
and see if something wrong. Operators don’t have
these abilities. So, prior to qualification welding, the
welders search for the optimal welding parameters in
order to produce good-quality welds without defects
and with good mechanical properties and a high
productivity. In case of quality issues in production
(due to weather, machine or consumable problems),
the welder is the key person to solve the problems.
Operators who just push the buttons are not capable
of doing this.
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Comprehensive training prior to testing and ‘tool-box’
talks during production should be used to convey
the importance of good welding practice and the
specification requirements applicable to the project.
Good pipe-end tolerances are likely to give better fitup which should result in better productivity, lower
repair rates, and greater longevity of copper backing
shoes on the internal line-up clamp. Typically, there
is a ± 1.6-mm tolerance on diameter for the pipe
sizes of interest to mechanized GMAW. Usually, the
tolerance on diameter and out-of-roundness is greater
for the pipe body than for the factory-supplied ends.
This can cause problems when a cut end is used for
production welding.
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and power brush to clean and/or dress the weld. Other
functions such as checking the earth clamp, gas settings,
power source settings, and connections are arguably the
responsibility of the technician.
Production welding
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The clearance between the bottom of the horizontal
pipe and the ground, or floor of the welding shack,
should be sufficient to allow unimpeded access for
the welding head, as well as physical access for the
welder to see the weld pool and to carry out any
remedial grinding. After completion of welding there
should also be sufficient access for visual inspection
and other non-destructive testing methods which
rely on equipment travelling around the outside of
the pipe. Generally, it is accepted that a minimum
clearance of 400 mm is sufficient.
Some methods of overcoming residual magnetism in
the pipe ends are not practical for GMAW, and it
may be necessary to use a dedicated demagnetizing
unit and coil. Stray arcs tend not to be an issue
with mechanized GMAW/FCAW systems since the
supply of arc current to the electrode is controlled by
the machine. There are various interlocks to provide
protection when cleaning the torch or changing a
contact tip. If an arc burn does occur despite these
precautions then remedial action is required according
to an approved procedure.
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Another aspect to consider is the clearance between
the welding and inspection equipment and any external
pipe coating, or concrete weight coating. The ‘cut-back’
distances, with suitable tolerances, need to be stated
in the linepipe coating specification. It is generally
accepted that a cut-back distance of 115 ± 15 mm
for the anti-corrosion coating will provide sufficient
access for welding and subsequent phased-array AUT
inspection. For projects involving heavy-wall pipe,
the cut-back distance may need to be increased. The
cut-back distance for the concrete weight coating
for offshore pipelines tends to be around 350 mm.
Again, for very thick concrete weight coatings, it is
possible that the cut-back distance may need to be
increased to avoid interference with the welding and/
or inspection heads.
Weld bands should ideally be placed on bare pipe
surfaces although, for various reasons beyond the control
of the welding contractor, this is often not possible.
It is often the case that the ‘feet’ of the bands are
either both on the coated pipe surface, or half on
and half off. This can cause problems with alignment
and stability of the welding band, as well as damage
to the external anti-corrosion coating, usually in the
form of indents into the softened coating. In extreme
cases, this can result in additional repairs having to
be made at the field-joint coating stage.
When using an internal line-up clamp with copper
backing shoes it is also normal practice to heat up
the shoes with a flame torch at the start of the day,
or after any prolonged delay, in order to eliminate
condensation or moisture and prevent rapid cooling
of the root pass on start up.
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The Journal of Pipeline Engineering
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After completion of the weld, it is also necessary to
remove all slag and weld spatter from the weld and
adjacent pipe surfaces. In addition to being a sign of
good workmanship, it is important to have a smooth
surface for the AUT probes to pass over unhindered,
and for good field-joint-coating integrity. Cleaning is
usually accomplished using a power brush, although
other tools may be required. Excessive grinding of the
pipe surfaces should be avoided, as this may also impede
the effectiveness of the AUT inspection.
Most, if not all, mechanized GMAW/FCAW systems
have the capability to measure and record the welding
parameters relative to the weld pass and angular position.
The information can be interrogated in real time, or
afterwards, to confirm whether the weld was made
in accordance with the approved WPD, or not. With
advances in pulsed welding, segment control, spatterfree ignition, seam tracking, and through-arc sensing, a
huge amount of data is generated. This cannot possibly
be assimilated by an inspector. However, it is feasible
automatically to evaluate the data and present the data
as either a ‘pass’ or ‘fail’.
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Some contractors allow both welders to start at top
dead centre (TDC) for vertical-down progression. Other
contractors adopt the practice of one welder starting
at TDC, whilst the other welder starts at 3 o’clock,
welding to 6 o’clock, returning to TDC and finishing
the root pass at 3 o’clock. This is more effective in
terms of maintaining a balanced sequence, but it does
mean that there is always a stop/start at the 3 o’clock
position. Some standards require a root stop/start to
be qualified during WPQT. Some contractors use more
than two welders on each side (simultaneously) on pipe
sizes over DN500. This can be achieved, but requires
careful organization.
be a cause of cold laps and may also mask missededge defects from being seen during visual inspection.
For this reason, it is good practice to power brush
the weld just prior to making the cap pass. When
using the FACW process, interpass cleaning is done
by power brush to remove the small amount of slag
from this process.
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One company standard states that a minimum of two
welders is required for pipe sizes greater than or equal to
457 mm OD. However, most – if not all – mechanized
GMAW welding with ‘bug-on-a-band’ systems use two
or more welders welding on opposite sides of the pipe
to maintain a balanced deposition sequence, particularly
for the root and hot passes. The fill and cap passes
could be welded with one welder, but this would not
be economic. Internal welding machines make use of
four, six, or eight welding arcs to make the root pass,
but are controlled by one operator at the end of the
pipe. Machine-mounted external welding systems, such
as the Saturne-8 system, control multiple welding heads
simultaneously, avoiding interactions between welders.
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The time limit between the start of the root and
the start of the hot pass is a throw-back to the days
of cellulosic welding where there was a real risk of
cold cracking. For mechanized GMAW welding it is
normal to specify a maximum time limit between the
completion of the root pass and the start of the hot
pass. But even the necessity of this variable depends
on the actual thickness of the root pass compared to
the pipe thickness. If the root has sufficient thickness,
i.e. 25% of the wall, there is no need put a restriction
on the time between passes
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It is particularly important for GMAW and FCAW
welding to remove clusters of surface porosity, stop/
start overlap, high points in the bead and other
visible defects before deposition of the next pass. This
is because GMAW is a low heat input process and
only has limited capacity to ‘burn out’ defects from
previous passes. Vertical-up flux-cored welding with a
rutile wire is more tolerant, but even so, it is better
to grind-out known defects. For narrow-gap GMAW or
FCAW, grinding needs to be done very carefully so as
not to damage or alter the bevel uniformity which in
itself could cause more weld defects.
GMAW is accepted as a non-slag forming process;
however, in heavy-wall, multi-pass, welds it is common to
see a build-up of a thin silicate ‘glassy’ slag. Generally,
the effects are benign, but this fine layer of slag can
Real-time data and event logging can also be performed to
record other activities such as manual override commands
for seam tracking and travel speed, delays between passes,
stop/starts, short circuits, and tip change-outs. It is
conceivable that in the future this information, together
with a vision sensor to measure weld bead profile and
‘hi-lo’, could be used in place of non-destructive testing.
Repair of defective welds
When a discontinuity or indication is deemed to be
outside the acceptance criteria, the contractor is faced with
the choice of either making a weld repair or a ‘cut-out’.
Remedial grinding of surface-breaking discontinuities is
not usually counted as a repair. The selection of repair
method and consumable should take into consideration
the metallurgical effect of the repair on the original
mechanized GMAW weld deposit.
Methods
Repair-welding processes need to be flexible to cope
with a variety of geometrical configurations and
non-ideal site conditions, and for these reasons, the
mechanized systems are generally not suitable for repair
welding. The most commonly used processes for repair
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The qualification of repair welds should be subject to
at least the same levels of inspection and mechanical
testing as the original girth welds. In this context it is
worthy of note that AS 2885.2 [5] does not currently
require any mechanical testing of repair welds, instead
relying only on macro examination and hardness
testing. In the authors’ opinion this is not acceptable
for mechanized GMAW welds in high-strength linepipe.
Inspection of welds
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The repair excavation length is usually restricted to
20% of the pipe circumference for full-penetration
repairs, and 30% for partial penetration repairs.
However, the designer or welding engineer should
assess each case to determine whether the stresses
acting on the pipe may place tighter restrictions on
the excavation length. This is particularly likely to be
the case for deepwater offshore installations where
considerable lengths of pipe may be hanging from the
laybarge. Engineering critical assessment methods have
been used to determine allowable excavation lengths,
taking advantage of the blunt shape of the groove to
disregard fracture and consider only plastic collapse.
The position selected for qualification of repair welds
should simulate the most onerous conditions. For example,
one end of a partial/full-penetration weld should be
at the 6 o’clock position on a fixed-position 5G weld,
and a vertical-down single-pass cap repair should be
made at the 3 o’clock position. For qualification of
partial-penetration repair welds, it is normal practice to
leave some of the original (mechanized GMAW) weld
so that the fusion boundary between the repair and
original weld can be tested (usually using Charpy testing).
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Removal or excavation of the defective weld material
can be by grinding and/or arc air gouging. The latter
method is preferred since it is very quick and often
it is possible to see the defect as the hot metal is
‘scooped’ out. For a full-penetration (or ‘root’) repair
it is normal practice to gouge to within 2 or 3 mm
of the root and to grind-out the remaining metal. It
is recommended that the repair welder performs the
gouging and grinding, since it allows him to visualize
the extent of the repair and mentally prepare for the
subsequent welding.
input may produce an unacceptable microstructure in
the heat-affected zone. Most pipeline standards also
require qualification testing of partial-penetration repair
welds and other options, such as back weld repairs.
or
d
welding are (i) basic coated low hydrogen SMAW,
(ii) gas-shielded semi-automatic FCAW, and (iii) selfshielded semi-automatic FCAW. Cellulosic electrodes
are generally not permitted for repair welding. Some
contractors use semi-automatic STT for the root pass
of full-penetration repair welds.
Visual inspection
-n
A challenge with most mechanized GMAW systems
is to keep the cap height within specification limits
(typically 1.6 mm at the 5-7 o’clock position on 5G
positional welds). The main reason for limiting the
cap height is to avoid problems with the integrity of
the field-joint coating. Welding systems according to
the current developments, like segment control and
pulsed weld parameters, are more able to control cap
bead height at the bottom of 5G welds. Making use
of a ‘split cap’ reduces the width of oscillation and
helps to control the size of the weld pool. This split
cap is, depending on the weld preparation and wall
thickness, often used in practice by twin-wire and
dual-torch systems.
e
co
py
Most standards also place limits on the proportion of
a girth weld which may be repaired and how many
attempts may be made at a repair. For example, BS
4515-1 restricts the cumulative repair lengths to 20%
and 30% for partial-penetration and full-penetration
welds, respectively. Only one attempt at a full-penetration
repair is permitted, whilst a second attempt at a
partial-penetration weld repair may be permitted.
pl
Qualification of repairs
Sa
m
Qualification of repair welds is normally performed as
part of the WPQT programme for mainline mechanized
GMAW welds. The number and type of repair-weld
configurations should be established beforehand.
Retrospective qualification of repair welds should not
be permitted, as this is considered bad practice due
to the risk of repair-weld-procedure qualification failure
which places unnecessary pressures on the project.
As a minimum, it is necessary to qualify a fullpenetration repair and a single-pass cap repair where
this is to be permitted. Qualification testing of a
single-pass cap repair is more important if a verticaldown technique is being used, since the low heat
Typically, visual inspection on production welds is limited
to the external cap profile. However, whenever possible,
the root should be inspected as well. In some instances
and depending on safety rules, it may be possible to
climb inside the pipe, but nowadays several camerabased vision systems are available, which allow rapid
and reliable visual inspection of the root-pass profile.
These systems are vital for CRA pipelines where it is
not possible to make full-penetration repairs. Internal
visual inspection is performed after the root or hot
pass has been completed, and if a defective profile is
found, then the whole weld is cut out and re-made.
On a laybarge this saves the time and effort of having
to back-up the barge just to re-make one defective weld.
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The Journal of Pipeline Engineering
rib
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over several years. The orientation of lack-of-fusion
defects on the sidewall of narrow-gap welds is generally
quite favourable for detection by this technique, but
other planar defects, such as cracks, are difficult
to detect. The probability of detection (POD) of
radiography related to planar defects is rather low.
Other consequences of radiography are safety (radiation),
environment (chemicals), and efficiency (examination
time and wait for inspection results). Since the image
on the film is a two-dimensional representation of a
3-D object, it is not possible to reliably ascertain the
depth and height of indications in the weld. For this
reason, conventional film radiography is not ideally
suited to alternative acceptance criteria which rely on
depth and height information as well as length. The
acceptance criteria of radiography are based on good
workmanship originally.
Additional visual inspection related to GMAW welding
co
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is
t
ot
f
It is not just the completed welds which need to
be inspected. Copper components (contact tips
and shoes from internal line-up clamps) should be
inspected regularly for signs of damage or wear during
production. Poor fit-up and non-optimized bevel or
welding parameters can cause excessive penetration of
the root bead onto the copper shoes. This reduces
the useful life of the shoes, and evidence of this
can be seen on shoes with pits on the surface and
blackened surfaces. In extreme cases, the shoes can
stick to the root bead preventing them from being
retracted by the pneumatic actuator or even tearing
out part of the root bead.
or
d
Fig.6. Example of copper cracking due to contamination
from the contact tip.
In the past decade, radiographic inspection of
pipeline girth welds has largely been overtaken by
AUT (automated ultrasonic testing), which is claimed
as having better reliability (i.e. POD) with a focus
on critical defects, being more suited to alternative
acceptance criteria, providing a permanent record and
to be safer as it does not use ionizing radiation.
However, in recent years, advances in digital radiography,
with lower radiation intensity due to the sensitivity of
digital detectors, have led to a resurgence in interest
in radiography as the primary means of girth-weld
inspection, especially suited for austenitic materials
and CRA pipelines.
Sa
m
pl
e
Contamination from the contact tip can occur either
from direct contact between the tip and the bevel
wall, or from ‘burn-back’ when the arc is switched
off. If, for some reason, copper contamination does
occur from the contact tip, it will inevitably result
in ‘copper cracks’ being formed (Fig.6). All welding
and NDT specifications stipulate that if cracks are
found during inspection, the weld shall be cut-out
and remade. However, with regard to copper cracking,
some pipeline specifications permit this defect to be
repaired. Copper cracking can be difficult to detect
and the possible presence of an adjacent embrittled but
uncracked copper-containing area must be considered
if copper cracks are to be repaired.
Radiography
Panoramic X-radiography has been used successfully on
many thousands of mechanized GMAW girth welds
Automated ultrasonic inspection
AUT systems using a combination of pulse-echo probes
(fixed-array or phased-array) and time-of-flight diffraction
techniques are favoured for inspection of pipelines.
These AUT systems can inspect a girth weld very
quickly. Before use on a project, the proposed AUT
system should be qualified in a manner analogous to
weld-procedure qualification.
At this moment there is ongoing discussion about
the application of AUT, such as: identifying critical
variables and how they affect AUT inspection;
understanding the technical capabilities of AUT
systems regarding POD; and sizing accuracy and
evaluation of the physical limits of AUT inspection,
such as minimum detectable flaw size and
inspection frequency.
Pipeline owners and operators need a better
understanding and reliability of the application
of AUT systems focused on their specific pipeline
project. A guideline for specification of AUT systems
has to be developed for cross-country and offshore
pipelines. Standards like API 1104, DNV-OS-F101,
ASTM-E-1961-11, and selected company specifications,
4th Quarter, 2013
289
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In principle either workmanship criteria or fitness-forpurpose approaches could be used to set acceptance
criteria for mechanized GMAW girth welds. Generally,
fitness-for-purpose criteria are used with mechanized
welds as they are able to take advantage of the
through-wall height information provided by the AUT
inspection systems which are generally used with
mechanized GMAW. An example of the integration
of AUT and defect-acceptance criteria is given in [9]
which describes the determination of AUT sizing
errors and the use of wide-plate testing to determine
defect-size limits.
ot
f
Production repair welds should be inspected by the
same NDT methods as were used to inspect the
original welds, as well as any methods which may be
more suited to the repair weld configuration. Generally,
this means that the repair welds are inspected by a
combination of AUT – to check that the original
defects have in fact been removed – and manual UT
and/or ToFD. The manual inspection is required
because the AUT system will not be optimized to
examine the variable position of the repair weld fusion
line. Even though the repair weld may be inspected
by AUT, the acceptance criteria should either be
based on workmanship standards or an ECA. If using
workmanship criteria, the repair weld must achieve
mechanical properties, particularly for toughness, that
are consistent with those that would be required when
workmanship standards are used. An ECA approach
must use fracture-toughness and yield-strength data
obtained for the repair weld; it cannot be assumed
that data from the original GMAW testing can be
used. Guidance on mechanical testing of repairs is
given in standards such as OS-F101, Appendix B [3].
rib
ut
Inspection and acceptance of repair welds
is
t
Another important issue is the interpretation of the
AUT system output (signals). This should be carried
out by personnel who have a thorough knowledge of
the AUT system and an understanding of the welding
system being used. They should hold a Level II
qualification in ultrasonic testing and have successfully
completed a full training course. The guideline shall
specify the minimum requirements for these personnel.
to the applied loads and the material properties. For
new pipeline construction, these alternative criteria are
usually derived during the design stage using generic
assumptions for the loads and material properties.
The assumed material properties would then be an
input to the specifications for linepipe procurement
and the development of welding procedures. It is also
possible to use alternative acceptance criteria to assess
a specific defect taking account of the actual loads
and defect position both along the pipeline route and
around the pipe circumference. This may occur after
a post-construction audit, or if the service conditions
change during the life of the pipeline.
or
d
have to be analysed as a reference for this guideline.
A technical justification is required as part of the
development of the guideline.
co
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Pipeline-specific alternative criteria are given in
CSA Z662 (Annex K for general use and Annex
J for assessing a specific defect), AS 2885.2, and
Appendix A of API 1104. The European Pipeline
Research Group has developed a set of guidelines for
weld-defect acceptance [10]. Originally aligned with
workmanship criteria, recent work [11] has extended
the Tier-2 requirements to make them more usable
with mechanized welding. A common feature of these
criteria is that the weld metal should overmatch the
parent pipe strength and have a minimum level of
toughness. The intention is to ‘shield’ any defects in
the weld from high stresses as the lower-strength pipe
will yield before the weld and so limit the stress on
the defect. The practical application of this apparently
simple requirement is difficult due to factors such as
variations in both pipe and weld metal actual strengths.
For mechanized GMAW, the narrow gap complicates
testing, as it is difficult to ensure that an all-weldmetal tensile specimen does not contain some parent
metal. It is also arguable whether a small-round-bar
tensile specimen fully reflects the performance of
the weldment.
Defect-acceptance criteria
Sa
m
pl
e
The ubiquitous workmanship criteria have served the
pipeline construction industry well over the years.
However, they are empirical and take little account
of (i) the material properties of the parent pipe and
the weldment, (ii) the actual service conditions, (iii)
the height of the defect, or (iv) whether the defect is
embedded or surface-breaking. Due to their empirical
nature, it is not always clear how conservative they are
for new high-strength materials or for arduous service
conditions such as high strains beyond yield or severe
fatigue loading. Workmanship criteria also do not
fully complement inspection methods such as AUT.
With the development of fracture mechanics and
fitness-for-purpose methods it has become possible
to develop alternative acceptance criteria which can
analyse the severity of defects in a quantitative manner.
Thus it is possible to relate the allowable defect size
The pipeline-specific assessment criteria usually have
limitations in their range of application, due to the
underlying test data used to calibrate them. For
example, Tier 2 of the EPRG Guidelines is currently
limited to C-Mn steels up to grade L485, 0.5% total
axial applied strain, and require a weld metal Charpy
impact energy of 40 J. If the project conditions or
290
The Journal of Pipeline Engineering
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This project was carried out with the support of the
EPRG Materials Technical Committee, with Dr Chris
Thornton of BP acting as project manager. This is
gratefully acknowledged. The authors also acknowledge
the support of the EPRG member companies and
welding contractors who provided examples of their
specifications and procedures. The opinions expressed in
this paper do not imply endorsement of any particular
system or equipment by the authors, their employers or
EPRG. An earlier version of this paper was published
in 3R International; the agreement of Vulkan Verlag
to allow the publication of the present paper is
gratefully acknowledged.
References
1. API 1104, 2005. 20th Edition: Welding of
pipelines and related facilities. American
Petroleum Institute.
2. BS 4515-1, 2009. Specification for welding of steel
pipelines on land and offshore. Part 1: Carbon and
carbon manganese steel pipelines. British Standards
Institution.
3.Det Norske Veritas, 2010. OS-F101: Submarine
pipeline systems.
4. Canadian Standards Association, 2007. CSA Z66207: Oil and Gas Pipeline Systems.
5. Standards Australia, 2007. AS 2885.2-2007: Pipelines
– Gas and liquid petroleum – Welding.
6.International Standards Organization, 2005. ISO
3834-2: Quality requirements for fusion welding of
metallic materials – Part 2: Comprehensive quality
requirements.
7. British Standards Institution, 1999. BS 4515-2:
Specification for welding of steel pipelines on land
and offshore. Part 2: Duplex stainless steel pipelines.
8. Det Norske Veritas,2010. RP-F118: Pipe girth weld
AUT System qualification and project specific
procedure validation.
9. R.M.Andrews and L.L.Morgan, 2004. Integration of
automated ultrasonic testing and engineering critical
assessment for pipeline girth weld defect acceptance.
In: International Conference on Pipeline Technology,
May 2004. Scientific Surveys, Beaconsfield, Vol 2,
pp 655-667.
10.G.Knauf and P.Hopkins, 1996. EPRG guidelines
on the assessment of defects in transmission
pipeline girth welds. 3R International, 35, 10/11,
pp 620-624.
11.R.Denys, R.M.Andrews, M.Zarea, and G.Knauf, 2010.
EPRG Tier-2 guidelines for the assessment of defects
in transmission pipeline girth welds IPC2010-31640.
-n
ot
f
Attempts have been made to quantify constraint effects
and reduce the conservatism using constraint-based
fracture mechanics’ methods, but these have not
been widely accepted in the pipeline industry.
DNV has proposed an approach, RP-F108[14], [15]
based on testing a single-edge-notch tension (SENT)
geometry, particularly for situations involving cyclic
plastic strain such as installation by reeling. To date,
the SENT test specimen has not been standardized,
which is a major limitation on the wider adoption
of this test.
Acknowledgments
is
t
Experience has shown that these generic assessment
methods often produce excessively conservative results
when applied to pipeline girth welds. Much of this
conservatism is due to these methods using a lowerbound material toughness measured using the standard
single-edge-notch bend (SENB) specimen. This uses a
deep notch (50% of the thickness) loaded in bending,
conditions which are designed to give a high crack tip
constraint and hence a lower bound to the toughness.
In contrast, most pipeline defects are much less than
50% of the thickness in through-wall height and the
dominant loading is tension. These conditions reduce
the constraint and increase the effective toughness.
the international standards to descriptive documents
will not lead to better welds; knowledge and QA/
QC in the field will.
or
d
materials are outside the code limits, then generic
methods such as BS 7910 or R6 can be used. These
offer greater flexibility by the correct choice of inputs
to match the pipeline geometry.
co
py
Pipeline owners and operators need guidelines for
a better understanding of these considerations,
and for interpretation of the application of defectacceptance criteria. It is intended that the guidelines
to be developed will address the differentiation of
defect-acceptance criteria and the level of AUT
system qualification required depending on
the application.
e
Concluding remarks
Sa
m
pl
There is no consensus in different standards regarding
the essential welding parameter requirements for
mechanized GMAW girth welding. The industry would
benefit from the development of a guidance document
covering best practices and the technical background
for the essential parameters, as the existing standards
do not give that guidance at the present time.
The guidance document can also have some positive
influence in discussions between the pipeline owner and
the construction company regarding the expectations
for high-quality welds.
It is not the purpose of the EPRG to rewrite all
international standards in order to diminish quality
and integrity problems during construction. Adjusting
4th Quarter, 2013
291
io
n
for pipeline installation methods introducing cyclic
plastic strain.
15.A.Cosham and K.MacDonald, 2008. Fracture control
in pipelines under high plastic strains – a critique of
DNV-RP-F108 IPC2008-64348. International Pipeline
Conference, Calgary, Canada. ASME, New York.
16.R.M.Andrews, N.A.Millwood, and P.Roovers, 2012.
An update on mechanized gas metal arc welding
(GMAW) of pipelines. 3R International, Special
edition, 2, 18-29.
rib
ut
International Pipeline Conference, Calgary, Canada.
ASME, New York.
12.British Standards Institution, 2005. BS 7910:2005
Incorporating amendment 1: Guide to methods
for assessing the acceptability of flaws in metallic
structures.
13.British Energy Generation Ltd, 2001. R6. Assessment
of the integrity of structures containing defects; R6
Revision 4. Barnwood.
14.Det Norske Veritas, 2006. RP-F108. Fracture control
Appendix: Essential variables
is
t
This table is an amalgamation, or summary, of the essential variables of relevance to girth butt welding. In
the last three columns it is indicated whether BS EN ISO 15614-1, BS 4515-1 and/or API 1104 address these
variables, either as essential (E), non-essential (NE), or not addressed (NA).
Sa
m
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e
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or
d
In the authors’ opinion, there is a danger of making the essential variables so onerous that weld-procedure
qualification testing on project-specific pipe has to be done each time. 
4
3
Welding process
2
py
co
Any change from single wire to multiple wire
systems and vice versa.
Number of wires
A change from a lower- to a higher-strength
grade, but not vice versa.
Groupings (as per API 1104):
(a) SMYS ≤ 290 MPa
(b) 290 < SMYS < 448 MPa
(c) SMYS ≥ 448 MPa (each grade shall be
separately qualified.)
A change in the supply condition (TMCP,
QT, or normalized).
Material grade
Supply condition
Base materials
Any increase
Hot key limits
is
t
E
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E
E
E
E
grouping on
chemical
analysis
NA
NA
NA
NA
NA
E
E
NA
E
E
E
BS 4515-1:
2009
E
E
E
BS EN ISO
15614-1: 2004
E
There are several ways of grouping
material grade. Most, if not all,
specifications adopt the principle of
restricting the maximum strength to that
welded in the procedure test.
The groupings suggested by API 1104
seem sensible since it is not good practice
to overmatch by too high a margin.
This is important for modern systems
which may use a dual torch, or tandem
wire arrangement.
Over-ride function
or
d
Any change
Software program
WPD should state revision number of
software/program.
This limits the procedure to a specific
Any change in make, type, and model for
partly mechanized, mechanized, or automatic system, which is sensible. However, the
system should include the power source,
welding
and controller.
ot
f
-n
Any change between manual, partly
mechanized, mechanized, and automatic
welding
Any change when multiple processes are
used.
Any change
This has the effect of limiting the use of
pre-qualified weld procedures.
Guidance notes
Welding
Welding equipment
Manual, partly mechanized,
mechanized, or automatic welding
Changes requiring
re-qualification
Any change in responsibility for operational,
technical and quality control
e
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m
The order of processes used
The process(es) used
Welding contractor
1
Variable
Sa
E
E
NA
NA
NA
E
E
E
E
NA
API 1104:
2008
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The Journal of Pipeline Engineering
5
Changes requiring
re-qualification
py
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For non-sour service:
t < 25 mm: change beyond 0.75 t to 1.5 t
t > 25 mm: change beyond 0.75 t to 1.25
For sour service:
a change outside the thickness range 0.75 t
to 1.25 t
Change in nominal outside diameter beyond
the groups qualified as follows:
D < 60.3 mm
60.3 mm < D < 323.9 mm
D > 323.9 mm
Alternatively, where there is a change in
diameter from a qualified procedure of more
than 50% of the nominal OD.
Material thickness of test joint
(where t is the nominal thickness).
Nominal OD of pipe
Guidance notes
or
d
The material thickness will have an
effect on the t8/5 cooling rate and hence
the HAZ hardness values. So, it is not
always wise to have too wide a range of
wall thickness covered by one PQR.
BS 4515 has a much more
comprehensive set of limits.
One should be careful to differentiate
between plate mill and pipe mill, i.e. a
pipe mill can obtain plate from more
than one plate mill, and similarly a plate
mill can supply plate to more than one
pipe mill.
NA
BS 4515-1:
2009
E
E
E
NA
io
n
E
E
E
NA
E
Grouping as per
CR-ISO 15608
includes chemical
limits.
NA
BS EN ISO
15614-1: 2004
rib
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is
t
Some specifications refer to the pipe
ID, but for simplicity the author prefers
nominal OD.
The minimum effective size for
mechanized GMAW/FCAW is 6 in.
ot
f
A change in the UNS number for CRAs.
UNS numbers
Material thickness and diameter
A change in manufacturing process (rolled,
seamless, forged, cast).
Manufacturing process
An increase in:
(i) Pcm of more than 0.020,
(ii) CE of more than 0.030, and
(iii) Carbon content of more than 0.02% for
C-Mn and low alloy steel.
co
For SMYS > 450 MPa: a change in base
material origin (steel mill).
e
pl
m
Chemical composition
Steel supplier
Variable
Sa
E, but no
clear limits
defined.
E, but no
clear limits
defined.
E
NA
NA
NA
API 1104:
2008
4th Quarter, 2013
293
7
6
py
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A reduction in the number or size of tack
welds or both.
Any change in removal of tack welds or
integration of tack welds in the [final] weld.
Omission of a line-up clamp and a change
between external and internal line-up clamp.
For mechanized GMAW: Any reduction in
the number of runs.
For manual or semi-automatic welding: Any
reduction in the percentage of root pass
completed.
Any reduction in the number of runs.
Any increase for clad and lined pipe
Line-up clamp
Removal of line-up clamp
Lowering-off (on land),
Barge move-up (offshore).
Internal misalignment
Guidance notes
Structural analysis should be carried
out to confirm minimum required weld
ligament.
NA
NA
io
n
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NA
NA
NA
NA
For mechanized GMAW 100% of
the root pass must be completed, as a
minimum, before removal of the line-up
clamp.
> 50% of root pass shall be completed
before line-up clamp is released. If clamp
is released before root pass completed
then at least 80% of both top and bottom
quadrants shall be completed.
is
t
NA
E
NA
External clamping applies to SMAW or
semi-automatic GMAW/FCAW root
pass.
Mechanized GMAW should be performed
together with an internal line-up clamp.
or
d
API 1104:
2008
NA
NA
NA
NE
NE
NA
E, J, to V
E, for main
configuration, or vice
versa.
tolerances
are to be
approved by
operator
BS 4515-1:
2009
NA
E
NA
BS EN ISO
15614-1: 2004
NA
Tack welds are generally not used for
mechanized GMAW, but may be used
for semi-automatic STT root pass.
For example, copper shoes.
Suggested tolerances are as follows:
Bevel angles (±1°)
Size of root face (±50%)
Width of root gap (+0.5 mm).
An increase in the permitted level of
high-low beyond that qualified should
also be considered as an essential
variable.
ot
f
Addition or deletion of backing, or change of
backing material.
Tack welding
Alignment and tack welding
Backing and backing material
co
Changes requiring
re-qualification
Any change in joint dimensions outside the
tolerances specified in the agreed WPS.
e
pl
m
Joint design/configuration
Joint configuration
Variable
Sa
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The Journal of Pipeline Engineering
9
8
Any change
Any change beyond range qualified
Electrode/wire spacing
Electrode/wire angle
Any change in designation, classification and
purity according to EN 439.
Any change of the nominal composition
(±10%), purity and dew point.
Any increase
Gases according to EN 439.
Other gases and mixtures.
Oxygen content of backing gas
Shielding, backing and plasma gases
Any change beyond range qualified.
Wire feed speed
NA
NA
E
E
E
NA
E
io
n
NA
NA
E
E
E
NA
E
E
E
E, with Charpy
requirements
NA
E
BS 4515-1:
2009
E
BS EN ISO
15614-1: 2004
rib
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For dual torch or tandem welding
or
d
ot
f
Any use of a welding consumable batch with
a reduction in tensile or impact properties
of more than 10% from the batch used for
WPQT when batch testing is not required.
is
t
Batch testing is required for most
offshore pipeline projects and highstrength onshore projects.
-n
Any use of an untested batch when batch
testing is required.
py
For lower material grades, change of
brand need not be an essential variable.
Where there is a significant change in
the proportion of the thickness welded
with different electrode classifications
there may be some merit in restricting
the range of qualification.
co
Any change of type, classification or brand.
Guidance notes
For manual welding it is normal to
specify:
- any change for the capping layer or the
first two layers, or
- any increase for other runs.
Changes requiring
re-qualification
Any change of diameter or cross-sectional
area
e
pl
m
Electrode or filler metal
Welding consumables
Variable
Sa
E
E
E
NA
NA
NA
NA
NA
E
E
API 1104:
2008
4th Quarter, 2013
295
10
e
Changes requiring
re-qualification
Any decrease
For tandem GMAW
Any change in type of current and a change Some specs only refer to a change of
from normal to pulsed current and vice versa. electrical current between AC and DC,
but with modern systems it is important
to consider any changes between normal
and pulsed current.
Any change in pulse frequency for
background and peak current exceeding
±10% and pulse duration range exceeding
±10%.
Any change in electrical stick-out exceeding
± 5 mm (different values may be used for
each run).
Any change in arc voltage exceeding ± 10%
Any change in wire feed speed or welding
current exceeding ± 10%
Any change in travel speed exceeding ± 10%
No separate restriction for calculated value of
arc energy.
For C-Mn and low alloy steels with SMYS
< 450 MPa in non-sour service: any change
exceeding ± 15%.
For C-Mn and low alloy steels with SMYS >
450 MPa in non-sour service: Any change
exceeding ± 10%.
For CRAs: Any change exceeding ± 10%.
AC, DC or pulsed current.
Pulse frequency range in pulsed
manual welding.
Contact tip to work distance
(electrical stick-out).
Parameter ranges
Arc energy range for each pass.
io
n
E, via heat input
rib
ut
E
E
E, via heat input
Tolerance should be based on the mean
value; not added to the range!
Notice the subtle difference between
‘heat input’ and ‘arc energy’.
is
t
E
NE
E, but
tolerance to
be defined by
operator
E
E
E via Heat input
E
NA
E
NA
E
BS 4515-1:
2009
Some specifications define a percentage
range (± 10%).
or
d
Any change in polarity
ot
f
-n
BS EN ISO
15614-1: 2004
Some specs are interested in the decrease NA
in shielding gas flow rate and the
decrease in the nozzle or cup size; rather
than any increases.
Guidance notes
Polarity
py
co
For processes 131, 135, 136, 137 & 141: any
change in flow rate beyond ±10%.
Electrical characteristics and pulsing data
Shroud diameter
pl
m
Shielding gas flow rate.
Variable
Sa
E
E
NA
E
E
E
NA
E
API 1104:
2008
296
The Journal of Pipeline Engineering
11
Any change in the sequence.
Any change in the sequence.
Not limited unless it is a reduction to less
than four passes.
Any change in the number of cap passes.
Change from single to multi-pass welding and
vice versa.
Any decrease in the number of welders for
welding of root and hot pass.
Sequence of deposition of different
consumables
Sequence of sides welded first and
last (double-sided welds)
Number of passes
Passes welded from each side.
Number of welders
Guidance notes
NA
Normal practice is to use two welders
per butt.
Dual-torch systems sometimes make use
of a split cap technique (two passes, one
run).
NA
E
NA
io
n
E
E
NA
E
E
E, but
tolerance to
be defined by
operator.
E, via heat input
E
E
E
NA
BS 4515-1:
2009
E
E
E
BS EN ISO
15614-1: 2004
rib
ut
is
t
or
d
The maximum amplitude of any
mechanized weave is to be agreed.
The frequency of any mechanized weave
is to be agreed.
The dwell time at the side of any
mechanized weave is to be agreed.
Horizontal (2G) welding would not
qualify fixed 5G positional welding.
Some spec state a ±5° tolerance from
nominal position, whilst others are more
generous in allowing ±25°.
For high-performance systems it would
be reasonable to specify the type of
power source as an essential variable.
ot
f
A change in amplitude, frequency, or dwell
time of any mechanized weave.
Stringer/weave
-n
A change from upwards to downwards and
vice versa.
Welding direction
py
co
A change of more than ±15° from the
position welded.
The L045 position qualifies for all positions
provided all other essential variables are
fulfilled.
Angle of pipe axis to the horizontal.
Welding techniques
Changes requiring
re-qualification
GMAW: a change from spray arc, globular
arc, or pulsating arc to short-circuiting arc,
and vice versa.
FCAW: a change from short-circuiting
transfer to spray or globular transfer.
Qualification with spray or globular transfer
qualifies both spray or globular transfer.
e
pl
m
Mode of metal transfer
Variable
Sa
NA
E
NA
NA
E
NA
E
NE
E
API 1104:
2008
4th Quarter, 2013
297
12
Changes requiring
re-qualification
-n
A change from flame heating to electrical
heating, but not vice versa.
N/A
Any reduction below 10°C.
Method of application
Method of controlling temperature
Initial temperature when preheat is
not used.
Guidance notes
NA
Method (i.e. temperature indicating
crayon, contact probe) should be stated
on WPD. It is the authors’ opinion
that non-contact thermometers (i.e.
infrared pyrometers) should not be used
for measuring preheat and interpass
temperature on welds.
NA
NA
rib
ut
is
t
or
d
It is generally accepted that electrical
methods (resistance and induction
heating) provide a more even,
controlled, temperature profile than
flame heating.
Some specs allow a plus tolerance (50 °C E
or 75 °C) on preheat, but really it is the
minimum preheat that is of interest. The
test weld must simulate the worst case to
be encountered during production.
io
n
E
NA
E
E
E
E
NA
Addressed
but only
essential
when
cellulosic
welding is
applied.
BS 4515-1:
2009
NA
BS EN ISO
15614-1: 2004
NA
This is for welds subject to AUT
inspection. If fast inspection is required.
Usually in field set up, this is not required.
For cellulosic electrodes it is the time
lapse between the start of the root run
and the start of the second run which is
important.
However, for hydrogen-controlled
electrodes it is usually the time lapse
between completion of root pass and
start of hot pass which is measured.
ot
f
Any reduction
Preheat temperature
Preheating
Any change in method and medium and any
increase in maximum temperature of the
weld at start of cooling.
Accelerated weld cooling
py
Any reduction in the number of passes
completed before cooling to below preheat
temperature.
Weld completion
co
Any increase in the time lapse beyond the
range qualified.
e
pl
m
Time lapse between completion of
root pass and start of hot pass.
Variable
Sa
NA
NA
NA
NE
NA
NA
E
API 1104:
2008
298
The Journal of Pipeline Engineering
Addition or deletion of post-weld heat
treatment.
Any change in method of applying heat.
Any change in holding temperature
exceeding ±20 °C.
Any change in holding time and any change
in heating and cooling rates outside ±5%.
Guidance notes
E
E
E
NA
NE
E
E
BS 4515-1:
2009
E
io
n
BS EN ISO
15614-1: 2004
rib
ut
is
t
or
d
Generally do not perform post-weld heat
treatment on TMCP linepipe.
13Cr martensitic stainless steel welds are
usually subject to a short heat-treatment
cycle (for example, 5 minutes at 650°C).
There may be certain instances where
the cleaning of the bevel and weld will
affect the performance of the weld, but
this is not really an essential variable.
Cleaning should be by hand tools, power
brush or grinder.
Usually measure minimum preheat and
maximum interpass temperature. For
C-Mn steels limit interpass to 250 °C
max.
ot
f
-n
Post-weld heat treatment (stress
relief).
py
co
Any reduction in time and temperature;
deletion (but not addition) of post heating.
Post-weld heat treatment
15
N/A
Post heating: hydrogen release
Cleaning of bevel and weld
Changes requiring
re-qualification
Any increase above 25°C for C-Mn and low
alloy steel. Any increase for CRAs. Any
reduction below the preheat temperature.
e
pl
m
Maximum and minimum inter-pass
temperature.
Interpass temperature
14
13
Variable
Sa
E
E
NA
E
API 1104:
2008
4th Quarter, 2013
299
io
n
September 30 – October 2, 2014
rib
ut
Calgary TELUS Convention Centre
is
t
Calgary, Alberta, Canada
-n
ot
f
or
d
EXHIBIT NOW
Held alongside International
Pipeline Conference
Sa
m
pl
e
co
py
Ensure your place at the world’s
largest pipeline gathering
internationalpipelineexposition.com
@petroleumshow #IPE14
4th Quarter, 2013
301
rib
ut
io
n
Prediction of the failure pressure
of corroded pipelines subjected
to a longitudinal compressive
force superimposed on the
pressure loading
by Dr Adilson C Benjamin
is
t
Petrobras R&D Centre, Rio de Janeiro, Brazil
S
or
d
EVERAL METHODS FOR the assessment of corroded pipelines subjected to internal pressure loading
are currently available: for example, the ASME B31G method, the RSTRENG 0.85dL method, and the
DNV RP-F101 method for single defects (Part B). These methods do not take into account the effect of a
longitudinal compressive force on the corroded pipeline failure pressure.
ot
f
When a corroded pipeline is subjected to a longitudinal compressive force superimposed on the pressure
loading, its failure pressure may be reduced. For a buried pipeline, the most common source of a longitudinal
compressive force is temperature loading; ground movement may also produce a longitudinal compressive
force in the pipeline.
-n
The DNV RP-F101 method for combined loadings and the RPA-PLLC method are two of the currently
available assessment methods which can take into account the effect of a longitudinal compressive force
on the corroded pipeline failure pressure.
co
Nomenclature
py
In this paper a comparison between the DNV RP-F101 method for combined loadings and the RPA-PLLC
method is presented.
Sa
m
pl
e
A – longitudinal area of metal loss
Asteel – area of the cross section of the pipe
De – outside diameter of the pipeline
d – maximum depth of the corrosion defect
E – Young’s modulus
(fR)h – reduction factor in the hoop direction
(fR)L – reduction factor in the longitudinal direction
I – moment of inertia of the cross sectional area of
the pipe
L – length of the corrosion defect
M – Folias bulging factor
Mb – external applied bending moment
This is an updated version of the author’s paper that was first published at
IPC, Calgary, in 2008.
Contact details:
tel: +55 21 2162 4782
email: acbenjamin@petrobras.com.br
n – ratio of the stress (σL)p to the stress σh
Nc – external applied longitudinal compressive force
p – pipeline internal pressure
pd – design pressure
(pa)comb – allowable pressure of a corroded pipeline
subjected to pressure loading plus longitudinal compression
(pa)press – allowable pressure of a corroded pipeline
subjected to pressure loading only
(pf)comb – failure pressure of a corroded pipeline subjected
to pressure loading plus a longitudinal compression
(pf)press – failure pressure of a corroded pipeline subjected
to pressure loading only
(pf)test – failure pressure measured in the burst test
t – wall thickness of the pipeline
Tinst – pipeline installation temperature
w – width of the corrosion defect
α – thermal expansion coefficient
α area – factor that depends on the geometric shape
adopted to represent the longitudinal area of metal loss A
302
The Journal of Pipeline Engineering
T
io
n
rib
ut
is
t
The software performs shell finite-element analyses of
pipeline corrosion defects under combined internal
pressure and longitudinal loads.
In a paper published in 1998 [18], Roberts and Picks
describe research work on corroded pipelines subjected to
a longitudinal compressive force or a bending moment
performed at the University of Waterloo. Based on
finite-element analyses and burst tests, the authors
developed an expression to calculate a longitudinal
stress factor to correct B31G or RSTRENG predictions
of burst pressure.
co
py
-n
ot
f
HE PUBLISHED LITERATURE about the
assessment of corrosion defects in pipelines subjected
to a longitudinal compressive force is not extensive.
Several papers found in the published literature [1-9]
are related to a research project carried out by the
Southwest Research Institute (SwRI) in the 1990s: this
project was funded by the Alyeska Pipeline Service Co
which operates and maintains the Trans Alaska Pipeline
System. The purpose of this project was to investigate
the structural behaviour of corroded pipelines subjected
to longitudinal compression due to temperature loading
and bending moment due to the freeze-thaw action of
arctic permafrost. The results of this project include
full-scale tests, finite-element analyses, and a computer
program named shell analysis failure envelope (SAFE).
σallow – allowable stress
(σallow)h – allowable stress in the hoop direction
(σallow)L – allowable stress in the longitudinal direction
σfail – failure stress of the material
(σfail)h – failure stress in the hoop direction
(σfail)L – failure stress in the longitudinal direction
σflow – flow stress of the material
σh – hoop stress
σL – longitudinal stress
(σL)p – longitudinal stress generated by the internal
pressure
(σL) ΔT – longitudinal stress generated by the temperature
rise ΔT
(σL)Mb – longitudinal stress due to an external applied
bending moment Mb
(σL)Nc – longitudinal stress due to the force Nc
σR – radial stress
σult – ultimate tensile stress of the material
σyield – yield stress of the material
or
d
ΔT – temperature rise above the temperature Tinst
γd – design factor, for example the safety factor applied to
the yield stress to establish the allowable circumferential
stress used to calculate the pipe wall thickness (according
to the ASME B31.4 code, γd is equal to 0.72)
γeqv – safety factor applied to yield stress to establish a
limit to the equivalent stress (von Mises stress or Tresca
stress) acting at any point of the pipe wall (according
to the ASME B31.4 code γeqv is equal to 0.90)
γm – modelling factor adopted by the DNV RP-F101
method for combined loading in the calculation of
the allowable pressure besides the usual design factor
(γm = 0.9)
ν – Poisson’s ratio
Σ(σL)add i – summation of the longitudinal stresses
generated by the additional loadings (loadings other
than the pressure loading). Herein it is supposed that
the stress Σ (σL)add i is negative (compressive)
σ1, σ2 – principal stresses
Sa
m
pl
e
Other papers found in the published literature [10-15]
are related to the joint-industry project (JIP) on Reliability
of corroded pipes carried out by DNV in the 1990s.
One of the objectives of this JIP was to investigate
the pressure strength of pipelines subjected to internal
pressure combined with a longitudinal compressive
force or a bending moment. Full-scale tests and finiteelement analyses were performed. Based on these results,
a method for the calculation of the pipeline failure
pressure taking into account the effect of a longitudinal
compressive force was developed. This method, called
the DNV RP-F101 method for combined loadings (DNV
CL method), was first published in the Section 7.3 of
the DNV RP-F101 [16] released in 1999.
In a report published in 1995 [17], Stephens,
Bubenik, and Francini presented the background of
the development of the PCORR computer program.
This research project was performed at Battelle under
the sponsorship of the Pipeline Research Committee.
In a paper published in 2008 [19], Benjamin presented
the RPA-PLLC method. This method is a modified
version of the RPA method [20] and can take into
account the effect of a longitudinal compressive force
on the corroded pipeline failure pressure. The RPA
method is itself a modified version of the RSTRENG
0.85dL method [21].
Note that RPA is the acronym for rectangular parabolic
area; PLLC is the acronym for pressure loading plus
longitudinal compression.
In this paper a comparison between the DNV RP-F101
method for combined loadings and the RPA-PLLC
method is presented.
Stresses in a pipeline subjected to
the pressure loading combined with a
longitudinal compressive force
Assuming that the pipeline is a thin shell the radial
stress σR at any point of the pipe wall is negligibly small.
Consequently there are only two stresses at any point of
4th Quarter, 2013
303
the pipe wall, the hoop stress σh and the longitudinal
stress σL. The assumption that the pipeline is a thin
shell is valid provided that the ratio of the pipeline
outside diameter De to the pipeline wall thickness t is
greater than or equal to 20 (De/t ≥ 20).
De
2t (1)
(σ L ) p = nσ h
rib
ut
σh = p
io
n
Besides the hoop tensile stress σh the internal pressure
also generates a longitudinal tensile stress (σL)p in the
pipe wall. The hoop tensile stress and the longitudinal
tensile stress are related to the internal pressure p by
the following equations:
(2)
longitudinal stress generated by the bending moment will
be a tensile stress; otherwise it will be a compressive
stress. The longitudinal stress due to an external applied
bending moment is given by the following equation:
or
d
n = 0.5 for longitudinally unrestrained pipe
(3a)
n = ν = 0.3 for longitudinally restrained pipe (3b)
is
t
Fig.1.Tresca yield criterion for a biaxial state of stress.
where
e
co
py
-n
ot
f
For a buried pipeline the most common source of
a longitudinal compressive force is a temperature rise
∆T. It is assumed here that even if the pipeline is (σ ) = ± M b De
(7)
L Mb
I 2
carrying a hot product, the steel properties at ambient
temperature can be used in the calculations. According
to the ASME B31.4 code [22], this assumption is valid where
provided that the pipeline temperature (Tinst + ΔT) is
π
less than or equal to 120oC.
=
I
( De4 − Di4 ) (8)
64
The longitudinal compressive stress generated by the
temperature rise in a straight pipe which is fully restrained The resultant longitudinal stress is equal to the
in the longitudinal direction is given by the Equn 4: longitudinal tensile stress plus the stress Σ(σL)add i which
is the summation of the longitudinal stresses generated
(σ L )∆T = − E α ∆t (4) by the additional loadings (loadings other than the
pressure loading).
A ground movement, such as a landslide, may also
produce a longitudinal compressive force in the pipeline.
σ L = (σ L ) p + ∑ (σ L )add i (9)
pl
The longitudinal compressive stress due to an external
applied longitudinal compressive force is given by Equn 5:
Nc
Asteel (5)
Sa
m
(σ L ) Nc =
where
=
Asteel
π
( De2 − Di2 ) (6)
4
A ground movement, such as a landslide or a differential
settlement, may also produce a bending moment Mb.
In this case there is a contribution of the bending
moment to the resultant longitudinal stress acting on
the corrosion defect. If the corrosion defect is situated
above the neutral axis of the pipe cross section, the
It is assumed here that the stress Σ(σL)add i is negative
(compressive). The resultant longitudinal stress is positive
(tensile) or negative (compressive) depending on the
value of the stress Σ(σL)add i.
Tresca yield criterion
The equations of the Tresca yield criterion for a biaxial
state of stress are as follows [23]:
σ1 − σ 2 =
σ yield if σ1 σ2 ≤ 0
(10)
σ 1 = σ yield or σ 2 = σ yield σ1 σ2 ≥ 0
(11)
Figure 1 presents a graphical representation of the
Tresca yield criterion for a biaxial state of stress.
304
The Journal of Pipeline Engineering
If the longitudinal stress is positive (tensile), the equations
of the failure criterion are:
h
σ L = (σ fail ) L
(16)
or
io
n
σ h = (σ fail )h (17)
rib
ut
Equations 16 and 17 are Equn 11 re-written such that
the longitudinal stress σL is the principal stress σ1,
the hoop stress σh is the principal stress σ2, and the
failure stress of the material is (σfail)L or (σfail)h.
Figure 2 presents a graphical representation of the
failure criterion based upon the Tresca yield criterion.
Level-1 assessment methods are the methods which
represent the longitudinal area of metal loss A on
the basis of the maximum defect depth d and defect
length L.
The RPA method is a Level-1 method which was
developed by Benjamin and Andrade [20], and is a
modified version of the RSTRENG 0.85dL method [21].
The method uses two different equations to predict
the failure pressure of a corrosion defect. The equation
for short defects is the same equation as that used
by the original 0.85dL method in the assessment of
short defects. However, the equation for long defects
is different from the equation used by the original
0.85dL method in the assessment of long defects, and
gives conservative results for long uniform-depth defects.
ot
f
The failure criterion adopted is based upon the Tresca
yield criterion. If the longitudinal stress is negative
(compressive), the start point to derive one of the
equations of the failure criterion is Equn 12 below.
is
t
Failure criterion
RPA-PLLC method
or
d
Fig.2. Failure criterion based upon the Tresca yield criterion.
σ L −σh =
σ fail(12)
py
-n
Equation 12 is Equn 10 re-written such that that the
longitudinal stress σL is the principal stress σ1, the
hoop stress σh is the principal stress σ2, and the failure
stress of the material is σfail.
co
Considering that the longitudinal stress is negative
(compressive) and the hoop stress is positive (tensile),
Equn 12 can be re-written as:
e
σh −σ L =
σ fail(13)
pl
or
m
σh
σ
− L =
1 (14)
σ fail σ fail
Sa
Considering that, due to presence of the corrosion
defect, the failure stress in the hoop direction is different
from the failure stress in the longitudinal direction,
Equn 14 can be re-written as:
σh
σL
−
=1
σ
σ
( fail )h ( fail )L (15)
Equation 15 is a general format equation that can
be used to derive different assessment methods [24]
depending on the expressions adopted to calculate the
failure stresses (σfail)h and (σfail)L.
Several methods for the assessment of corroded pipelines
subjected to internal pressure loading are currently
available; for example, the ASME B31G method [25],
the RSTRENG 0.85dL method [21], the DNV RP-F101
method for single defects [26], and the RPA method
[20]. These methods do not take into account the effect
of a longitudinal compressive force on the corroded
pipeline failure pressure.
When the corroded pipeline is subjected to a longitudinal
compressive force superimposed onto the pressure loading,
its failure pressure may be reduced.
The RPA-PLLC method is a modified version of the
RPA method which can take account of the effect of a
longitudinal compressive load on the corroded pipeline
failure pressure. This method can only be applied for
the assessment of pipelines made of steel.
The RPA-PLLC method was developed in 2004 and
was included in the first edition of the Petrobras
4th Quarter, 2013
305
Basic equations
The failure stress in the longitudinal direction is given by:
(σ )
fail L
= σ flow ( f R ) L (26)
The design pressure is given by:
pd = γ d σ yield
The flow stress of the material is given by:
2t
(27)
De
io
n
standard N-2786 [27], released in 2005. The method
was developed based on a failure criterion which checks
the pipeline plastic collapse. It is assumed that the
pipeline’s global buckling is prevented, and the local
buckling in the corrosion defect region will be checked
in parallel by another method.
Failure pressure
The reduction factor in the hoop direction is given by:
The failure pressure of the corroded pipeline subjected
to the pressure loading only is given by:
1 − α area (d / t )
1 − α area (d / t ) M −1 (19)
(p )
f
press
=
1 − α area (d / t )
2t
(28)
σ flow
De
1 − α area (d / t ) M −1
is
t
( f R )h =
rib
ut
σ=
σ yield + 69 MPa(18)
flow
where
 L2 


 Det 
6
L2
if
> 20
Det
or
d
α area = 1 − 0.15
64 ×106
The failure pressure of the corroded pipeline subjected
to the pressure loading plus a longitudinal compression
is given by the following equations:
(p )
f
(21)
(p )
f
=
2t
(σ fail )h H f (29a)
De
comb
= ( pf
)
press
if
(p )
f
-n
2 1/ 2
comb
ot
f
α area
L2
= 0.85 if
≤ 20
Det
(20)
L2
L2
if
> 20
(23)
Det
Det
co
M
= 2.1 + 0.07
py

 L2  
L2
L2
M= 1 + 0.6275
− 0.003375 
≤ 20
  if
Det
Det

 Det  
(22)
e
Equations 18 to 23 are identical to the ones adopted
by the RPA method [20].
comb
> ( pf
)
press
(29b)
where
Σ (σ L ) add

1 + (σ )
fail L
Hf = 
n (σ fail ) h

 1−
(σ fail ) L

i





 (30)
The derivation of Equn 29a was performed using Equns
15, 9, 2, and 1.
pl
The failure stress in the hoop direction is given by:
= σ flow ( f R )h (24)
m
(σ )
Sa
fail h
The reduction factor in the longitudinal direction is
given by:
( f R )L=
 d w 
1 −
(25)
 t π De 
The reduction factor in the longitudinal direction
(Equn 25) is the ratio of the cross-section area of the
corroded pipe (π De t – w d) to the cross section area
of the uncorroded pipe (π De t).
Equation 29b is a consistency check to guarantee that
the failure criterion in the circumferential direction is
not violated (Equn 17)).
Equation 29a is valid provided that the following
inequalities hold:
(σ )
fail L
> n (σ fail ) h
(31)
H f > 0(32)
In order to be consistent with the physical behaviour,
the internal pressure must be positive ((pf)comb > 0).
Consequently the parameter Hf in Equn 29a must
306
The Journal of Pipeline Engineering
be positive (Hf > 0). If the parameter Hf is negative
or null (Hf ≤ 0), there is no room for the pressure
loading and the additional loadings must be reduced.
( pa )comb = ( pa ) press
if
( pa )comb > ( pa ) press
(39b)
If the condition expressed by the inequality (31) is
not fulfilled, it is necessary to use Equn 15 (if σL is
negative) or Equns 16 and 17 (if σL is positive) to
obtain a set of (pf)comb and additional loadings which
comply with the failure stress criterion.
Allowable pressure

1 +
Ha = 
 1−


Σ (σ L ) add i 
(σ allow ) L 
n (σ allow ) h 
(σ allow ) L 
io
n
where
(40)
The derivation of Equn 39a was performed using Equns
35, 9, 2, and 1. The equation is valid provided that
the following inequalities hold:
( pa ) press = γ d ( p f ) press (33a)
(σ allow )L > n (σ allow )h (41)
(33b)
H a > 0(42)
( pa ) press > pd
Under service loadings, the state of stress at any point
of the pipe wall is limited by the following equation:
In order to be consistent with the physical behaviour,
the internal pressure (pa)comb must be positive ((pa)comb
> 0). Consequently the parameter Ha in Equn 39a
must be positive (Ha > 0). If the parameter Ha is
negative or null (Ha ≤ 0) there is no room for the
pressure loading and the additional loadings must
be reduced.
ot
f
σh −σ L =
σ allow(34)
is
t
if
or
d
( pa ) press = pd
rib
ut
The allowable pressure (pa)press of the corroded pipeline
subjected to pressure loading only is given by:
or
If the condition expressed by the inequality (41) is
not fulfilled, it is necessary to use Equn 36 (if σL is
negative) or Equns 37 and 38 (if σL is positive) to
obtain a set of (pa)comb and additional loadings which
comply with the allowable stress criterion.
Due to presence of the corrosion defect, the allowable
stress in the hoop direction (σallow)h is different from
the allowable stress in the longitudinal direction (σallow)L.
DNV RP-F101 method for combined
loadings
−
σL
co
σh
py
-n
σh
σ
− L =
1
σ allow σ allow
(35)
=1
(36)
e
(σ allow )h (σ allow )L
pl
The allowable stress in the hoop direction is given by:
(37)
m
(σ allow )h = γ eqnσ flow ( f R )h
Sa
The allowable stress in the longitudinal direction is
given by:
(σ allow )L = γ eqnσ flow ( f R )L
(38)
The allowable pressure (pa)comb of the corroded pipeline
subjected to the pressure loading plus a longitudinal
compression is given by the following equations:
(p )
f
comb
=
2t
(σ allow )h H a (39a)
De
The DNV RP-F101 method for combined loadings (the
DNV CL method) was developed in the 1990s during
the Reliability of corroded pipes JIP carried out by DNV,
and was first published in the Section 7.3 of the DNV
RP-F101 [16] released in 1999. Further details about
the method were given by Bjornoy, Sigurdsson, and
Marley [15]. The DNV CL method is recommended
in the Section 8.3 of the current edition of DNV
RP-F101 [26], released in 2004.
Basic equations
The flow stress of the material is given by:
σ flow = σ ult
(43)
The reduction factor in the hoop direction is given by:
( f R )h =
1 − α area (d / t )
1 − α area (d / t ) M −1 (44)
4th Quarter, 2013
307
(σ )
fail L
(σ )
fail h
= σ flow ( f R )h (47)
The reduction factor in the longitudinal direction is
given by:
 d w 
1 −

t π De (48)

( f R )L=
The failure stress in the longitudinal direction is given by:
(σ )
fail L
= σ flow ( f R ) L (49)
(p )
e
2t
(σ allow )h H f (51a)
De
comb
= ( pf
m
f
comb
=
pl
f
co
The failure pressure (pf)comb of the corroded pipeline
subjected to the pressure loading plus a longitudinal
compression is given by the following equations:
(p )
)
press
if
(p )
f
comb
> ( pf
)
press
(51b)
where
Sa
( pa )comb = γ mγ d ( p f )comb (55)
Comments about the RPA-PLLC
and the DNV RP-F101 method for
combined loadings
ot
f
2t
1 − (d / t )
σ ult
( De − t )
1 − (d / t ) M −1 (50)
py
press
=
The allowable pressure (pa)comb of the corroded pipeline
subjected to the pressure loading plus a longitudinal
compression is given by the following equation:
The similarities are the failure criterion based upon
the Tresca yield criterion (Equn 15), the general
format of the reduction factor in the hoop direction
(Equns 19 and 44), and the reduction factor in the
longitudinal direction (Equns 25 and 48).
-n
The failure pressure considering the corroded pipeline
subjected to the pressure loading only is given by:
f
Allowable pressure
Even though there are many similarities between the
RPA-PLLC method and the DNV RP-F101 method for
combined loadings, there still remain many differences.
Failure pressure
(p )
It is proposed that if the condition expressed by
the inequality (53) is not fulfilled, it is necessary to
use Equn 15 (if σL is negative) or Equns 16 and
17 (if σL is positive) to obtain a set of (pf)comb and
additional loadings which comply with the failure
stress criterion.
io
n
The failure stress in the hoop direction is given by:
H f > 0(54)
is
t
1/ 2

L2 
M= 1 + 0.31

Det  (46)

h
or
d
α area = 1.0 (45)
> 0.5 (σ fail ) (53)
rib
ut
where
Σ (σ L ) add i

1 + (σ )
fail L
Hf = 
σ
0
5
.
(

fail ) h
 1−
(σ fail ) L






(52)
Although in the DNV RP-F101 [16, 26] there is no
comment about the range of validity of Equn 51a, this
equation is valid only if the following inequalities hold:
The main differences are the pipeline restraint considered
in the longitudinal direction (the difference is clearly
detected by comparing Equns 30 and 52), the flowstress expression (Equns 18 and 43), the αarea parameter
expression (Equns 20, 21, and 45), the bulging factor
expression (Equns 22, 23, and 46), and the allowable
pressure expression (Equns 39a and 55).
DNV laboratory test results
Full-scale tests were performed as part of the DNV
JIP, and a detailed description of these tests and their
results were published by Bjornoy et al. [13]. Only a
brief description will be presented here.
Twelve burst tests were performed, of which nine were
with external longitudinal corrosion and three with
external circumferential corrosion defects. The tubular
specimens were loaded with internal pressure plus an
external load, except for two specimens which were
loaded with internal pressure only. The external load
considered was a longitudinal compressive force or a
bending moment.
308
The Journal of Pipeline Engineering
Specimen
d
(mm)
L
(mm)
w
(mm)
d
–
t
L2
–––
D et
w
–––
π De
1
5.15
243.0
154.5
0.50
17.7
2
5.15
243.0
154.5
0.50
3
5.15
243.0
154.5
4
3.09
162.0
5
3.09
6
applied failure loadings
Nc
(N)
Mb
(N.mm)
0.15
23.20
-
-
17.7
0.15
21.90
-
-1.290E+08
0.50
17.7
0.15
19.50
-
-2.120E+08
30.9
0.30
7.9
0.03
29.00
-
162.0
30.9
0.30
7.9
0.03
28.60
-2.563E+06
3.09
162.0
30.9
0.30
7.9
0.03
28.70
7
5.15
243.0
30.9
0.50
17.7
0.03
18.60
8
5.15
243.0
30.9
0.50
17.7
0.03
22.00
9
7.21
243.0
30.9
0.70
17.7
0.03
12.30
10
5.15
12.0
1017.9
0.50
0.04
1.00
11
5.15
12.0
1017.9
0.50
0.04
12
7.21
12.0
1017.9
0.70
0.04
io
n
pf
(MPa)
-7.300E+07
rib
ut
-
-
-3.000E+06
-
-
-
-2.070E+06
-
-2.289E+06
-
is
t
-2.943E+06
or
d
32.00
1.00
33.50
-2.343E+06
-
1.00
32.10
-2.399E+06
-
ot
f
De = 324 mm
t = 10.3 mm
σyield = 380 MPa
-n
σult = 514 MPa
(σflow)RPA
(MPa)
514
449
(σflow)DNV /(σflow)RPA
co
(σflow)DNV
(MPa)
py
Table 1. Dimensions of the tubular specimens and the applied failure loadings. Note: In the specimens subjected to bending
moment, the corrosion defect is located on the compressed side of the specimen’s cross section.
1.14
e
Table 2. Flow stress adopted by the assessment methods.
Sa
m
pl
The specimens were cut from seamless tubes made of
API 5L X-52 steel with a nominal outside diameter
of 324 mm (12.75 in) and a nominal wall thickness
of 10.3 mm (0.406 in).
The corrosion defects were longitudinal uniform-depth
defects generated using spark erosion, and mechanically
machined circumferential uniform-depth defects.
The tensile specimens were tested to determine the
material properties. The average yield strength and
the average ultimate tensile strength determined
were 380 MPa and 514 MPa, respectively. The mean
yield strength is 6.0% greater than the SMYS of
API 5L X-52 steel (SMYS = 358.5 MPa). The mean
ultimate strength is 12.9% greater than the SMTS of
API 5L X-52 steel (SMTS = 455.1 MPa). The ratio of
the mean ultimate tensile strength to the mean yield
strength is equal to 1.35. This value is greater than
the ratio SMTS / SMYS ((SMTS / SMYS) = 1.27).
Table 1 presents the dimensions of the tubular
specimens and the applied failure loadings.
Table 2 presents the values of the flow stress σflow
adopted by the two assessment methods, calculated
using Equns 18 and 43. The ratio of the flow stress
(σflow) DNV adopted by the DNV RP-F101 method
for combined loadings to the flow stress (σflow)RPA
adopted by the RPA-PLLC method is also presented
in this table. The most conservative expression is the
one adopted by the RPA-PLLC method, and the less
conservative is the one adopted by the DNV RP-F101
method for combined loadings.
For the specimens in the DNV tests, the flow stress
adopted by the DNV RP-F101 method for combined
loadings is 1.14 times the flow stress adopted by the
RPA-PLLC method.
4th Quarter, 2013
309
Specimen
Test
DNV CL
RPA-PLLC
(Nc)test
(N)
(Mb)test
(N.mm)
(pf)comb
(MPa)
(Nc)method
(N)
(Mb)method
(N.mm)
(pf)comb
(MPa)
(Nc)method
(N)
(Mb)method
(N.mm)
1
23.20
0.0
0.0
21.00
0.0
0.0
18.82
0.0
0.0
2
21.90
0.0
-1.290E+08
20.51
0.0
-1.290E+08
17.47
0.0
-1.290E+08
3
19.50
0.0
-2.120E+08
13.34
0.0
-2.120E+08
9.88
0.0
-2.120E+08
4
29.00
0.0
-7.300E+07
28.19
0.0
-7.300E+07
23.80
0.0
-7.300E+07
5
28.60
-2.563E+06
0.0
24.57
-2.563E+06
0.0
17.77
-2.563E+06
0.0
6
28.70
-2.943E+06
0.0
20.99
-2.943E+06
0.0
14.32
-2.943E+06
0.0
-3.000E+06
0.0
io
n
(pf)test
(MPa)
18.60
-3.000E+06
0.0
12.77
-3.000E+06
0.0
9.38
22.00
0.0
0.0
21.00
0.0
0.0
18.82
0.0
0.0
9
12.30
-2.070E+06
0.0
10.53
-2.070E+06
0.0
10.09
-2.070E+06
0.0
10
32.00
-2.289E+06
0.0
33.53
-2.289E+06
0.0
28.27
-2.257E+06
0.0
11
33.50
-2.343E+06
0.0
33.53
-2.343E+06
0.0
28.27
-2.257E+06
0.0
12
32.10
-2.399E+06
0.0
27.61
-2.399E+06
0.0
28.00
-2.235E+06
0.0
Specimen
DNV CL
is
t
or
d
Table 3: Actual and predicted failure loadings.
rib
ut
7
8
RPA-PLLC
(Nc)test / (Nc)method
(Mb)test / (Mb)method
1
0.91
-
-
2
0.94
-
3
0.68
-
4
0.97
-
5
0.86
1.00
6
0.73
1.00
7
0.69
8
0.95
9
0.86
10
(pf)test / (pf)comb
(Nc)test / (Nc)method
(Mb)test / (Mb)method
0.81
-
-
ot
f
(pf)test / (pf)comb
0.80
-
1.00
1.00
0.51
-
1.00
1.00
0.82
-
1.00
-
0.62
1.00
-
-
0.50
1.00
-
1.00
-
0.50
1.00
-
-
-
0.86
-
-
1.00
-
0.82
1.00
-
1.05
1.00
-
0.88
0.99
-
11
1.00
1.00
-
0.84
0.96
-
12
0.86
1.00
-
0.87
0.93
-
py
co
e
-n
1.00
m
pl
Table 4. Ratios of the predicted to the actual failure loadings.
Sa
Comparison between test results and
assessment method results
Table 3 presents the failure loadings applied in the
laboratory tests of the 12 tubular specimens along
with those predicted by the DNV RP-F101 method
for combined loadings (DNV CL method) and the
RPA-PLLC method.
For the DNV CL method the external loading
(longitudinal force Nc or bending moment Mb) applied
in the test was the input to the procedure applied by
the assessment method to calculate the failure pressure
(pf)comb. For this reason, the longitudinal force Nc and
bending moment Mb predicted by the DNV CL method
presented in Table 2 are 100% accurate.
For the RPA-PLLC method, the external loading
(longitudinal force Nc or bending moment Mb) applied
in the test was input to the procedure applied by the
assessment method to calculate the failure pressure (pf)
comb except for the specimens 10, 11, and 12. For these
specimens it was necessary to reduce the absolute value of
the longitudinal force Nc in order to obtain a non null
value of the failure pressure (pf)comb. These calculations were
performed using Equn 15 and imposing the condition
The Journal of Pipeline Engineering
rib
ut
io
n
310
1
-9.48
-18.87
2
-6.33
-20.23
3
-31.56
-49.31
4
-2.80
-17.91
5
-14.10
-37.85
6
-26.88
-50.12
7
-31.32
-49.56
8
-4.55
9
-14.40
10
4.79
-17.96
-11.66
0.09
-15.61
-13.99
-12.77
co
12
mean
-14.45
py
11
standard deviation
Table 4 presents the ratios of the predicted to the
actual failure loadings for the 12 tubular specimens,
and Fig.3 present the ratios of the predicted to the
actual failure pressures. The maximum accuracy that
one method could achieve would be a ratio (pf)comb /
(pf)test equal to the unity.
is
t
RPA-PLLC
or
d
DNV CL
A majority of the predicted failure pressures are
conservative, i.e. the ratios (pf)comb / (pf)test presented in
Table 4 are smaller than or equal to the unity. Among
the failure pressures predicted by the DNV CL method
there was only one unconservative ((pf)comb / (pf)test > 1).
Among the failure pressures predicted by the RPA-PLLC
method none was unconservative.
ot
f
Specimen
-n
Fig.3. Ratios of the predicted
to the actual failure pressure.
13.4
26.4
10.6
14.9
m
pl
e
Table 5. Error between the failure pressure predictions (%).
Note 1: error (%) = ((predicted – experimental) /
experimental) x 100
Note 2: mean = ∑ |error|/12
Sa
that the longitudinal stress σL is null (σL = (σL)p – (σL)
Nc = 0). Actually the condition that the longitudinal stress
σL is null was the loading condition under which the
burst tests of specimens 10, 11, and 12 were carried out
[28]. For this reason the longitudinal force Nc predicted
by the RPA-PLLC method for the specimens 10, 11, and
12 (see Table 2) are, respectively, 1.41%, 3.68%, and
6.82% smaller than those applied in the test.
In the input data for the RPA-PLLC method, the tubular
specimens were considered longitudinally unrestrained
(n = 0.5) because they were end-capped and longitudinally
unrestrained.
Table 5 presents the errors of the failure pressure
predictions.
The DNV CL method was the method that predicted
the failure pressures closest to the actual failure pressures.
The DNV CL method presented a mean error equal to
13.4% and a standard deviation equal to 10.6% while
the RPA-PLLC method presented a mean error equal
to 26.4% and a standard deviation equal to 14.9%.
The DNV CL method predicted five failure pressures
to be adequately conservatives (0% ≤ |error| ≤ 10%),
four failure pressures as moderately conservative (10%
< |error| ≤ 30%), two failure pressures as overly
conservative (|error| > 30%), and one failure pressure
as unconservative (error > 0%).
The RPA-PLLC method predicted eight failure pressures
to be moderately conservative (10% < |error| ≤ 30%)
and four failure pressures to be overly conservative
(|error| > 30%).
In relation to the DNV CL method, it is important
to mention that in the determination of the allowable
pressure according to this method, besides the usual
4th Quarter, 2013
311
((pf)comb)DNV
((pf)comb)RPA
1
21.00
18.82
1.12
2
20.51
17.47
1.17
3
13.34
9.88
1.35
4
28.19
23.80
1.18
5
24.57
17.77
6
20.99
14.32
7
12.77
8
21.00
9
10.53
10
33.53
11
12
33.53
27.61
io
n
((pf)comb)RPA
(MPa)
or
d
Table 6 presents the failure pressure ((pf)comb)DNV predicted
by the DNV CL method and the failure pressure
((pf)comb)RPA predicted by the RPA-PLLC method. The
ratio ((pf)comb)DNV / ((pf)comb)RPA is also presented in this
table. Except for specimen 12, all the failure pressures
predicted by the DNV CL method are greater than
the ones predicted by the RPA-PLLC method. Apart
from specimen 12, the ratios ((pf)comb)DNV / ((pf)comb)RPA
are between 1.04 and 1.47.
((pf)comb)DNV
(MPa)
1.38
1.47
rib
ut
It is also worth remembering that in any set of
experimental results there is always some scatter.
Specimen
9.38
1.36
18.82
1.12
10.09
1.04
28.27
1.19
28.27
1.19
28.00
0.99
is
t
design factor, a modelling factor of 0.9 is always applied.
This additional safety factor may be interpreted as a
de-rated factor that should be applied directly on the
flow stress established in Equn 43. According to this
approach, the value of the flow stress adopted by
the DNV CL method would be 90% of the ultimate
tensile stress (σflow = 0.90 σult) instead of 100% of the
ultimate tensile stress (σflow = σult). If this de-rated flow
stress had been adopted, the results of the DNV CL
method presented in Table 3 would be similar to the
ones predicted by the RPA-PLLC method (mean error
equal to 29.1% and standard deviation equal to 19.2%).
Table 6. Predicted failure pressures.
the DNV CL method, there was only one that was
unconservative. Among the failure pressures predicted
by the RPA-PLLC method, none were unconservative.
ot
f
Conclusions
With the exception of specimen 12, all the failure
pressures predicted by the DNV CL method are greater
than the ones predicted by the RPA-PLLC method.
py
-n
In this paper, a comparison between the DNV RP-F101
method for combined loadings and the RPA-PLLC
method was presented. Even though there are many
similarities between the RPA-PLLC method and the
DNV RP-F101 method for combined loadings (DNV
CL method), there still remain many differences.
co
The similarities are the failure criterion based upon
the Tresca yield criterion, the general format of the
reduction factor in the hoop direction, and the
reduction factor in the longitudinal direction.
The DNV CL method predicted the failure pressures
closest to the actual failure pressures. The DNV CL
method presented a mean error equal to 13.4% and
a standard deviation equal to 10.6%, while the RPAPLLC method presented a mean error equal to 26.4%
and a standard deviation equal to 14.9%.
The results of the full scale tests performed as part of
the Reliability of corroded pipes JIP, carried out by DNV
in the 1990s, were used to evaluate the performances
of the DNV CL and RPA-PLLC methods.
In relation to the DNV CL method, it is important
to mention that in the determination of the allowable
pressure according to this method, besides the usual
design factor, a modelling factor of 0.9 is always
applied. This additional safety factor may be interpreted
as a de-rated factor that should be applied directly to
the flow stress established in Equn 43. According to
this approach, the value of the flow stress adopted by
the DNV CL method would be 90% of the ultimate
tensile stress (σflow = 0.90 σult) instead of 100% of the
ultimate tensile stress (σflow = σult). If this de-rated flow
stress had been adopted the results of the DNV CL
method presented in Table 3 would be similar to the
ones predicted by the RPA-PLLC method (mean error
equal to 29.1% and standard deviation equal to 19.2%).
A majority of the predicted failure pressures are
conservative. Among the failure pressures predicted by
It is also worth remembering that in any set of
experimental results there is always some scatter.
m
pl
e
The main differences are the pipeline restraint
considered in the longitudinal direction, the flow stress
expression, the αarea parameter expression, the bulging
factor expression and the allowable pressure expression.
Sa
The two methods were developed based on a failure
criterion which checks the pipeline’s plastic collapse.
It is assumed that the pipeline’s global buckling is
prevented and the local buckling in the corrosion defect
region will be checked in parallel by another method.
312
The Journal of Pipeline Engineering
Sa
m
pl
e
co
py
-n
io
n
rib
ut
is
t
ot
f
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and M.F.Kanninen, 1995. The development of
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NACE Annual Conference and Corrosion Show
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2.H.R.Couque, M.Q.Smith, S.C.Grigory, and
M.F.Kanninen, 1996. The development of methodology
for evaluating the integrity of corroded pipelines
under combined loading - Part 1: Experimental testing
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3. Ibid. Part 2: Engineering model and PC program
development, pp 67-76.
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of 48-inch diameter corroded pipe determined by full
scale combined loading experiments. 1st International
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for the residual strength assessment of corroded
pipe subjected to combined loads. 1st International
Pipeline Conference, 1, pp 387-400.
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M.Anderson, 1997. Numerical simulations of full
scale corroded pipe tests with combined loading.
J.Press.Vessel Technology, 119, pp 457-466, November.
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Full-scale wrinkling tests and analyses of large
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Conference, 1, pp 543-551.
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1998. A new rupture prediction model for corroded
pipelines under combined loadings. 2nd International
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loading tests of large diameter corroded pipelines.
3rd International Pipeline Conference, 2, pp 769-779.
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Probabilistic calibrated design equation for burst
strength assessment of corroded pipes. 7th Offshore
and Polar Engineering Conference (ISOPE’97), 4,
pp 160-166.
11.O.H.Bjornoy, G.Sigurdsson, E.H.Cramer, B.Fu, and
D.Ritchie. 1999. Introduction to DNV-RP-F101. 19th
International Conference on Offshore Mechanics
and Arctic Engineering, OMAE 99.
G.Sigurdsson, E.H.Cramer, O.H.Bjornoy, B.Fu,
12.
and D.Ritchie, 1999. Background to DNV-RP-F101
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O.H.Bjornoy and M.J.Marley, 2001. Assessment
of corroded pipelines: past, present and future.
11th International Offshore and Polar Engineering
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15.O.H.Bjornoy, G.Sigurdsson, and M.J.Marley, 2001.
Background and development of DNV-RP-F101
corroded pipelines. 11th International Offshore and
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16.Anon, 1999. DNV Recommended Practice – DNVRP-F101 – Corroded pipelines. Det Norske Veritas,
Norway.
17.D.R.Stephens, T.A.Bubenik, and R.B.Francini, 1995.
Residual strength of pipeline corrosion defects under
combined pressure and axial loads. Final Report to
Line Pipe Research Supervisory Committee of the
Pipeline Research Committee of the American Gas
Association, NG-18 Report No. 216, A.G.A. Catalog
No. L51722, Battelle Memorial Institute, February.
18.
K.A.Roberts and R.J.Pick, 1998. Correction for
longitudinally stress in the assessment of corroded
line pipe. 2nd International Pipeline Conference,
1, pp 553-561.
19.A.C.Benjamin, 2008. Prediction of the failure pressure
of corroded pipelines subjected to a longitudinal
compressive force superimposed on the pressure
loading. International Pipeline Conference, September.
20.A.C.Benjamin and E.Q.Andrade, 2003. Modified
method for the assessment of the remaining strength
of corroded pipelines. Rio Pipeline Conference,
October.
21.J.F.Kiefner and P.H.Vieth, 1989. A modified criterion
for evaluating the remaining strength of corroded
pipe. Final Report on Project PR 3-805, Pipeline
Research Committee, American Gas Association.
22.Anon, 2006. ASME B31.4-2006 Pipeline transportation
systems for liquid hydrocarbons and other liquids.
The American Society of Mechanical Engineers,
October.
23.L.M.Kachanov, 1971. Foundations of the theory of
plasticity. North-Holland Publishing Co, London.
24.A.Cosham, 2002. Assessment methods for corrosion
in pipelines. A report to the Pipeline Defect
Assessment Manual (PDAM) Joint Industry Project,
Report NR99012/4238.1.72, Revision 3, September.
25.Anon, 1991. ASME-B31G – Manual for determining
the remaining strength of corroded pipelines – a
supplement to ANSI/ASME B31 Code for pressure
piping. The American Society of Mechanical Engineers,
New York.
26.Anon, 2004. DNV Recommended Practice – DNVRP-F101 – Corroded pipelines. Det Norske Veritas,
Norway.
27.Anon, 2005. Petrobras Standard N-2786 – Assessment
of defects and failure modes of land and submarine
steel pipelines. Petrobras, NORTEC, July.
28.O.H.Bjornoy, G.Sigurdsson, and E.H.Cramer, 1997.
Laboratory burst tests. DNV JIP Reliability of corroded
pipes. Report 96-3393, Revision 2, 7 May 1997.
or
d
References
4th Quarter, 2013
313
Comparing international pipeline
failure rates
by Peter Tuft* and Sergio Cunha
R
io
n
1 Peter Tuft & Associates, Sydney, Australia
2 Petrobras Transporte – Transpetro, Rio de Janeiro, Brazil
A
(Throughout this paper ‘failure’ refers to loss of
containment, while ‘incident’ is more general and
can include damage without loss of containment,
and near misses.)
ot
f
T FACE VALUE the failure rates of onshore
transmission pipelines in Australia appear to be
much lower than in the Americas and Europe. The
difference is large (note that the failure rates are lossof-containment events per 1000 km-yr for the most
recent five-year period. Derivation of these values is
explained later in the paper):
or
d
is
t
rib
ut
ATES OF PIPELINE FAILURE in Australia seem to be substantially lower than in the Americas and
Europe, at only 10-20% of the international mean for failures in onshore transmission pipelines. This
paper examines the validity of the Australian data and then explores reasons for the difference. Some
reasons are obvious, such as the relative youth of Australian pipelines which results in a negligible rate
of corrosion failures. However there is no obvious explanation for the markedly lower rate of failures
due to third-party damage. It is hypothesized that Australian practices for managing third-party damage
may differ in some way. Given the high social and economic cost of pipeline failures, there should be a
comparative study to identify any beneficial differences between third-party damage protection practices
in Australia and elsewhere.
A comprehensive overview of loss-of-containment rates
(excluding Australia) was presented by Cunha [1], and
Tables 1 and 2 from that paper are reproduced here.
More complete references to the data sources can
be found in the original paper. Note the variation
in reporting criteria from different regions. For gas
pipelines, most regions except the US include all
events involving loss of containment. Because the US
database contains only events that exceed thresholds
for severity1, it is possible that US rates are underreported relative to other regions.
-n
Australia
Ratio
Gas pipelines
0.15
0.032
21%
Oil pipelines
0.28
0.032
11%
py
International
co
This striking difference demands explanation and raises a
number of questions that will be addressed in this paper:
Sa
m
pl
e
• Are the Australian data valid?
• If so, is there something inherent in Australian
pipelines or their environment that minimizes the
likelihood of pipeline failures?
• Or is there something different about Australian
pipeline management that reduces the number
of failures?
The objective of this paper is to draw attention to what
appear to be real differences in some aspects of pipeline
failure rates in order to encourage further investigation
into the causes of those differences so that they might
be applied, if possible, for a wider benefit.
This paper was presented at the Joint Technical Meeting held between the
APIA, EPRG, and PRCI in Australia in April, 2013, and is reproduced by kind
permission of the APIA Pipeline Operators Group and the meeting’s organizers.
* Corresponding author’s contact details:
tel: +61 2 9983 1511
email: peter@tuft.id.au
Failure rates in the Americas and
Europe
For the purpose of this paper we will focus mainly on
the international mean values (highlighted in the tables)
for comparison with Australian data.
The Australian pipeline-incident
database
The Australian pipeline industry has been collecting
incident data since about 1965; at least, the earliest
recorded incidents occurred in 1965 and the oldest
transmission pipelines in Australian were only constructed
around 1960.
1 Significant incidents involve any of the following:
a. fatality or injury requiring in-patient hospitalization.
b. $50,000 or more in total costs, measured in 1984 dollars (equivalent
to about $115,000 at the end of 2012).
314
The Journal of Pipeline Engineering
Frequency of failure (/103 km-yr)
Region
Period
Exposure
(km-year)
Europe
1970 – 2010
3.55 x 106
0.35
0.16
EGIG
No lower limit.
Canada
2000 –2008
1.91 x 105
0.10
NA
NEB
Pipelines at 15 bar or more.
UK
1962 – 2010
7.73 x 105
0.23
0.093
UKOPA
No lower limit.
USA
1985 – 1997
5.96 x 106
0.11
NA
DOT–PRCI
Death, injury,
cost > US$ 50,000
Brazil
1978 – 2010
8.23 x 103
0.36
NA
Transpetro
No lower limit.
Average(1)
0.23
0.13
Mean(2)
0.20
0.15
Source
Reporting criteria
io
n
Five-year
average
rib
ut
Historic
is
t
Table 1. Frequency of failure for gas pipelines. Note: (1) arithmetic mean of the frequency of failures; (2) total number of
failures / total exposure.
Europe
1971 - 2010
1.01 x 106
Canada
2000 - 2008
2.41 x 105
Brazil
1978 - 2010
6.13 x 104
Historic
0.55
Reporting criteria
Five-year
average
Source
0.28
CONCAWE
1 m3 release.
ot
f
Period
0.10
NA
NEB
1.5 m3 release.
0.70
0.23
Transpetro
No lower limit.
-n
Region
or
d
Frequency of failure (/103 km-yr)
Exposure
(km-year)
Average
0.46
0.25
Mean
0.48
0.28
py
Table 2. Frequency of failure for liquid pipelines.
e
co
Pipelines for which incident data are collected are gas
and liquid transmission pipelines that are required
to comply with AS 2885 [2]. Maximum allowable
operating pressure must be above 1050 kPa.
pl
The Australian incident database collects three broad
categories of incident:
Sa
m
• loss-of-containment events (LoC)
• pipeline damage that required repair but did
not result in leak or rupture (gouges, dents,
deformation, etc., but excluding routine corrosion
repairs)
• near misses, comprising unauthorized third-party
excavation activity on the pipeline easement.
There is on average only about one LoC event each
year, although the number fluctuates widely and in
recent years has ranged from zero to three. Limiting
the data collection to these rare LoC events would
provide the industry with very limited scope for
learning. The collection of a broader range of incident
types is an attempt to learn from the more-frequent
events involving minor damage (about 130 items in
the database) and the much-more-frequent events
involving near misses (about 460 items).
Since 2007 the scope of the database has also included
incidents from New Zealand, but the NZ data are
not included in this analysis.
The database contains about 100 fields to record
data about the pipe itself, the events causing the
incident, details of any damage and repairs, and
operating practices (particularly relating to external
interference protection).
Reporting is voluntary and data are collected by the
Australian Pipeline Industry Association from members
of its Pipeline Operators Group (POG). Practices for
reporting and recording incidents have developed over
time and there was a period when it appears that
reporting was less rigorous. However we are confident
that the data collected since about 2002 are reasonably
4th Quarter, 2013
315
Period
International
Historical
(all data)
Five-year
(most recent period)
Gas pipelines
0.20
Oil pipelines
0.48
Gas pipelines
0.15
Oil pipelines
0.28
Australia
32%
0.063
13%
21%
0.032
11%
rib
ut
is
t
Before the 1990s it seems that the largely governmentowned pipeline authorities reported LoC and damage
incidents at a rate which appears plausibly realistic.
Full reporting would have been consistent with what
is known of the organizational cultures of the time.
However there is no hard evidence that reporting of
failures was complete.
Because there is some doubt about the completeness
of early data, the analysis presented here de-emphasizes
failure rates prior to 2002 although it is sometimes
necessary to use the full data set because the small
number of failures since 2002 is not always sufficient
for meaningful analysis.
ot
f
In practice, we find that each year a few POG members
fail to submit their declarations and/or incident reports by
the deadline. At face value that has given an impression
of poor reporting but we also find that the problem is
mainly one of timing rather than non-reporting, since
the missing data are almost always provided before the
closure of the next reporting period.
the voluntary incident-reporting system lapsed among
many operators during this period.
or
d
• POG members represent 94% of the total
transmission pipeline length in Australia.
• Each year POG member companies submit a
signed declaration that they have either reported
all incidents or have had none.
io
n
Table 3. International and Australian comparison.
complete, and that any omissions are insufficient to
affect the overall conclusions drawn in this paper.
That confidence comes mainly from two observations:
Ratio
The most recent publicly available analysis of Australian
incidents was presented at the Australian Pipeline
Industry Association convention in 2009 [3]. The data
presented in the current paper are based on more
recent analyses, including failures since 2009.
co
py
-n
The total length of pipelines considered in this analysis
is 32,020 km, representing all pipelines operated by
POG member companies that have reported consistently
for the last few years. There is a further 1100 km
operated by POG members that was omitted because
recent incident reporting has been somewhat patchy
(probably no incidents, but we are not completely certain).
Non-members of POG operate another 2400 km of
pipeline for which there are no recent incident data.
Sa
m
pl
e
Gas pipelines comprise about 83% of the total Australian
pipeline length and the remaining 17% carry diverse fluids
including various forms of oil as well as LPG, ethane,
etc. The incident database is capable of distinguishing
gas pipelines from others, but the distinction has not
been crucial to this analysis. In particular, because the
overall failure rate is low, it is not very meaningful
to present results on a small subset of the pipeline
system for which the number of failures per year may
be zero for many years in a row.
Data prior to 2002 should be treated with caution.
A sharp drop in reported incidents during the 1990s
corresponds to a transition of pipeline ownership from
government authorities to various private operators.
This was not a clean transition and many pipelines
changed hands (or at least management) several times
as the newly privatized industry slowly settled into a
new regime that was commercially viable. It appears that
Australian failure rates
The historic mean Australian failure rate, based on
all recorded failures, is 0.063 failures per 1000 km-yr,
based on a total of 43 LoC events2. The total exposure
underlying this failure rate is 684,000 km-yr, which is
in the middle of the range of the exposures for other
regions listed in Tables 1 and 2.
The failure rate in recent years is more relevant than
the overall historical rate for two important reasons.
Firstly, more-recent Australian data have greater validity
as discussed above. Secondly, if we are seeking lessons
from the data about possible improvements to pipeline
operation then it is important to look at data that
2 The 43 LoC events include 15 corrosion failures, mostly in the 1960s and
1970s, on a single pipeline that was particularly badly managed (it started
leaking within a year or so of commissioning and is no longer in service).
When reporting within Australia we usually omit these failures since they
reflect practices no longer used and are highly unrepresentative. However
for the purpose of comparing overall historical failure rates they are included
here because the data for other regions may include failures on similarly
poorly maintained lines.
316
The Journal of Pipeline Engineering
Year
Total
Third party
2002
3
2
2003
0
2004
0
2005
1
2006
2
2007
0
2008
0
2009
1
2010
0
2011
1
2012
3
Total
11
3
Average rate(1)
0.034
0.009
Corrosion
Material/
construction
Natural events
1
io
n
1
1
rib
ut
1
1
is
t
or
d
1
0.003
1
1
2
2
5
0.006
0.016
ot
f
Table 4. Australian loss-of-containment events. Note: (1) average rate in failures per 1000 km-yr based on total exposure of
320,000 km-yr since 2002.
-n
reflects current practice and avoids past practices that
are no longer applicable. The rolling five-year average
failure rate was the basis for comparison of regions
in Tables 1 and 2 and will be adopted here as well.
co
py
The current Australian five-year average is 0.032 failures
per 1000 km-yr, but due to the very small number
of failures each year, it fluctuates considerably and
for 2011 was only 0.013 per 1000 km-yr. The rolling
10-year average hovers at around 0.028 per 1000 kmyr. Nevertheless, for consistency, we will use here the
somewhat higher five-year value.
m
pl
e
Table 3 compares international and Australian failure
rates for both all data and the most-recent five-year
period. The Australian values are markedly lower than
the international mean and also significantly below any
individual region reported in Tables 1 and 2.
Sa
Table 4 shows a breakdown of Australian LoC events
since 2002. The last row of the table shows the average
failure rate for the period since 2002, but given the
erratic occurrence of failures due to any single cause,
these figures are at best only indicative and are not
discussed further. However it is possible to make some
general comments and observations:
• The paucity of corrosion failures is notable.
Further, apart from the badly managed pipeline
mentioned in Footnote 2, there are no failures
due to metal-loss corrosion in the entire database.
The single event in 2006 was an SCC defect
revealed by in-line inspection and found to be
almost imperceptibly weeping when exposed for
repair.
• It is also notable (and surprising) that there
have been no LoC events caused by third-party
damage since 2005. Third-party damage incidents
do occur: there have been 31 pipeline strikes
since 2002 but most have resulted in only minor
harm to the pipe or coating.
• Of the five failures due to natural events, four
were due to lightning plus one due to earth
movement. There are three additional non-LoC
lightning damage events (largely found through
in-line inspection) plus one more leak in 2001 just
prior to period covered by the Table 4. The fact
that lightning damage is the single largest cause
of LoC was unexpected and is likely to be the
subject of further investigation within Australia.
Are the Australian data valid?
The answer to this question is implicit in the earlier
description of the Australian incident-reporting system.
While some questions may be raised about the overall
historical rate derived from all failures since 1965,
we are confident in the data collected since 2002.
It has been necessary in this analysis to make some
assumptions or approximations. In every case (in
both preceding and following sections of this paper)
4th Quarter, 2013
317
International or UK
Australia
Ratio
No. of Aust.
failures
Aust. pipeline
length, km
All third-party failures
0.09
0.022
24%
15
31,200
Urban areas (1)
0.18
0.066
37%
9
2,100
Rural areas (1)
0.049
0.016
33%
6
29,100
Location
Are Australian circumstances
different?
rib
ut
ot
f
Population density: influence on third-party damage
Table 5 summarizes the available data: in both urban
and rural areas the Australian failure rate is a fraction
of the international mean failure rate, and hence the
low Australian rate cannot be attributed to a low level of
third-party activity in vast expanses of unpopulated land.
The international mean values in Table 5 are based
on data from Europe, the UK, the US, and Brazil
for the first row (all third-party failures), but only
on UK data for the last two rows (see Tables 9 and
10 in [1]). Data collected from other regions do not
allow analysis based on location class or population
density. This difference in source data explains why
the ratio of international to Australian failure rates for
all third-party failures is not a weighted average of the
rates for urban or rural areas but is lower than either.
Because the overall UK third-party failure rate is little
more than half of the international mean (see [1]),
the figures in the ‘ratio’ column are probably inflated
(perhaps roughly double) relative to the values they
would take if a true international mean was available
for comparison.
is
t
Further, the difference between recent Australian and
international failure rates is so large that it far outweighs
any possible under-reporting of Australian failures. It is
not credible that under-reporting of Australian failures
could be so extreme that the true Australian failure
rate could be even doubled, let alone comparable to
the international mean rates.
been only three third-party damage failures since 2002,
one in a remote rural location and two in suburban
areas. Hence breakdown against population density
must be based on the whole data set back to 1965.
or
d
we have taken the approach least favourable to the
Australian data, and yet Australian failure rates still
compare very favourably.
io
n
Table 5.Third-party failure rates. Note: (1) For these rows the values in the ‘international’ column are for UK only.
py
-n
A natural reaction on learning of the low Australian
failure rate is to assume that Australian pipelines are in
unpopulated desert areas and hence largely unaffected by
third-party activities. While it is true that Australia has
thousands of kilometres of pipelines in remote locations
it also has a significant proportion in more populated
areas including semi-rural regions, city outskirts, and
within cities. It is helpful to break down failure rates
based on location class.
Sa
m
pl
e
co
As a factor influencing failures rates, location classification
is relevant only to failures caused by third-party
damage. All other things being equal, the likelihood
of third-party damage depends mainly on the level of
third-party activity around a pipeline, which depends
on the population density that is in turn reflected in
the location class. In general it seems reasonable to
expect that failures due to corrosion, natural events,
and defects in material or construction should be largely
independent of the land use and population density
around the pipeline. At most, failures in these categories
may be influenced by location class only insofar as
the pipeline operator may take additional precautions
(for example, more intensive corrosion monitoring) in
locations where the consequences of failure are higher,
but that is a secondary effect that can be ignored for
the present purposes.
Because third-party damage failures have been so
infrequent in Australia it is not meaningful to analyse
population effects in the most recent period; there have
The basis for assigning failures to urban or rural
areas in Table 5 also deserves explanation. AS 2885
nominates four location classes: R1 (broad rural), R2
(rural residential), T1 (suburban), and T2 (high density),
and these roughly correspond to location classes 1 to
4 in US pipeline codes. In practice, R2 locations tend
to have quite a lot of roads, underground services,
farming activities, etc., so the level of third-party activity
is much higher than in the more-remote R1 locations.
However the comparison is largely with UK data, and
Australian R2 areas are probably roughly comparable
to UK rural areas. Hence for this analysis, Australian
failures in location classes R1 and R2 are grouped in
Table 5 as ‘Rural areas’, while T1 and T2 are grouped
as ‘Urban areas’.
As it happens, there was only one failure in an R2
location, but grouping R1 and R2, and T1 and T2,
also minimizes the exposure of pipeline in urban areas
which has the effect of increasing the calculated failure
rate. This approach is conservative in the sense that
318
The Journal of Pipeline Engineering
any resulting bias will be in the direction of making
the Australian failure rate in populated areas higher
rather than lower.
the single poorly protected pipeline that suffered 15
external corrosion leaks mostly in the 1960s and 1970s.
There have been no other metal-loss corrosion failures.
Another possible explanation for the low failure rate
is that Australian pipelines are better protected against
external interference through greater wall thickness
or deeper burial. We believe that neither is the case.
Most Australian pipelines are relatively small diameter
and hence thin-walled. There are few pipelines larger
than DN 500 (20 in) (the maximum existing size is
DN 750 (30 in) but DN 1050 (42 in) currently under
construction). Wall thicknesses are typically under 10
mm, often around 6 mm or down to 4.8 mm on
small-diameter lines. In populated areas, pipelines
built since the late 1990s have increased thickness but
there are many older pipelines in urban areas that
are thin. Standard burial depth in rural areas is 750
mm although some pipelines are at 900 mm cover
while in urban areas the minimum cover is 1200 mm.
These thicknesses and depths do not appear to provide
unusually robust protection.
There have been only two stress-corrosion-cracking failures,
both on the same pipeline. SCC occurs too erratically
and is too pipeline-specific for any broad conclusions
to be possible, and so is not discussed further here.
io
n
rib
ut
or
d
is
t
The relative youth of Australian pipelines is the most
obvious explanation for these low rates of failure due
to corrosion or defects. It is possible that there may be
other factors contributing to the low corrosion failure
rate but deeper investigation would be necessary to
uncover them.
Are Australian circumstances different for failures due
to corrosion or defects in material or construction?
Perhaps, in that most Australian pipelines are relatively
young and well protected.
ot
f
In answer to the question “Are Australian circumstances
different?”, we would argue that the answer is “No”
but the failure rate is low nevertheless.
There have been four failures due to material or
construction defects, all pinhole leaks in girth welds
(3) or a seam weld (1). Two occurred in 1983 (on the
same poorly managed pipeline as the multiple corrosion
leaks), the others in 2002 and 2012. With such sparse
failures it is not very meaningful to calculate average
failure rates.
Pipeline age: influence on construction defects and
corrosion failures
py
-n
Australian pipelines are relatively young, which offers
several benefits, including the use of modern standards
for materials and construction, the use of modern
practices for corrosion protection, and less time to
accumulate deterioration.
Sa
m
pl
e
co
Roughly 80-85% of Australian pipelines were built after
1980 when factory-applied coatings on grit-blasted pipe
became standard practice and replaced over-the-ditch
coatings on poorly prepared pipe surface. Good cathodicprotection systems have been applied since at least the
1970s. Also, since the 1970s, there have been generally
high standards of specification and quality assurance
for materials and construction. Government ownership
of many pipelines built between about 1970 and 1990
may have been a contributing factor to generally high
standards, as the culture of the government authorities
tended to be risk-averse and also the commercial pressures
to minimize costs may have been a little lower for
such organizations.
It seems that this fortunate history is reflected in very
low failure rates of Australian pipelines due to corrosion
and defects in materials or construction.
The rate of metal-loss corrosion failures on Australian
pipelines has been zero for over 20 years. Arguably,
it has been zero for all ‘modern’ pipelines, omitting
Natural causes
In terms of overall failure rate due to natural causes,
the Australian average is not very different from the
international mean. Historical and five-year rates are
0.010 and 0.026 respectively (but the latter is highly
variable), compared with international means of 0.018
and 0.014 respectively. There is no obvious conclusion
to be drawn here.
However there is a difference in the distribution of
failures due to natural causes. There have been only
seven Australian failures due to natural causes, two
(29%) due to earth movement and five (71%) due to
lightning. In contrast, in the Americas and Europe
earth movement accounts for 50 - 100% of naturalevent failures and lightning causes only 0 - 10%.
The low rate of geologically caused failures is
not surprising given the stable terrain in most of
Australia. However the high rate of lightning failures
is unexpected and perhaps reflects a high-lightning
environment, but that is only speculation and more
investigation is necessary.
It seems that the Australian environment is rather
different for pipeline failures due to natural events,
although this is reflected in the distribution of failure
causes rather than the overall failure rate.
4th Quarter, 2013
319
Summary of differences
design and then reviewed every five years or
whenever the environment around the pipeline
changes (such as for new urban development).
This study is a fine-grained analysis, often
on a metre-by-metre basis, of all possible
causes of pipeline failure. Threats to pipeline
integrity are explicitly identified and mitigated,
with great emphasis on protection against thirdparty damage.
• The safety-management study is an engineering
process but may have a cultural side effect:
because it is integral to Australian pipeline
design and operation it may help keep safety
matters – and particularly the consequences of
pipeline failure – in the forefront of pipeline
engineers’ thinking at all times.
io
n
Do these differences between Australian and
international conditions for pipelines explain the
markedly lower Australian failure rate? Only partly.
They may explain the virtual absence of corrosion
failures in Australia, and they may also explain the
different pattern of failures due to natural events.
However they do not explain the much lower rate of
failures due to third-party damage.
The absence of a simple explanation for the low
Australian failure rate is not a clear-cut and satisfying
conclusion. However the objective of this paper is to
initiate discussion of whether others might benefit
from research into the differences between Australian
and international failure rates. We believe it provides
a convincing case that Australian pipeline failure
rates are indeed substantially lower than elsewhere
and hence that investigation of that difference has
potential to provide benefits in reducing failure rates
in other parts of the world.
Sa
m
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e
co
py
-n
ot
f
• Australian pipelines in populated areas tend to
be patrolled frequently, usually on the ground
but sometimes by air. In and around at least
two major cities the transmission pipelines
are patrolled every day or every weekday, and
in other cities they are patrolled weekly. The
incident database contains about 20 near-miss
events where patrollers have caught third parties
in the act of digging or preparing to dig on the
easement, and there are many more instances
where work near the pipeline was forestalled by
patrollers before encroaching on the easement
(such off-easement activity is not reportable but
there is ample anecdotal evidence).
• The ‘One-Call’ or ‘Dial-Before-You-Dig’ system is
well used by third parties with only rare lapses.
• Pipeline marker signs tends to be frequent,
conspicuous, and explicit in their warning message.
• Since 1997, AS 2885 has required a safety
management study to be undertaken during
is
t
Following are some speculative comments on Australian
practices that might contribute to low third-party
failure rates, although they are only very tentative
explanations for the different failure rates until there
is better information on whether practices elsewhere
do in fact differ significantly.
We reiterate that all or none of these factors may be
responsible for the low rates of Australian failures due
to third-party damage, although they at least suggest
possible initial directions for investigation.
or
d
The mostly likely explanation for the low rate of thirdparty damage failures in Australia is some difference in
approach to managing third-party interference. Exactly
what that difference might be is not clear and there
has been no study that might cast light in this area.
rib
ut
Conclusion
References
1. S.B.Cunha, 2012. Comparison and analysis of
pipeline failure statistics. International Pipeline
Conference, Calgary, Canada, September, paper
IPC2012-90186.
2. Standards Australia, 2012. AS 2885.1-2012: Pipelines
– Gas and liquid petroleum, Part 1: Design and
construction.
3.P.Tuft and C.Bonar, 2009. Experience with the
Australian pipeline incident database. Australian
Pipeline Industry Association convention.
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20 – 23 October 2014
Berlin, Germany
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CALL FOR PAPERS NOW OPEN
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ABSTRACT SUBMISSION
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Proposals should include an abstract of no more than 200 words,
accompanied by the author’s complete contact information and affiliation,
and should be sent to:
John Tiratsoo, Director, Tiratsoo Technical
e-mail: jtiratsoo@gs-press.com
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SCHEDULE
Abstracts deadline: 1 July, 2014 | Final papers: 8 September, 2014
.
ORGANIZED BY
www.clarion.org
4th Quarter, 2013
321
Internal stress-corrosion cracking
in anthropogenic CO2 pipelines:
is it possible?
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by Daniel Sandana*1, Mike Dale1, Dr E A Charles2, and Dr Julia Race3
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1 MACAW Engineering, Newcastle upon Tyne, UK
2 School of Chemical Engineering and Advanced Materials, Newcastle University, Newcastle
upon Tyne, UK
3 School of Marine Science and Technology, Newcastle University, Newcastle upon Tyne, UK
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RANSPORTING ANTHROPOGENIC CO2 in pipelines, either in dense phase or gaseous phase, is an
essential component in the practical realisation of carbon capture and storage (CCS).Whichever phase is
considered, the likelihood and severity of internal degradation mechanisms arising from CO2 transportation
under normal operating conditions and under process upsets needs to be assessed.
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Whilst internal corrosion has been a focus of research in this area, the risk of stress-corrosion cracking
(SCC) has not been extensively investigated. This paper explores the level of risk posed by SCC in CO2
pipelines, and the gaps in current knowledge, together with a presentation of test results that investigate
the presence of SCC in simulated CO2 environments in the presence of impurities.
T
will need to be made to mitigate or prevent internal
corrosion. Over the past few years the development of
such CCS technology has generated increased research
and development activities to evaluate the integrity
risks related to the transport of anthropogenic CO2
in pipelines, i.e. in the presence of impurities such
as oxides of sulphur (SOx) or nitrogen (NOx).
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HE RELEASE OF GREENHOUSE gases – such
as carbon dioxide (CO2), methane, and nitrous
oxides – into the atmosphere due to human activities
has been associated with global warming and climate
change [1]. Carbon dioxide (CO2) represents a significant
component (~77%) of the total greenhouse emissions.
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To significantly cut the sustained increase of global
atmospheric CO2 emissions, one promising option that
has attracted interest from governments and industry
has been to capture the CO2 produced from fuel use
at major point sources and prevent it from reaching
the atmosphere by storing it. This has been referred
to as carbon capture and storage (CCS).
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Transporting anthropogenic CO2 in pipelines is
an essential component in the realization and
implementation of CCS. Transportation of dense CO2
has generally been the preferred economic solution, but
projects in the UK have also considered transportation
of gaseous CO2. Whichever option is selected, provision
This paper was presented at the 4th International Forum on the Transportation
of CO2 by Pipeline held in June, 2013, in Newcastle upon Tyne, UK, and
organized by the University of Newcastle, Tiratsoo Technical, and Clarion
Technical Conferences.
*Corresponding author’s contact details
tel: +44 191 215 4010
email: daniel.sandana@macawengineering.com
So far, whilst the corrosion research in this domain
has focused on identifying plausible corrosion rates
which may occur in these environments, the risk
of SCC has not been extensively investigated [2-7].
This needs to be assessed [8] in order to implement
the correct conditioning plant process and materials
design, and to set up suitable integrity-management
strategies for the infrastructures to ensure they fulfil
their required operating life [9].
CO2 transport and the presence of
impurities
There are currently over 3,500 km of operational,
long-distance, high-pressure CO2 pipelines. These
pipelines are mainly located in the USA and are mostly
transporting CO2 from natural sources for enhanced
oil recovery. CO2 from natural sources is relatively
pure, and this means that defining a specification for
such product is, in many respects, not too complex
a problem [10].
322
The Journal of Pipeline Engineering
IPCC Gas
>99.97
ENCAP
99.8
Oosterkamp et al
<99
IEAGHG – Comp1
CH4
H 2S
C2+
CO
O2
Ar
N2
0.01
0.01
NOx
SOx
<0.01
<0.01
<0.01
<0.01
0.003
0.001
0.003
0.021
0.021
0.002
0.001
0.01
0.001
0.01
Trace
0.17
<0.005
<0.001
99.93
0.001
0.015
0.002
0.001
IEAGHG – Comp2
99.92
0.001
0.015
0.045
0.002
0.001
IEAGHG – Comp3
99.81
0.002
0.03
0.045
0.002
0.001
0.01
Trace
0.045
H2
HCN
IPCC Coal
>96.39
0.01
0.01-0.6
0.03-0.4
0.03-0.6
>95.65
2
>0.01
0.04
1.3
ENCAP – CO2/H2S
97.8
0.035
0.01
Unknown
0.17
Unknown
0.05
0.03
Unknown
1.7
<0.0005
ENCAP – CO2+H2S
95.6
0.035
23
Unknown
0.17
Unknown
0.049
0.03
Unknown
1.7
<0.0005
<0.01
<0.4
Trace
>0.035
<3.4
<0.05
<0.6
97.95
0.01
0.01
0.04
0.03
0.9
IEAGHG – Rectisol
99.7
0.01
0.01
0.04
0.15
0.21
IPCC Coal
>95.79
IPCC Gas
>95.88
3.7
0.01
0.5
<0.01
91
Unknown
1.6
5.7
0.61
0.25
0.076
ENCAP – CO2+H2S
90
Unknown
1.6
5.6
0.6
0.24
Trace
>90
Trace
Unknown
1
With H2S
0.002
With H2S
Trace
Trace
Trace
1.5
<3
<5
<7
<0.25
<2.5
85
4.7
4.47
5.8
0.01
0.007
IEAGHG – Comp2
98
0.67
IEAGHG – Comp3
99.94
0.01
IEAGHG – Comp1
0.003
0.003
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<0.01
ENCAP – CO2/H2S
Oosterkamp et al
4.1
<0.05
<0.0005
<0.0005
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>95.6
CH2OH
0.8-2.0
1
Oosterkamp et al
NH3
Trace
IPCC Gas
IEAGHG – Selexol
COS
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CO2
>99.97
Trace
0.02
Trace
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Oxyfuel
Pre Combustion
Post Combustion
Comp (vol %)
IPCC Coal
0.59
0.71
0.01
0.007
0.01
0.01
0.01
0.007
Table 1. CO2 % vol. compositions from different capture technologies [10].
The Inter-governmental Panel for Climate Change (IPCC)1
considers that the main impurities in flue gases generated
from a post-combustion process by coal combustion will
include not only nitrogen (N2), oxygen (O2), and water,
but also SOx and NOx, hydrochloric and hydrofluoric acids
(HCl and HF), and mercury (Hg) [11]. In comparison, flue
gases from natural gas combustion processes typically contain
low levels of SOx and NOx and higher concentrations of
O2; HF can, however, also be present. Desulphurization
plant is generally necessary to prevent sulphur-poisoning
of the solvent in the CO2-absorption process.
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In contrast, the capture and transport of CO2 from
power plants means that different types and levels
of impurities are present in the CO2 stream, and
the purity of the CO2 becomes significantly affected.
The composition of such product via pipelines to
its destination is dependent on many parameters,
essentially:
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• the nature and chemical composition of the
fuel-gas source;
• the carbon-capture technology: currently there are
three main options – pre- or post-combustion,
or oxyfuel;
• the conditioning / treatment process: for
example, sulphur- or nitrogen-scrubbing plants to
limit hydrogen sulphide (H2S), SOx, and NOx;
• the use and type of drying plant to restrict
water content;
• the process used to separate CO2 from the
rest of the flue gases, including chemical or
physical absorption.
Additional local regulatory requirements and safety
considerations will bring further complication into
the definition of a universal specification for the
transport of anthropogenic CO2 [5, 10].
The types and levels of impurities as a function of the
fuel source and the carbon-capture technology source
used are provided in various publications. Table 1
gives a comparison of published CO2 compositions
from different capture technologies [10].
In the pre-combustion process, the captured CO2 may
contain very small levels of impurities such as N2, O2,
hydrogen (H2), methane (CH4), carbon monoxide (CO),
and sulphur compounds such as H2S. The levels of SOx
and NOx present in captured CO2 from pre-combustion
processes are insignificant. CO2 from pre-combustion
physical solvent scrubbing processes typically contains
about 1-2% H2 and CO, and traces of H2S and other
sulphur compounds.
In the oxy-fuel process, the CO2-rich stream commonly
contains O2, N2, argon (Ar), sulphur (S), and NOx.
The presence of impurities will have a significant impact
on the pipeline design and operation [10, 12, 13] but also
on the pipeline integrity in terms of internal corrosion
risks [2, 9].
1 IPCC Secretariat, c/o World Meteorological Organization, 7 bis, Avenue de
la Paix, CP 2300, CH-1211 Geneva 2, Switzerland.
4th Quarter, 2013
323
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Fig.2. Predicted bicarbonate concentrations in water vs CO2
partial pressure at various temperatures [4].
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Studies have investigated the chemistries of the aqueous
phase in the presence of pure CO2 in the view of
assessing corrosion of steel materials in high-pressure CO2
environments. The levels of carbonic acid, bicarbonates,
and carbonates in deionized water as function of the
CO2 partial pressure and temperature are identified in
Figs 1-3 [4]. The concentrations increase with increasing
pressure whilst decreasing with temperature. The pH value
also decreases with higher CO2 pressures, and will be
in the range of 3 to 3.4 above 50 bar. At high CO2
pressures, the pH values are so low that the formation
of a surface protective film may become difficult (i.e.
scale-free CO2 corrosion) due to the high solubility of
iron carbonate under these conditions. However, the
expected increased dissolution of iron due to higher
carbonic acid concentration and lower pH with pressure
may provide an increased source of ferrous ions which
might lead, over time, to iron carbonate precipitation even
at low pH, although probably not as a protective layer.
Fig.1. Predicted carbonic acid concentrations in water vs
CO2 partial pressure at various temperatures [4].
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It is generally accepted as a simplified rule that if no
aqueous phase condenses out from the CO2 stream, the
risk of internal corrosion in the transporting facilities
will remain low. The occurrence of aqueous-phase
condensation is dependent on the water solubility in
the CO2 fluid which is a function of the operating
pressure, operating temperature, and the types and levels
of impurities present. In pure CO2, the condensation
of water will occur when the water content is above
its solubility limit for the considered pressure and
temperature. The additional presence of impurities such
as SOx and NOx will, however, drive the precipitation
of acid aqueous phases at water contents much lower
than the water solubility limit in otherwise-pure CO2
streams. This is related to the formation of acids (whose
nature is dependent on the type of oxide compounds)
at a temperature much higher than the water dewpoint,
which is commonly referred to as the acid dewpoint[14].
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The presence of impurities and internal corrosion
considerations
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The chemistry of the aqueous phase in rich CO2
environments will be further modified by the presence of
impurities in the CO2 stream, and the magnitude of the
change will be dependent on the type and concentration
of the impurity, but also – and as important – on the
partitioning behaviour of these impurities between the
different CO2 and water phases. This partitioning will
be a function of the CO2 physical state, temperature,
pressure, and on the synergy effects between the different
mixture compounds. The presence of impurities of SOx
and NOx in the CO2 stream will further decrease the
pH of any aqueous phase formed, due to the formation
of acids such as sulphuric/sulphurous acids or nitric/
nitrous acids, which will aggravate further general and
localized corrosion in these environments and render
any protective film formation more difficult. Ayello et
Fig.3. Predicted carbonate concentrations in water vs CO2
partial pressure at various temperatures [4].
324
The Journal of Pipeline Engineering
Stress to cause cracking, MPa
370
16
320
12
8
270
4
220
0
0.2
0.4
0.6
0.8
1
1.2
Carbon monoxide partial pressure, bar
2.6
0
Fig.4. Effect of
carbon monoxide
partial pressure on
minimum stress
to initiate cracking
and on crackgrowth rate (total
pressure 7.9 bar
(0.79 MPa), +100
mV from FCP) [18].
However, in the case of a delay in response to process
upsets or in the case of a shut-down (pipeline shut-in or
total depressurization), situations could exist where free
water may be present over long periods of time in the
pipeline. Indeed, during long shut-downs, water-removal
operations will be required and experience from the oil
and gas industry has indicated that this may take weeks.
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al. suggested that sulphur dioxide (SO2) can drop the
pH by a magnitude of 1 unit [7]. General and localized
corrosion rates in the presence of free water in rich
CO2 environments and in the presence of impurities
are expected to be significant; the importance of water
content and the effect of impurities such as SOx and
NOx on general and localized (pitting) corrosion risks
in rich CO2 streams have been well discussed elsewhere,
and are beyond the scope of this paper [2, 4, 5, 6,
7, 9, 15].
1.4
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20
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Stress to cause cracking, MPa
420
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Crack Growth Rate at 448 MPa
Crack growth rate, mm/sec x 10 -7
470
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A mitigation strategy to prevent the realization of
internal corrosion in CO2 transport pipelines would be
to identify (from corrosion testing) the levels of water
and impurities acceptable in terms of pipeline internal
integrity prior to the pipeline commissioning, and then
to ensure suitable physical and chemical processes have
been put in place upstream of operating CO2 pipelines
such that the conveyed product is in accordance to
specification. However, it should be recognized that
despite all the precautions taken at the process design
stage to guarantee acceptable water and impurity contents
in CO2, upset conditions in the CO2 dehydration and
conditioning process are still a possibility in complex
pipeline systems, especially over decades of operating
life. Under such scenario, free water is expected at the
6 o’clock position of the pipeline transportation system
in presence of significant levels of impurities, typically as
high as concentrations in flue gases. Hence the resulting
risk of internal corrosion from such excursions should
not be excluded. One may argue that if a continuous
flow of dry CO2 is present following an event of water
incursion, the water may rapidly dissolve in the stream
minimizing any internal damage to the pipeline [6, 9].
The following sections will aim at understanding whether
SCC should be considered as a potential internal corrosion
risk under such extreme, but realistic, operating scenarios,
when water and high levels of impurities may be present
in the pipeline during its operating life. As part of the
authors’ experience in other systems related to the oil
and gas industry, the review will consider the following
impurities: CO, H2S, NOx [8].
The presence of impurities in CO2:
why SCC should be considered
Stress-corrosion cracking leads to the sudden and
catastrophic failure of alloys as a result of materials
cracking in a corrosive environment. Three key parameters
are essential for the initiation and sustained propagation
of SCC:
• a material susceptible to SCC;
• an environment in which this material is susceptible
to SCC;
• a tensile stress (residual or applied) whose magnitude
is sufficient to initiate and propagate cracking.
Should one of these parameters not be present, SCC
will not be produced.
4th Quarter, 2013
325
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H2S and sour cracking
Hydrogen sulphide is a significant impurity in CO2
captured from pre-combustion processes, but can be
also present in streams generated from post-combustion
and oxy-fuel technologies.
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Carbon monoxide is a significant impurity in CO2
captured from pre-combustion processes [1]. In the 1970s
cracking of carbon steels was observed in environments
constituted of wet mixtures of CO2 and CO gases, such
as those present in coal-processing plants, and town-gas
manufacture, transport, and storage systems.
Under upset dehydration conditions, there is a potential
risk of CO2-CO-H2O SCC in pipelines transporting
CO2 from pre-combustion capture processes. There is a
fundamental requirement to investigate the susceptibility
of pipeline steels to CO2-CO-H2O SCC at the high
CO2 partial pressures typical of gaseous and dense
CO2 pipelines.
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Carbon monoxide SCC in the CO2-CO-H2O system
• The additional presence of oxygen will increase
the susceptibility to SCC in this system.
• Crack-growth rates of 10-6 mm/s were reported.
• The mechanism of SCC for the CO2-CO-H2O
system can be classed under the ‘strain-generated
active path’ model. This is the result of the
formation of a mono-molecular CO film on
the surface of the carbon steel and its rupture
under stress.
• Most of the experimental data are limited to low
partial pressures of CO2 (<20 bar (<2 MPa)).
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It is generally considered that the presence of CO2 alone
(in the presence or not of free water) is not sufficient
to drive initiation and propagation of SCC. Hudgins
et al. [17] nevertheless indicate that cracking may be
generated on high-strength carbon steel in high-pressure
CO2 environments under extreme stress conditions in
relatively long exposure times. At 20 bar CO2, failures
were produced within exposures as low as 22 hrs on
steel materials with hardnesses of 34Rc and deformation
levels of 115%; the production of cracks was associated
with the potential leaching of sulphur from the steel
materials. Scenarios under which such high stresses
may arise, such as from geological ground motion or
at localized corrosion features, should be considered.
The additional presence of other impurities in the CCS
stream may further increase the likelihood of SCC in
CO2-H2O environments.
The presence of H2S can lead to different types
of sour cracking, mainly sulphide-stress-corrosion
cracking (SSCC) and hydrogen-induced cracking
(HIC). These threats and their respective mitigation
requirements have been well documented in the
oil and gas industry. In particular, the standard
NACE2 MR0175/ISO3 15156 has been used to
mitigate the risk of sour cracking [20]. This standard
is based on oil and gas industry experience and
testing for hydrocarbon systems (i.e. CO2 is present
as an impurity). Although this document is a starting
point to potentially decrease the susceptibility of
sour cracking in CO2 pipelines, there is a
fundamental requirement to obtain data at the
high partial pressures of CO2 in presence of H2S
to understand in which conditions of H2S partial
pressure, pH, temperature, SSCC, or HIC can be
realized in CO2 pipelines.
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Microscopic examination of the failures indicated fine
transgranular cracks initiated from the internal surface of
the vessel containing the gas mixture. The investigations
also showed that cracking initiated at sites subject to
tensile stress typically generated from the high pressure
of the contained gas. The occurrence of such cracking
in practical engineering situations worldwide, particularly
in town-gas high-pressure pipelines, meant that great
interest was generated and various research studies were
conducted, mainly by Brown et al. and Kowaka and
Nagata [18, 19]. Kowaka and Nagata were the first to
indicate that transgranular SCC of steel is possible in
the CO2-CO-H2O system. The current understanding
for the occurrence of CO2-CO-H2O SCC is summarised
[18, 19]:
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• The presence of water is critical for the incidence
of cracking.
• The presence of CO in CO2-H2O systems
is critical for the occurrence of transgranular
cracking in carbon steels.
• An increase of the CO activity in CO2-H2O
systems increases the susceptibility to cracking (see
Fig.4 [18]), i.e. the crack growth rate is greater,
and the minimum initial stress to be applied for
SCC occurrence is lower. At high CO activity,
fine branched cracks are formed during crack
propagation, whilst at low CO activities voids are
created below the metal surface. It is possible to
generate cracking under freely corroding conditions
at high CO partial pressures.
If a CO2 pipeline is expected to see significant levels
of H2S during service, sour-resistant steels will need
to be considered to prevent catastrophic failure of the
pipeline which could occur within days, or even hours,
under the most favourable conditions. Compliance to
maximum hardness will have to be specified for the
parent and weld materials.
2 NACE, 1440 South Creek Drive, Houston, TX 77084-4906, USA.
3 ISO Central Secretariat, 1, ch. de la Voie-Creuse, CP 56, CH-1211 Geneva
20, Switzerland.
The Journal of Pipeline Engineering
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326
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Bicarbonate and carbonate SCC, and the effect of
impurities
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The excessive presence of water in rich CO2 environments
will drive the formation of an acid aqueous phase in
which dissolved CO2, bicarbonates, and carbonates will
be in equilibrium. The concentrations of these species
as a function of the partial pressure are illustrated in
Figs 1-3 [4].
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Aqueous concentrated carbonate-bicarbonate solution
environments are known to result in intergranular SCC
of low-alloyed steel pipeline materials. This mechanism
is generally referred to as high-pH SCC since it readily
occurs in solutions with a pH of 9-10, conditions under
which iron carbonate films will precipitate on steel.
The occurrence of such cracking has only occurred on
operational pipelines as an external mechanism due to
the importance of potential polarization to generate
SCC initiation and growth. The critical potential
for SCC is related to the steel surface active-passive
transition as a result of iron carbonate formation. This
potential is dependent on the actual pH environment
and temperature of the pipe.
This mechanism has been extensively studied:
• The critical potential for SCC is in the range
of -650 to -750 mV (CSE); this potential can
be present on operating pipelines where the
Fig.5.The effect of bicarbonate
levels on the average crack
velocity for low-carbon steel in
1 M Na2CO3 solution [21].
100-mV shift criterion is used, where the CP
is monitored by ‘on’ potentials, or where there
is some degree of CP shielding, for example in
areas of disbonded coating or from a porous
coating.
• In the bicarbonate-carbonate system, the
susceptibility to cracking decreases with decreasing
concentration of bicarbonate. This is illustrated
in Fig.5 [21].
• The susceptibility to cracking is maximum at
temperatures of 75-80ºC, and diminishes with
decreasing temperature. The risk of cracking is
usually considered to be low at temperatures
lower than 40ºC, but it is still possible at
ambient temperatures, as illustrated in Fig.6 [21].
The risk of bicarbonate/carbonate SCC in CO2
pipelines in the presence of free liquid water may in
the first instance be discarded due to:
• Non-existence of surface electrochemical
polarization to drive the internal pipeline
surface steel potential in the critical range for
SCC initiation.
• A low pH (< 4) which will mitigate the formation
of protective iron carbonate.
• Relatively low concentrations of bicarbonates
(< 0.001M for CO2 partial pressures < 100
bar (<10 MPa) – see Fig.2) and carbonates in
free water.
327
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4th Quarter, 2013
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Fig.6.The effect of temperature
on the average crack velocity
for low-carbon steel in 1 M
NaHCO3 + 0.75 M Na2CO3
solution [21].
Nitrate SCC
Nitrates can cause SCC of carbon steel materials on
their own. The susceptibility to cracking increases with
the concentration of nitrates in solution, and with the
temperature. The occurrence of SCC becomes significant
at temperatures above 70ºC due to the rapid formation
of a magnetite film.
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However, other operational considerations should
be given to the impact of events/conditions in
generating an SCC mechanism in CO2 pipelines,
whose characteristics can be similar to bicarbonate/
carbonate SCC:
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• Following significant dehydration upsets, impact
of water evaporation due to re-establishment of
dry-gas operations in concentrating the levels of
bicarbonates/carbonates, and impurities, such as
nitrates and sulphates in existing water pools.
• The solution has initially a low pH due to the
presence of acids; over time as the solution
becomes saturated with bicarbonates/carbonates
and corrosion products, the pH of the solution
may increase to become alkaline.
• Impact of chemicals (such as amine, sulphite)
and by-products (such as ammonia) carry-over
from the capture and conditioning process
into the pipeline to generate more alkaline
conditions in the aqueous phases present in
a CO2 pipeline.
• Impact of impurities such as nitrates and
sulphates to shift the free corrosion potential
into the critical range for SCC and increase
the susceptibility to SCC under freely corroding
conditions.
• The presence of scales such as iron sulphide
may shift the potential in the critical range
of potentials for SCC.
It is plausible that occurrences of concentrated solutions
of nitrates are present over the pipeline operating life
as a result of low water condensation or water pool
evaporation following process upset. Considering the
spectrum of operating temperatures of 40ºC at the pipeline
inlet (downstream of compression after-cooler unit) to
ambient temperature (< 20ºC), the risk of nitrate SCC
is considered to be low. However, the nitrate interaction
with bicarbonate-carbonate environments may increase the
susceptibility to cracking at relatively low temperatures,
< 40ºC, as discussed above, in naturally corroding conditions.
Nitrate SCC should be considered upstream of the
pipeline inlet.
Experimental testing
SCC in environments containing concentrated levels of
bicarbonates and carbonates as a result of the evaporation
of a pool of water present in a CO2 pipeline following
an upstream process upset.
328
The Journal of Pipeline Engineering
Elements
C
Si
Mn
P
S
Cr
Mo
Ni
Al
Cu
Nb+Ti+V
%wt
0.064
0.309
1.96
0.010
<0.003
0.217
<0.001
0.005
0.029
0.009
0.132
Table 2. Materials chemistry of tested X-80 pipeline steel.
Sodium Nitrate or Sulphite addition (%wt)
Temperature (ºC)
0.25M NaHCO3+0.125M Na2CO3
0, 10
23, 40, 75
0.5M NaHCO3+0.25M Na2CO3
0, 10
0.70M NaHCO3+ 0.35M Na2CO3
0, 10
1M NaHCO3+0.5M Na2CO3
0, 10
23, 40, 75
23, 40, 75
Potentials (mV SCE)
0.25M NaHCO3+0.125M Na2CO3
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23, 40, 75
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Table 3. Test environments for electrochemistry.
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Bicarbonate/Carbonate solutions
-755, -740, -725, -710, -695
-720, -710, -690, -650
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0.25M NaHCO3+0.125M Na2CO3 + 10 %wt NaNO3
0.25M NaHCO3 + 0.125M Na2CO3 + 10% Na2SO3
-820, -790, -770, -750, -730
0.70M NaHCO3 + 0.35M Na2CO3
-710, -685, -675, -655
0.70M NaHCO3 + 0.35M Na2CO3 + 10% Na2SO3
Table 4.Test environments for SSRT, 75°C.
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The experimental work was conducted using pipeline
steel of API4 5L X-80 grade. The materials composition
(%wt) of the steel is given in Table 2.
Electrochemical testing
-700, -670, -650, -628, -590
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0.70M NaHCO3 + 0.35M Na2CO3 + 10% NaNO3
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Potentiodynamic testing of the X-80 steel materials
was carried out to identify:
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• If this system is potentially susceptible to SCC,
i.e. if the materials shows passivation at anodic
potentials.
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• Within which range of electrode potentials,
SCC can be produced. The critical region of
potentials for SCC can be determined from any
significant difference in current flow between
anodic potentiodynamic polarization curves
plotted at a slow and a fast sweep rate.
The electrochemical measurements were conducted in
a three-electrode cell using an automated potentiostat.
Potentiodynamic testing was carried out at two potential
sweep rates, of 0.2 mV/s and 10 mV/s. Each test was
conducted in a fresh test solution of approximately 600 ml.
The test solutions are summarized in Table 3. The molar
4 API, 1220 L Street, NW, Washington, DC 20005-4070, USA.
-730. -720, -710, -690
concentration ratio of sodium bicarbonate to sodium
carbonate was maintained constant at 2. Addition of
10%wt sodium nitrate (NaNO3) or sodium sulphite
(Na2SO3) to the carbonate/bicarbonate solutions was
made to assess effect of impurity. Each solution was
tested at 23ºC, 40ºC, and 75ºC to simulate the range
of temperatures possible in service.
All the solutions had pH values between 8.5 and 9.5,
depending on the composition and the temperature.
The addition of nitrate or sulphite to bicarbonate/
carbonate solutions resulted in a slight acidification of
the solution; the most significant impact on pH was
from the sulphite addition
Slow-strain-rate testing
The X-80 tensile test specimens were produced from
the pipe section. The specimens were polished over
their gauge length to a 1200 grit-finish. After polishing,
the specimens were cleaned with methanol, swept with
cotton wool, and air dried.
A potential was applied to the specimen via a potentiostat;
the reference electrode was a saturated calomel electrode
coupled to the test solution via a salt bridge, and
the counter electrode was a platinum wire directly in
contact with the test environment. The temperature
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Fig.7. Polarization curves at slow and
fast sweep rates for 0.70M NaHCO3
+ 0.35M Na2CO3 + 10%wt
NaNO3 at various temperatures.
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Fig.8. Polarization curves at slow and
fast sweep rates for 0.25M NaHCO3
+ 0.125M Na2CO3 + 10%wt
NaNO3 at various temperatures.
then prepared and hot mounted, and the cross-section
was observed under an optical microscope.
The specimen fracture surfaces were cleaned in Clarks
Solution. The specimen surface at proximity of the
fracture was then observed using a scanning-electron
microscope (SEM) to identify the presence of any stresscorrosion cracks. A cross-section of the specimen tip was
Potentiodynamic curves
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of the solution was controlled via a thermostat. The
strain rate during testing was 1.4 x 10-6 sec-1. The test
ended when fracture of the specimen occurred. Table 4
shows the conditions at 75°C at SSRT was conducted.
Following SSRT, the reduction of area of the specimen
in the necking region was measured.
Results
Electrochemical data
The polarization curves at slow (0.2 mV/s) and fast
sweep rates (10 mV/s) for 0.70 M NaHCO3 + 0.35M
Na2CO3 + 10%wt NaNO3, and for 0.25 M NaHCO3
The Journal of Pipeline Engineering
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Potential, mV SCE
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Fig.9. Polarization curves at slow and
fast sweep rates for 0.75M NaHCO3
+ 0.35M Na2CO3 + 10%wt
Na2SO3 at various temperatures.
+ 0.125M Na2CO3 + 10%wt NaNO3, are illustrated
in Figs 7 and 8, respectively. The anodic curve
shows an active-passive transition at all temperatures,
suggesting the formation of a protective surface film
in carbonate/bicarbonate environments in the presence
of nitrates. The anodic current difference between the
active and the passive state is lower as the temperature
is decreased; this suggests that the surface film is less
protective with the drop of temperature. The presence
of an active-transition region is often indicative of the
possible occurrence of SCC in low-alloy steels, and
Fig.10. Polarization curves at slow and
fast sweep rates for 0.25M NaHCO3
+ 0.125M Na2CO3 + 10%wt
Na2SO3 at various temperatures.
SCC may also be generated in lower bicarbonate/
carbonate systems with nitrates (Fig.8).
An active-transition region was also observed with the
addition of sulphites, as illustrated in Figs 9 and 10.
Free-corrosion potential, Ecorr
The effect of nitrate and sulphite in various bicarbonate/
carbonate solutions on the free-corrosion potential
response (Ecorr) is illustrated at 23˚C, 40˚C, and 75˚C in
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Fig.11. Effect of nitrate and sulphite
on the free corrosion potential Ecorr in
bicarbonate and carbonate solutions at
23˚C.
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Fig.12. Effect of nitrate and sulphite
on the free corrosion potential Ecorr in
bicarbonate and carbonate solutions at
40˚C.
Figs 11-13, respectively. The addition of nitrate to
bicarbonate or carbonate environments shifts the value of
Ecorr to more anodic potentials for all the test temperatures
used, suggesting the system becomes nobler with the
addition of nitrates.
This also suggests that in the presence of nitrates the
electrode potential will shift towards the active-passive steel
transition in systems containing concentrated bicarbonates
and carbonates. This may indicate that the susceptibility
to cracking in concentrated bicarbonates and carbonates
in the presence of nitrates under naturally occurring
conditions (i.e. at Ecorr) or under very low polarization
(such as resulting from the presence of semi-conductive
scales cathodic to the steel) may be increased.
The addition of sulphites to bicarbonate or carbonate
environments shifts the value of Ecorr to more cathodic
potentials for all the test temperatures used, suggesting the
system becomes more corrosive with the addition of sulphites.
This is probably related to the surface films being less
stable or protective in the presence of sulphur compounds.
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Fig.14. Intergranular
SCC on X-80 gauge
surface: 0.70M
NaHCO3+0.35M
Na2CO3+10%wt
NaNO3, 75˚C, -650
mV SCE.
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Fig.13. Effect of nitrate and sulphite
on the free corrosion potential Ecorr in
bicarbonate and carbonate solutions at
75˚C.
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It is noted that the free-corrosion potentials are taken
from the potentiodynamic curves, and there will be
an over-potential related to the dynamic nature of the
test. The free-corrosion potential values obtained under
long steady exposure conditions will be slightly lower.
Fig.15. Intergranular
SCC of X-80
in 0.70M
NaHCO3+0.35M
Na2CO3+10%wt
NaNO3, 75˚C, -650
mV SCE, x100.
lower concentrated bicarbonate and carbonate environments
in the presence of nitrates, i.e. 0.50M NaHCO3 + 0.25M
Na2CO3 + 10%wt NaNO3, -670 mV SCE, at 75°C;
this is illustrated in Fig.16.
SSRT
Intergranular stress-corrosion cracking was also produced
in the presence of sulphites (see Fig.17).
Multiple intergranular cracking was produced along the
gauge of X-80 in 0.70M NaHCO3 + 0.35M Na2CO3 +
10%wt NaNO3, -650 mV SCE, at 75°C, as illustrated in
Figs 14 and 15. Significant cracking was still produced in
Initial results associated with reduction of area measurements
for tests at 75°C on failed specimens (Fig.18) suggests
that nitrates do not significantly affect the maximum
cracking susceptibility other than that obtained in a pure
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Fig.16. Intergranular SCC of X-80
in 0.50M NaHCO3+0.25M
Na2CO3+10%wt NaNO3, 75˚C,
-670 mV SCE, x400.
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Fig.17. Intergranular
SCC on X-80 gauge
surface, 0.70M
NaHCO3+0.35M
Na2CO3+10%wt
Na2SO3, 75˚C, -650
mV SCE.
Conclusions
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carbonate or bicarbonate system. Sulphites, however, appear
to decrease the susceptibility to stress-corrosion cracking,
especially in the higher concentrated bicarbonate and
carbonate systems. This may be associated with sulphites
hindering the formation of protective surface films on
the steel and hence enhancing general corrosion or the
formation of shallow pits.
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• Internal stress-corrosion mechanisms should be
considered at the process design stage, i.e. CO2
specification definition, and during the operating
lifecycle of the CO2 transporting pipeline system.
• Stress-corrosion cracking in the CO2-H2O
system may occur at high partial pressures of
CO2, typically above 20 bar, under severe stress
conditions. The presence of sulphur in the steel
may increase susceptibility. Scenarios under which
high stresses can arise, such as from geological
ground motion or localized corrosion features,
should be considered.
• CO and H2S can result in internal SCC in
CO2 pipelines depending on the fuel source
and the CO2-capture technology used. Further
experimental work is required to quantitatively
assess the crack susceptibility at high CO2 partial
pressures (>20 bar).
• Consideration should be given to the impact
of extreme operational events/conditions (i.e.
upsets) which can generate a SCC mechanism
in CO2 pipelines, whose characteristics can
be similar to bicarbonate/carbonate SCC due
to the presence of impurities such as nitrates.
»» Intergranular SCC was produced in bicarbonate
and carbonate environments in the presence
of nitrates and in the presence of sulphites.
»» In the presence of nitrates, the Ecorr shifts
towards the active-passive steel transition in
systems containing concentrated bicarbonates
and carbonates. The susceptibility to cracking in
concentrated bicarbonates and carbonates in the
presence of nitrates under naturally occurring
conditions or under very low polarization
(for example resulting from the presence of
semi-conductive scales cathodic to the steel)
may be increased.
»» The presence of nitrates does not appear
to affect significantly the cracking susceptibility
compared with a pure carbonate or
bicarbonate system.
»» The presence of sulphites appears to decrease
the cracking susceptibility compared with a pure
carbonate and bicarbonate system. This may be
associated with sulphur compounds hindering
the formation of protective surface films.
The Journal of Pipeline Engineering
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References
11.IPCC, 2005. Carbon dioxide capture and storage.
Special Report, Intergovernmental Panel on Climate
Change (IPCC).
12.P.Seevam et al., 2008. Transporting the new generation
of CO2 for carbon capture and storage: the impact of
impurities on supercritical CO2pipelines. IPC, paper
64063.
13.P.Seevam et al., 2010. Capturing carbon dioxide: the
feasibility of re-using existing pipeline infrastructure
to transport anthropogenic CO2. IPC, paper
2010-31564.
14.Kear. Low-temperature corrosion by flue gas condensates
Part 1.
15.Farelas et al., 2012. Effects of CO2 phase change,
SO2 content and flow on the corrosion of CO2
transmission pipeline steel. Corrosion/2012, paper
C2012-01322, NACE International.
16.R.N.Parkins, 1972. Stress corrosion spectrum. British
Corrosion Journal, 7, pp 15–28.
17.Hudgins et al., 1966. Hydrogen sulfide cracking
of carbon and alloy steels. Corrosion, 22, pp 238-251, 56.
18.Brown et al., 1973. Electrochemical investigation
of SCC of plain carbon steel in carbon dioxidecarbon monoxide-water system. Corrosion-NACE, 5,
pp 686-695.
19.M.Kowaka et al., 1976. SCC of mild and low steels
in CO2-CO-H2O environments. Corrosion-NACE,
32, pp 395-401, October.
20.NACE, 2009. MR0175/ISO 15156: Petroleum and
natural gas industries – materials for use in H2S
environments in oil and gas production. NACE
Standard.
21.R.N.Parkins and S.Zhou, 1997. SCC of C-Mn steel in
CO2/HCO3-/CO32, I: Stress corrosion data. Corrosion
Science, 39, 1, pp 159-173.
Sa
m
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-n
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1. IPCC, 2007. Climate change 2007: Synthesis report.
Intergovernmental Panel on Climate Change, Adopted
by the IPCC Plenary XXVII, November.
2. A.Dugstad et al., 2012. Internal corrosion in dense
phase CO2 transport pipelines - state of the art and
the need for further R&D. Corrosion/2012, paper
C2012-01452, NACE International.
3. Seiersten, 2001. Materials selection for separation,
transportation and disposal of CO2. Corrosion/2001,
paper 01042, Houston, TX, NACE International.
4. Choi et al., 2010. Determining the corrosive potential
of CO2 transport pipeline in high pCO2–water
environments. Int. J. of Greenhouse Gas Control.
5. A.Dugstad et al., 2011. Corrosion of transport pipelines
for CO2 – effect of water ingress. Energy Procedia, 4,
3063–3070.
6.Zhang et al., 2011. Water effect on steel corrosion
under supercritical CO2. Corrosion/2011, paper 11378,
NACE International.
7.Ayello et al., 2010. Effect of impurities on corrosion
of carbon steel in supercritical CO2. Corrosion/2010,
paper 10193, NACE International.
8. D. Sandana et al., 2013. Transport of gaseous and
dense carbon dioxide in pipelines: is there an internal
stress corrosion cracking risk? Corrosion/2013, paper
C2013-02516, NACE International.
9.D.Sandana et al., 2012. Transport of gaseous and
dense carbon dioxide in pipelines: is there an internal
corrosion risk? J. of Pipeline Engineering, 11, 3, pp 229238.
10.J.Race, 2012. Towards a CO2 pipeline specification:
defining tolerance limits for impurities. J. of Pipeline
Engineering, 11, 3, pp 173-190.
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Fig. 18. Reduction of area of X-80
steel in different bicarbonate and
carbonate environments in the
presence of nitrates and sulphites at
75°C.
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335
Earthquakes and the Indian
pipeline industry
by Indranil Guha*1, Beau Whitney1, Raúl Flores-Berrones2, Aditya
Barsainya3, and Gaurav Arya4
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1 Centre for Offshore Foundation Systems, School of Civil and Resource Engineering, University
of Western Australia, Crawley, WA, Australia
2 Mexican Institute of Water Technology, Jiutepec, Mexico
3 Samit Spectrum Eit Pvt Ltd, Gurgaon, India
4 Siti Energy Ltd, Moradabad, UP, India
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IPELINES ARE THE SAFEST, most reliable, affordable, and efficient means for the transportation of water
and other commercial fluids such as oil and gas. In last few decades the importance of the pipeline
transportation system has increased due to its extensive use in the oil and gas industry. Pipelines pass
through myriad geologic environments and some are subjected to earthquake hazards. Historically, the most
catastrophic damages are the once resulting from faulting, seismic shaking, and liquefaction. Among others,
the San Francisco (1906); Meckering, Australia (1968); Mexico City (1985); Loma Prieta, California (1989);
Northridge, California (1994); Kobe, Japan (1995); Bhuj, India (2001); Denali, Alaska (2003); and Sumatra
(2004) earthquakes all triggered damages to critical pipeline routes. Ruptures or severe distortions of the
pipeline are often associated with landslides, liquefaction, loss of support, fault surface rupture, or differential
motion at abrupt interfaces between rock and soil.
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The performance of buried and above-ground pipeline structures subjected to seismic hazards has become
an important subject of study. Approximately 2,000,000 km of pipelines has been laid worldwide. In India
there are already more than 23,000 km of oil and gas pipelines that have been laid through many geographical
areas and geologic conditions. More pipelines are slated to be laid in the future. There are plans for crossborder pipelines from Afghanistan; the route is in areas of high seismicity.There is also plan to construct an
offshore pipeline over 1300 km of highly variable geologic conditions between the Middle East and India
across the Indus River delta.The performance of buried and above-ground pipeline structures subjected to
ground-surface rupture, soil liquefaction, and other seismic hazards is critical for engineers to understand
in the Indian context.
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Seismic design and engineering of pipelines has advanced significantly in last few decades; still, little has been
accomplished to address the vulnerability of buried pipelines to seismic hazards. With new and proposed
cross-country pipelines in India, it is becoming more important to understand the effects of seismic hazards
(such as shaking, liquefaction, fault-surface rupture) on buried pipelines.
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IPELINES ARE THE SAFEST, most economic
and efficient means for the transportation of
water and other commercial fluids such as oil and
gas and, nowadays, minerals in the form of slurry
[1]. The designation of pipeline systems as ‘lifelines’
signifies that their operation is essential in maintaining
public safety and critical services (for example, power,
water, and sewer) at all times, even immediately after
natural disasters. It is a linear system which traverses
a large geographical area, and soil conditions thus, is
*Corresponding author’s contact details:
email: guha@civil.uwa.edu.au
susceptible to a wide variety of geohazards. Ruptures
or severe distortions of the pipeline are most often
associated with relative motion arising from earthquake
movements, landslides, liquefaction, or differential
motion at abrupt interfaces between rock and sediment.
Historically the most catastrophic damage results from
ground rupture, seismic shaking, and liquefaction.
The performance of buried and above-ground pipeline
structures subjected to seismic hazards has become an
important subject of study. This paper will give an
over view of pipeline damage along with its failure
modes during past earthquakes, and also the seismic
vulnerability of Indian pipeline industry.
The Journal of Pipeline Engineering
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(a)
(b)
Fig.1. (a) Generalized tectonic map of India and surrounding countries [2]; (b) Major earthquakes in India [3].
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The Indian subcontinent is one of the most seismically
active zones in the world. A deterministic seismic hazard
map is shown in Fig.1a [2]; the Indian subcontinent
has undergone catastrophic earthquakes claiming huge
loss of life and property, and socio-economic losses, and
a few of the major earthquakes locations are shown
in Fig.1b [3], and these have happened due to active
seismic/tectonic activities in Himalayan-Hindukush region
spread over Afghanistan in the west to Bangladesh in
the east across Pakistan, India, Nepal, and Bhutan. This
is one of the earth’s youngest mountain range and is
still isostatically imbalanced and geodynamically active
due to the movement of the Eurasian Plate towards
the north and the Indian Plate towards north-east. Due
to tectonic movement of both the Plates, stresses are
generated; when the stresses reach a critical stage, they
are released in the form of earthquakes.
Consequently, the Indian subcontinental region is
always at threat of earthquakes in present or future
scenarios. The Indian landform has been classified into
five different zones from Zone I (lowest) to Zone V
(highest) in relation to seismic activity, and geographical
statistics clearly show that 54% of the land is vulnerable
to earthquakes. Figure 2 is a map showing that the
north east of the country and a portion of Gujarat lie
under Zone V, and major proportion of the country
lies in Zone III. Consequently, any major or minor
earthquake may create havoc, with huge losses of life
and property due to high population densities and
developed infrastructure.
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History of pipeline damage during
earthquake events
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Indian seismic hazards
In 1971 the San Fernando Earthquake resulted in direct
losses to pipeline systems by damaging a 1.24-m diameter
water pipeline at nine bends and welded joints. The
ductile steel pipelines were able to withstand ground
shaking but could not withstand ground deformation
associated with fault rupture and lateral spreading [4,
5]. The 1983 Coalinga Earthquake caused a number
of breaks in a natural gas line, and several pipeline
failures occurred in oil drilling and processing facilities.
In 1987, after the Whittier Narrows Earthquake, the
Southern California Gas Co reported 1411 gas leaks
that were directly caused by the earthquake. In 1989
the Loma Prieta Earthquake, with a magnitude of 6.9
Mw (Richter scale, moment magnitude), also caused
failure of numerous water pipelines, and broken water
pipelines occurred at the Ford automobile plant as a
result of liquefaction and excessive soil pressures. During
the Tennent Creek earthquakes of 1988 in Australia,
three powerful earthquakes ranging from 6.3 to 6.7
ML (Richter scale, local magnitude) shook the region.
The main infrastructure damage was the severe warping
of a major natural gas pipeline as ground ruptures
occurred along a 35-km long fault scarp (with up to 2
m of vertical displacement) due to the ductile failure
of mild steel pipeline materials [6] as shown in Fig.3b.
On 28 December, 1989, an earthquake of magnitude
5.6 in the Newcastle region of Australia caused 22
water-main breaks in 150-mm diameter and smaller
pipes, mainly due to the seismic shaking. A few cast
iron pipes were found to have circumferential cracking,
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Fig.2. Seismic zone map of India [22].
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and also areas of localised corrosion appeared to have
been shaken by the shockwaves from the earthquake
and pieces blown out of the pipes [7].
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The 1994 Northridge Earthquake caused about 1400
pipeline breaks in the San Fernando Valley area in
the USA, and leaking gas ignited at several locations.
Some broken water and gas lines were found to
have experienced between 152.4 and 304.8 mm of
separation (Fig.4). The area experienced widespread
ground cracking and differential settlements. In the
1999 Kocaeli, Turkey, Earthquake (of magnitude 7.4
Mw) substantial water supply damage occurred in many
cities [8]. For example, the entire water distribution
system of Adapazari was damaged. A 2.4-m diameter
steel water pipe was damaged at Kullar due to a rightlateral strike-slip motion along the fault, and a 2.2-m
diameter butt-welded steel raw water pipeline crossing
the Sapanca Segment of the North Anatolian fault
and was damaged at the fault crossing. Damage was
observed at three locations where a small surface leak
was observed in the pipe at a point near the fault
crossing; a significant leak occurred at yet another point;
and a minor leak had happened at a bend in the pipe.
In 1999, the Chi Chi Earthquake in Taiwan damaged
many buried water and gas pipelines at many sites. It
was reported that buried gas pipelines underwent bending
deformation due to ground displacement along a reverse
fault near the Wushi Bridge about 10 km south of
Taichung. The risk to pipelines from permanent ground
(a)
(b)
Fig.3. (a) Brittle failure of water pipe during the Meckering
Earthquake (Source: AEES Gallery); (b) Damage to the natural
gas pipeline during the Tennant Creek Earthquake [6].
deformation (PGD) received particular attention from
the engineering community after the 1999 Kocaeli and
Chi-Chi earthquakes [9), following faults displacing the
ground surface by 2 and 9 m, respectively, and causing
damage to water and gas pipelines. These kinds of events
are likely to cause permanent damage to pipelines that
cross the fault line. The response of buried pipelines
to earthquake-induced PGD has received attention by
the pipeline engineering community in the past decade
(for example, Ref.10).
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Fig.4. Pipeline damage during the Northridge Earthquake.
(b)
(a)
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Fig.5. Schematics of fault-pipeline interaction: (a) strike-slip fault; (b) normal slip fault [13].
Failure modes of pipelines during
earthquakes
Approximately 3% of natural gas pipelines failures
in the USA are due to ground movement during
seismic events [11]. Soil movement can induce
stresses and strains in the pipe walls, the magnitude
of which depends on the magnitude and direction
of soil movement, the soil shear strength, the
friction between the soil and the pipe, the depth
of burial, and the pipe properties. Governing
strains induced in the pipeline may be tensile or
compressive depending on the type of motion along
the underlying fault (or seismically triggered failure
surface) and the angle at which the pipeline crosses.
Seismic hazards have been classified as being either
permanent ground deformation (PGD) or seismicwave-propagation hazards [12]: PGD may be due to
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(b)
(b)
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Fig.6. Schematics of landslide-pipeline interaction: (a) longitudinal; (b) lateral [13].
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Fig.7. Mexico City Earthquake, 1985 [17]: (a, b) Damage to steel pipelines; (c) close-up of a joint failure; (d) joint failure of a
concrete pipeline.
a discrete movement along a geologic fault (Fig.5),
or triggered from seismic shaking such as landsliding
Fig.6 and liquefaction.
Compressive failure of a continuous buried pipeline
occurs due to fault rupture, landslide, liquefaction, or
relative ground motions. Local buckling or wrinkling
in the buried pipelines is due to local instability
of the pipe wall, and this is very common failure
mode for steel pipes. Figure 6 illustrates the local
buckling of a 77-in welded steel pipe during the 1994
Northridge Earthquake [13]. For a shallow buried
pipeline, during movement along a fault in the
vertical plane, global buckling is predominant over
local buckling: the uplift resistance is much less than
the downward bearing capacity. Typically, the relative
The Journal of Pipeline Engineering
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Circumferential flexural failure and joint rotation
When a segmented pipe is subjected to bending due
to permanent ground movement or shaking due to
seismic events, the ground curvature is accommodated
by a combination of rotation at the joints and flexure
on that pipe segment, and these are the two major
failure modes for cast iron or asbestos-cement pipes.
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movement is distributed over a considerable length,
and hence the compressive strains in the pipeline
are not too large and the potential of tearing of the
pipe wall is reduced.
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Fig.8. Indian hydrocarbon
transportation modes (% share)
(after Mathur, 2010 [18]).
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In tension, a corrosion-free steel pipe with arc-welded
butt joints is ductile and capable of mobilizing large
strains, associated with significant tensile yielding,
before failure. However, older steel pipe with gaswelded joints often cannot withstand large tensile
strains before rupture. The strain associated with
tensile rupture is generally well above about 4% [14];
for analysis and design, an ultimate tensile value of
approximately 4% [15] is often used, beyond which
the pipeline is considered to have failed in tension.
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Welded slip joint
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The material strength of the pipe governs the failure
of the arc-welded butt joints. However, for pipelines
on steel slopes with slip joints and gas-welded joints,
the failure criterion is different and is governed
by the strength of the joints which is less than
the strength of the pipe material. During the San
Fernando Earthquake in 1971, the 48-in diameter
Granada Trunk Line was an example of welded slip
joint failure during an earthquake [5].
Axial pull-outs
The shear strength of the joint material is much less
than that of the pipeline material. During seismic
activity in areas of tensile ground strain, this kind
of failure mechanism dominates especially for water
transport pipelines [16].
Crushing of bell-and-spigot joints occurs due to
compressive strain and was observed following the Mexico
City Earthquake in 1985 [17], Fig.7, and following the
Bhuj earthquake of 2001 [16] where many of the cast
iron pipes were damaged due to this failure mechanism.
Seismic vulnerability of existing and
proposed Indian pipelines
In India there are already more than 33,000 km of
oil and gas pipelines which have been laid through
many geographical areas and geologic conditions, and
these pipelines contribute 32% of total transportation
modes of hydrocarbons in India, as shown in Fig.8 [18].
More pipelines are planned to be laid in the future.
The previous history of pipeline damage in India due
to earthquake was summarised by Das and Jain in
Ref.13. In the 6.6-M Bihar Earthquake of 1988, some
minor damage to facilities at the IOCL refinery was
reported. In the 6.8-M Chamoli Earthquake, water
supply lines in Chamoli and Gopeshwar was disrupted
due to landslides. In the 7.7-M Gujarat Earthquake
in 1991, while a little damage occurred at the joints
of pipelines to pump station equipment, no major
damage was reported. Similarly, in the 9.0-M Sumatra
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Fig.9. (a) Axial pull-out at the joint of a water supply pipeline during the Tangshan Earthquake, 1976 [23]; (b) Leaking at
a bell-and-spigot joint of a water supply pipeline due to bending during the Sumatra Earthquake, 2004 [13]; (c) Local
buckling/wrinkling of a product pipeline in compression in the California Earthquake [24]; (d) Beam buckling of a water
pipeline [13].
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Earthquake, most of the water pipelines were damaged
in the Andaman and Nicobar Island areas, Fig.9b.
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In addition to various pipeline projects being undertaken
within India, there are plans to import piped gas
from gas-rich neighbouring countries, such as Iran
and Turkmenistan in Central Asia, Qatar and Oman
in West Asia, and also from Burma and Bangladesh.
As part of these schemes, the following international
pipelines are being proposed:
• Iran-Pakistan-India (IPI) gas pipeline
• Turkmenistan-Afghanistan-Pakistan-India (TAPI)
gas pipeline
• Bangladesh-India onshore gas pipeline
For the pipelines from Afghanistan and Iran, the routes
are in areas of high seismicity as shown in Fig.11.
The route map of the IPI pipeline is shown in Fig.10;
superimposing this route map with the tectonic map
of Fig.1 shows that the pipelines entering India from
the north west border are particularly vulnerable to
seismic activity. Even the eastern side of the country
falls under seismic threat, and the pipeline routes from
Bangladesh and Burma also cross high earthquake zones
as shown in Fig.2.
There is also plan to construct an offshore pipeline
of over 1300 km length [19] across highly variable
geologic conditions between the Middle East and India
across the Indus River delta. In the Indian context, it
is critical for engineers to understand the performance
of on- and offshore buried and above-ground pipeline
structures subjected to ground surface rupture, soil
liquefaction, and other seismic hazards.
Seismic-hazard analysis for the proposed Oman-India
subsea pipeline was carried out few years ago [19]. The
The Journal of Pipeline Engineering
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ground-shaking hazard along the route of the pipeline
and in the Indus delta was found out to be relatively
high. Due to this, and other potential geohazards such
as liquefaction, submarine landslides can be triggered.
Figure 11 shows the route of the pipeline and seismic
activities in nearby areas.
Conclusion
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Seismic design and engineering of pipelines has advanced
significantly in last few decades, although little has been
accomplished to address the vulnerability of buried pipelines
to seismic hazards. With new and proposed cross-country
pipelines in India, it is becoming more important to
understand the effects of seismic hazards (such as shaking,
liquefaction, fault surface rupture) on buried pipelines. In
1974 the first seismic design code Technical standard for oil
pipelines [20] was developed by the Japan Roads Association
[13]. Thereafter, in 1984, ASCE first published formal
guidelines [15] for seismic design of pipeline systems,
although until 2007 there was no specific standard for
seismic design of pipeline systems. However, the Gujarat
State Disaster Management Authority (GSDMA) felt the
urge to develop such a standard for Indian application
as the state was the worst affected during the 2004 Bhuj
Earthquake, and numerous public and privately owned
oil and gas companies have laid their pipeline networks
across that state. GSDMA has sponsored a project at
the Indian Institute of Technology in Kanpur, and in
2007 the first draft was published [13]. An analysis of
Fig.10. Route map of
the IPI pipeline [18].
the effect of earthquakes on a continuous pipeline in
the state of Gujarat in India was presented in Ref. 21
based on the GSDMA report, in which the authors
also discuss the design and construction methodology to
minimize the effect of loading on the pipeline during
ground movement.
In summary, this paper has given an overview of past
performance of buried pipelines during earthquake events
including fault rupture, liquefaction, seismic shaking, and
illustrates the nascent understanding of earthquake hazards
around the world and in India. Identification of seismic
sources and geohazard-prone areas during the early phases
of a project allows these data to be incorporated during
the design phase. Appropriate site-specific seismic design
during the engineering stage can then reduce the risks
posed by earthquake hazards on buried pipeline structures.
References
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2.I.A.Parvez, F.Vaccari, and F.P.Giuliano, 2003. A
deterministic seismic hazard map of India and adjacent
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3.V.Kamalakar and R.P.Kumar, 2009. Damage based
life of historical constructions in seismic environment.
European J. of Scientific Research, 35, 2, pp 254-273.
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vulnerability of
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(http://www.iitk.ac.in/nicee/IITK-GSDMA/EQ28.pdf).
14.N.M.Newmark and W.J.Hall, 1975. Pipeline design
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MI, pp 416–425.
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21.I.Guha and R.Flores-Berrones, 2008. Earthquake
effect analysis of buried pipelines. Proc. 12th
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W.K.Mohanty and M.Y.Walling, 2008. Seismic
hazard in mega city Kolkata, India. Nat Hazards, 47,
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16.S.R.Dash and S.K.Jain, 2005. Seismic design of buried
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17.
R.Flores-Berrones and X.L.Liu, 2003. Seismic
vulnerability of buried pipelines. Geofίsica International,
42, 2, pp 237-246.
18.S.Mathur, 2010. Pipeline perspective on India –
2010. Petromin Pipeliner, Oct-Dec, pp 22-35.
K.W.Campbell, P.C.Thenhaus, J.E.Mullee, and
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R.Preston, 1996. Seismic hazard evaluation of the
Oman India pipeline. Proc. Offshore Technology
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JRA, 1974. Technical standard for oil pipelines.
Japan Road Association.
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