Journal of Pipeline Engineering

Transcription

March, 2012
Vol.11, No.1
Journal of
Pipeline Engineering
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incorporating
The Journal of Pipeline Integrity
Great Southern Press
Clarion Technical Publishers
Journal of Pipeline Engineering
Editorial Board - 2012
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Obiechina Akpachiogu, Cost Engineering Coordinator, Addax Petroleum Development Nigeria, Lagos,
Nigeria
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 Michael Beller, NDT Systems & Services AG, Stutensee, Germany
Jorge Bonnetto, Operations Director TGS (retired), TGS, Buenos Aires, Argentina
Dr Andrew Cosham, Atkins Boreas, Newcastle upon Tyne, UK
Dr Sreekanta Das, Associate Professor, Department of Civil and Environmental Engineering, University
of Windsor, ON, Canada
Prof. Rudi Denys, Universiteit Gent – Laboratory Soete, Gent, Belgium
Leigh Fletcher, Welding and Pipeline Integrity, Bright, Australia
Roger Gomez Boland, Sub-Gerente Control, Transierra SA,
Santa Cruz de la Sierra, Bolivia
Daniel Hamburger, Pipeline Maintenance Manager, El Paso Eastern Pipelines, Birmingham, AL, USA
Prof. Phil Hopkins, Executive Director, Penspen Ltd, Newcastle upon Tyne, UK
Michael Istre, Engineering Supervisor, Project Consulting Services,
Houston, TX, USA
Dr Shawn Kenny, Memorial University of Newfoundland – Faculty of Engineering and Applied
Science, St John’s, 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, Kema Gas Consulting & Services, Groningen, Netherlands
Dr Nobuhisa Suzuki, JFE R&D Corporation, Kawasaki, Japan
Prof. Sviatoslav Timashev, Russian Academy of Sciences – Science
& Engineering Centre, Ekaterinburg, Russia
Patrick Vieth, Senior Pipeline Engineer - Pipelines & Civil Engineering, BP America, Houston, TX,
USA
Dr Joe Zhou, Technology Leader, TransCanada PipeLines Ltd, Calgary, Canada
Dr Xian-Kui Zhu, Senior Research Scientist, Battelle Pipeline Technology Center, Columbus, OH,
USA
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1st Quarter, 2012
1
The Journal of
Pipeline Engineering
incorporating
The Journal of Pipeline Integrity
Volume 11, No 1 • First Quarter, 2012
Contents
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Dr Antonio Martinez Niembro, Naim M Dakwar, and Dr Roger King . ...............................................................11
On the protection of landfall pipelines installed by HDD
Ingrid Pederson, Millan Sen, Andrew Bidwell, and Nader Yoosef-Ghodsi ............................................................21
Enbridge Northern pipeline: 25 years of operations, successes and challenges
Abu Naim Md Rafi, Halima Dewanbabee, and Prof. Sreekanta Das...................................................................... 29
Use of lighter backfill materials for delaying dent repair
Jim E Marr, Elvis Sanjuan, Gabriela Rosca, Jeff Sutherland, and Andy Mann....................................................... 35
Validation of the latest generation EMAT ILI technology for SCC management
Mark Slaughter, Kevin Spencer, Jane Dawson, and Petra Senf ............................................................................... 43
Comparison of multiple crack detection in-line inspection data to assess crack growth
Taylor Shie, Dr Tom Bubenik, and Daniel J Revelle ............................................................................................... 53
Independent validation of in-line inspection performance specifications
Faisal M AlAbbas, John R Spear, Anthony Kakpovbia, Nasser M Balhareth, David L Olson,
and Brajendra Mishra ................................................................................................................................................ 63
Bacterial attachment to metal substrate and its effects on microbiologically-influenced corrosion in transporting hydrocarbon pipelines
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The final pipes are curently being laid on the second NordStream pipeline that runs
through the Baltic Sea from Russia to Germany. Our COVER PICTURE, taken
recently on the Castoro Sei laybarge offshore Sweden, shows one of the 48-in diameter,
23-tonne, concrete-coated pipe lengths being hoisted onto the laybarge, having been
transported from the nearby Slite pipe-storage site on the Swedish island of Gotland.
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.
2
T
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.
Authors wishing to submit papers should do so online at www.j-pipeng.com. The Journal of Pipeline Engineering now
uses the ScholarOne 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.
Notes
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.
5. Publisher: The Journal of Pipeline Engineering is
published by Great Southern Press Ltd (UK and Australia)
and Clarion Technical Publishers (USA):
2. Copyright and photocopying: © 2012 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 from the copyright holder.
Authorization to photocopy items for internal and personal
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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.
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
2012 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
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HP9 1NS, UK
• tel: +44 (0)1494 675139
• fax: +44 (0)1494 670155
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Editor: John Tiratsoo
• email: [email protected]
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Suite 255, Houston TX 77002, USA
• tel:
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• web: www.clarion.org
Associate publisher: BJ Lowe
• email:
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6. ISSN 1753 2116
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is available for subscribers
1st Quarter, 2012
3
Editorial
CCS and transportation of captured CO2: a Government initiative,
a new book, and an important Forum
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The deployment of CCS is at an early stage, so to the extent
that UK-based business can take advantage of these local
opportunities it should help to establish them as leaders in a
developing worldwide market. The Government is committed
to helping make CCS a viable option for reducing emissions in
the UK and, in doing so, to accelerate the potential for CCS
to be deployed in other countries. It is seeking to support the
development of a sustainable CCS industry that will capture
emissions from clusters of power and industrial plants linked
together by a pipeline network transporting CO2 to suitable
storage sites offshore. The CO2 thus captured might also be
used in enhanced-oil-recovery processes to recover additional
amounts of the UK’s hydrocarbon reserves, thereby improving
the economics of CCS and accelerating deployment.
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he UK Government’s Department of Energy and Climate
Change (DECC) has just issued an important strategy
document which, if all its aims come to pass, heralds an
equivalent expansion of the UK pipeline high-pressure
gas-transportation network to the national transportation
system constructed when North Sea gas came ashore in
the 1970s. Furthermore, if other European governments,
not to mention those further afield, take similar steps, the
international pipeline industry will experience an expansion
that was previously unimaginable. Those of a cynical
disposition might well murmur that they’ve “seen it all
before” and, to a certain extent, this may be the case. But the
Secretary of State for Energy and Climate Change Edward
Davey’s recent announcement that “This is a really exciting
time for the fledgling CCS industry: our offer is one of the
best anywhere in the world” deserves consideration in the
context of this new CCS Roadmap1 and its accompanying
CCS Commercialization Programme.
In this unusually-lengthy editorial, we summarize the
intentions of this important Roadmap using its executive
summary as a reference, and go on to introduce an important
new book that has been published on engineering aspects
of the pipelines that will be needed to achieve some of
them. We conclude with a review of the forthcoming Third
International Forum on Transportation of CO2 by Pipeline,
taking place in Newcastle, UK, on 20-21 June and jointly
organized by the co-publishers of the Journal.
The DECC’s Roadmap starts by emphasizing that tackling
climate change requires global action and every country
needs to play its part. For the UK this will mean a
transformation in the way the country generates and uses
energy – a long-term transition to secure, affordable, lowcarbon energy on the way to an 80% cut in greenhouse-gas
emissions by 2050. Carbon capture and storage (CCS)
has the potential to be one of the most cost-effective
technologies for decarbonisation of the UK’s power and
industrial sectors, as well as those of economies worldwide.
CCS can remove carbon dioxide (CO2) emissions created
by the combustion of fossil fuels in power stations and in
a variety of industrial processes and transport it for safe
permanent storage deep underground, for example (in the
UK’s case) deep under the North and Irish Seas.
1. CCS Roadmap: supporting deployment of carbon capture and storage in the UK.
Department of Energy & Climate Change, London, April 2012. Crown Copyright.
The Roadmap goes on to outline how the goal of seeing
commercial deployment of CCS in the UK in the 2020s will be
met, pointing out that the UK has a number of key advantages
that make this country ideally suited for the deployment of
CCS, including:
• extensive storage capacity under the UK seabed,
particularly under the North Sea;
• existing clusters of power and industrial plants with
the potential to share CCS infrastructure;
• expertise in the offshore oil and gas industry which
can be transferred to the business of CO2 storage; and
• academic excellence in CCS research.
To ensure CCS can contribute to the UK’s low-carbon future,
the Government is taking forward a programme of interventions
that aims to make the technology cost-competitive and enable
the private sector to invest in CCS-equipped fossil-fuel power
stations, in the 2020s, without Government capital subsidy.
This early deployment on power stations is seen as providing the
starting point for the development of CCS clusters with multiple
sources of CO2, including industrial sources, benefitting from
access to shared transport and storage infrastructure. There are
three key challenges which the Government believes must be
tackled to enable commercial deployment of CCS in the UK:
• reducing the costs and risks associated with CCS so that
it is cost-competitive with other low-carbon technologies;
• establishing the market frameworks that will enable
CCS to be effectively deployed by the private sector
cost; and
• removing key barriers to the deployment of CCS.
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Among the ways that these challenges are to be met are a
£1-billion CCS commercialisation programme to support
commercial-scale CCS schemes, targeted specifically at
“learning by doing” and to share the resulting knowledge.
There is also to be a £125-million, four-year, co-ordinated
research and development and innovation programme and,
among other activities, further work to support the CCS
supply chain, and to develop transport and storage networks.
A UK CCS Research Centre is also to be established
which will bring together around 100 of the UK’s top
CCS academics to support core research, development,
and innovation activities. In the transportation field, the
Centre’s aims will include:
The economic case for investment in shared infrastructure
is considered to be straightforward and unquestionable.
Although transportation of CO2 in particular, the DECC
says, is dominated by upfront capital investment, the
investment does not increase in proportion to the installed
capacity. Shared infrastructure therefore reduces the cost of
CCS, provided the investment in additional capacity is used
to the extent necessary to justify the additional investment.
The DECC states firmly that the Government will support
the development of CO2 transport and storage infrastructure
through this programme, as well as keeping the economic
regulation arrangements for pipelines under review and
assisting those looking to develop regionally focused CCS
activities, including the development of regional clusters
of CO2 emitters.
The issue about the cost of shared infrastructure is illustrated
in the accompanying Table 1 published by the DECC, in
which the figures are based on ‘typical’ circumstances in the
UK and compare the cost of a pipeline sized to transport
CO2 captured from a 300-MW power station, compared
with a pipeline constructed at the largest size typical in the
UK. The larger pipeline would cost about 25% more than
a pipeline designed solely for the 300-MW source. The
additional capital investment will increase capacity between
five and seven times, and provided this additional capacity
is fully exploited it will reduce the cost of transporting CO2
by a factor of about five. However, if that additional CO2
does not materialise, then increasing the capacity of the
pipeline beyond that required for the 300-MW power
station will have the opposite effect, increasing the cost
of transport by about a quarter on an equivalent basis.
The cost-benefit is therefore entirely dependent on the
likelihood and timing of the additional CO2 materialising:
if that were not the case, then the assessment would
change markedly.
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• understanding potential hazards and risks to inform
decisions on pipeline routes onshore;
• developing techniques for leak mitigation and
remediation;
• identifying novel pipeline materials and sealing and
jointing technologies;
• developing a performance database for CO2
transportation networks to enable grid optimization.
for money, without compromising the overall thrust of
Government policy for infrastructure to be privately owned
and financed.
With an important gesture towards the pipeline industry,
the Roadmap later points out that the development of the
infrastructure necessary to transport and permanently store
CO2 is one of the key challenges to achieving its objectives.
The availability of pipelines and storage sites that enable
high-emitting industries to contract for the transport and
storage of CO2 on similar commercial bases to other
utilities, it says, will be one consequence of the widespread
deployment of CCS in the UK’s economy. It goes on to say
that some supporters of CCS argue that the development
of the infrastructure will in fact be a pre-requisite for the
widespread deployment of CCS on the scale needed to
meet the Government’s low-carbon electricity objectives.
A note of caution is sounded further on in the Roadmap in
connection with the engineering skills that will be needed
to achieve the targets it proposes. One of the main issues, it
says, is the expected decline in the number of UK engineering
specialists and experts in the coming decade. Greater demand
for these skills following commercial deployment of CCS
schemes (alongside other low-carbon technologies) is seen
as an opportunity of offset this decline. The Roadmap’s
authors say that there is no room for complacency in this
regard: ensuring enough skilled workers are available will be
crucial in the successful roll-out of commercial CCS schemes.
The DECC says that, while it is not the role of the
Government to plan the generation of electricity or the pace
and location of CO2 transport and storage infrastructure
at the level of detail implied by the Roadmap’s ambitions,
there are steps the Government can take that will facilitate
the development of CCS infrastructure. It intends to
tailor these in order to encourage cost-effective investment
in CCS infrastructure where it helps deliver the CCS
Commercialisation Programme objectives and offers value
As the DECC points out, a number of organisations have
undertaken more sophisticated assessments and come to
similar conclusions. In particular, it says, excellent work
has been carried out in areas of the UK where there are
high concentrations of CO2 emissions in order to plan
the development of regional networks that would enable
industries to tap into the service at the point where this
makes business sense. The high level of capital investment
required to get these projects off the ground becomes
economic even when relatively pessimistic assumptions
are made about the amount of additional CO2 being
handled by the network and when that becomes available.
In addition to these prospective economic benefits, the
DECC identifies other less-tangible benefits that are also
likely to emerge from a networked approach. It obviously
makes sense in terms of reducing environmental damage
1st Quarter, 2012
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110km onshore 170km offshore
(£-million)
(£-million)
Table 1. Comparison of
the cost of pipelines for
transporting CO2 from a
300-MW power station
or on a larger scale.
Total cost
(£-million)
Incremental cost
(compressors, etc.)
(£-million)
300-MW, 16-in
diameter pipeline
30
30
220
40
Larger scale, 3642in diameter
50
225
275
200
+20 (70%)
+35 (20%)
+55 (25%)
Difference
The UK Government’s long-term strategy is that CCS
infrastructure will be funded through private investment,
and that it will develop over time, in line with demand. It
hopes that the relatively ‘piecemeal’ investments will become
integrated into a network as demand and geographical
distribution of CO2 capture increases. To enable this,
regulatory powers have been adopted to ensure that third
parties can access infrastructure on a fair and equitable
basis, and also to enable new pipelines to interconnect with
existing capacity in order for a network to develop.
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and public inconvenience to avoid the construction
of multiple pipelines along the same or similar routes
within a relatively short period. It is also likely to be the
case that businesses would be more likely to capture and
permanently store CO2 if transport infrastructure were
readily available than if they were required to develop and
install an infrastructure from scratch. A readily available
CO2 transport and storage network is therefore likely to
provide an attractive mitigation option for high-emitting
industries looking to reduce emissions. This, in turn, is
likely to have implications for the make-up of the economy
in those areas of the country with a high concentration of
carbon intensive industries.
Recognizing the contribution that reduced CO2 transport
and storage costs could make to achieving the objectives of
the CCS commercialisation programme, the Government
will consider supporting the development of CCS
infrastructure on a scale that anticipates future demand and
enables the development of local infrastructure networks,
provided there is clear value for money justification in
doing so.
According to the DECC, its Roadmap is intended to
help build confidence in the scale, location, and type
of investment in CCS that is likely to take place until
2030, and the steps the Government will take in order to
facilitate that. The Roadmap will therefore help inform
decisions about investment in CCS that will consequently
help provide confidence in the emerging need for CCS
infrastructure. As is emphasized, the key to unlocking
investment in CCS infrastructure is market confidence
that CCS will provide the benefits anticipated, that the
demand for transport and storage will materialize, and
that commercial arrangements typical for other utility
services will emerge. Government action to facilitate the
development and deployment of CCS is designed to help
address each of these points, and will ultimately create
the right conditions for the private sector to invest in
the pipeline and storage infrastructure without further
Government intervention. Prior to this, the Government
will be willing to consider supporting the development
of infrastructure through the CCS commercialisation
programme that anticipates future demand as well as the
development of local networks, provided there is clear
value for money justification in so doing.
This is all unmistakably exciting news on several fronts,
but not least for the high-pressure pipeline industry in the
UK. The challenges are huge, but the outcomes that are
anticipated will be significant in their technical achievements
as well as in the environmental benefits. There have been few
moments such as this in the history of pipelines, when such
a clear outlook has been available. We hope that industry
embraces these opportunities, to the benefit of itself, the
country’s economy as a whole, and the communities it serves.
The definitive textbook on anthropogenic CO2
transportation by pipeline
In the first single source that encompasses such a
comprehensive field, this new book2 brings together the
entire spectrum of design and operating needs for a pipeline
network to transport CO2 containing impurities both safely,
and without adverse impact on people and the environment.
As is widely acknowledged, pipeline systems are the safest
means of transporting captured CO2. However, the phase
diagram for a CO2 stream containing impurities is very
sensitive to the level of these impurities, which in turn affects
the pipeline design and the boundaries between which CO2
pipelines can be operated without affecting the facilities’
design as well as the delivery conditions. The largest network
of CO2 pipelines is in North America, the oldest there being
Denbury’s 82-km long Cranfield pipeline from Mississippi
to Louisiana, constructed in 1963. However, the majority
of these lines (with one exception – see below) transport
CO2 which predominantly has originated in underground
reservoirs and which has been processed and dehydrated,
2. Pipeline transportation of carbon dioxide containing impurities, by Dr Mo
Mohitpour, Dr Patricia Seevam, Kamal Botros, Brian Rothwell, and Claire Ennis,
with contributions by Prof. Martin Downie and Dr Julia Race, is published by ASME
Press in New York, 444 pages, hard cover, ISBN 978-0-7918-5983-4.
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The 13 chapters of this book have been written with the
intent that each could stand alone on the subject matter
presented without necessarily referencing other chapters.
Both imperial and metric units have been used, justified
because the industry continues to use the unit systems
interchangeably, and the authors have identified exhaustive
lists of references for each chapter.
programme, which aims to address and resolve the
key issues relating to the safe routeing, design, and
construction of onshore pipelines for the transportation
of anthropogenic, high-pressure, dense-phase CO2 from
power stations and other industrial emitters to offshore
locations for underground storage by 2014. An overview
of the COOLTRANS research programme was given at
the 2011 Forum, which explained the integrated analysis
strategy combining state-of-the art numerical modelling
of the pipeline decompression, and near- and far-field
dispersion, studies being conducted by three university
groups and use of full-scale experimental tests carried out
at the Spadeadam test site of GL Noble Denton. This
paper presents the results of further work, and explains
how the results of the integrated analysis are being used
to assess the performance of pragmatic dispersion models
used in pipeline QRA studies in the COOLTRANS
research programme.
In one of the Forewords to the book, Charles Fox –
vice-president of operations and engineering for Kinder
Morgan – writes that until now, the transportation aspects
of CCS schemes has been unjustly neglected. He goes
on: “The authors, from various different backgrounds
and organizations related to pipeline engineering, have
assembled the state of the art and science”. Perhaps even more
significantly, as one who is responsible for the management
of the world’s largest CO2 pipeline system, he continues:
“Like all companies, my employer constantly faces staff
turnover, and we struggle to pass along the knowledge of CO2
transportation to newcomers. This reference will help assure
that experts always operate our pipeline system. I encourage
others who plan, design, or operate CO2 pipelines, to obtain
this book and use it.” It is hard to see how his remarks or
his endorsement, can be improved.
The paper will provide further details of the COOLTRANS
project and report the results of integrated analysis case
studies designed to bring together theoretical predictions
and experimental measurements of CO2 releases. The
results of studies involving venting of dense-phase CO2
through a single, straight, vertical vent pipe of constant
diameter and instantaneous horizontal release from a
shock tube designed to simulate a full-scale pipeline release
will be discussed. The paper will include contributions
generated by the group of universities working on
the integrated dispersion analysis (UCL, Leeds, and
Kingston) and contributions generated by GLND using
pragmatic models applied in QRA studies. The paper
will demonstrate the value of combining and comparing
modelling strategies and explain the improvements
planned as part of the COOLTRANS objectives.
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and for which the main use is in enhanced oil recovery
(EOR) schemes. The single exception is the 324-km long,
14- and 12.75-in diameter, Weyburn pipeline that came
on-stream in 2000, and which transports captured CO2
from the flue stacks of a coal-gasification plant in North
Dakota to oil fields in Weyburn, Saskatchewan for EOR.
(Not only is this the only pipeline world-wide transporting
industrial quantities of anthropogenic CO2, but it is
also one of the few pipelines generally that crosses an
international border.)
Third international Forum planned for June
As mentioned a the beginning of this Editorial the copublishers of the Journal are organizing the Third
International Forum on Transportation of CO2 by
Pipeline, which will be held in Newcastle, UK, on 2021 June. The event has become an important fixture in
the calendar of many who are involved in this subject,
testified to by the fact that the programme contains 28
papers from authors from seven countries. As in previous
years, the programme is a gallimaufry of the latest stateof-the-art, encompassing research and practical solutions,
and ranging from fracture arrest to planning. The full
programme and other details can be seen at www.clarion.
org: we have space here to highlight a number of papers
of particular interest.
COOLTRANS – Integrated analysis of CO2 decompression
and near- and far-field dispersion from a pipeline release: case
studies, by Russell Cooper, National Grid, Warwick, UK
National Grid is progressing the COOLTRANS (Dense
Phase CO2 PipeLine TRANSportation) research
Corrosion and solid formation in dense-phase CO2 pipelines
with impurities: what do we know, and what do we need to
know?, by Arne Dugstad, Chief Scientist – Materials and
Corrosion Technology, Institute for Energy Technology, Kjeller,
Norway Following the ‘Blue Map Scenario’ for the abatement
of climate change, about 10Gt/yr of CO2 need to be
safely transported and stored underground by 2050.
This requires the construction of about 3000 12-in
diameter, or 1000 20-in diameter, pipelines, assuming
a flow velocity of 1.5m/s.
The good experience with CO2 transport in USA is
often referenced to argue that CO2 pipeline transport
will not be a big challenge for CCS. Therefore, so far,
there has been surprisingly little focus on corrosion and
impurity reactions in the pipeline. A recent review shows
that less than ten published papers actually present new
data that are relevant for pipeline transport with small
amounts of water and impurities. The justification for
this negligence can be questioned as:
1st Quarter, 2012
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Risk assessment of CO2 pipeline network for CCS: a UK case
study, by Chiara Vianello and Giuseppe Maschio, Dipartimento
di Ingegneria Industriale, Universita’ di Padova, Italy, and Prof.
Sandro Macchietto, Department of Chemical Engineering, Imperial
College, London, UK
CCS technology requires transporting large amounts of CO2
over long distances, as capture plants are expected to be situated
near power plants and other large industrial sources such as
steel and cement works, while storage locations are expected
to be in remote geological formations, typically offshore. CO2
can be transported using one or a combination of transport
media: truck, train, ship, or pipeline. Transport by pipeline is
considered the preferred option for large quantities of CO2
over long distances, and is the subject of this paper.
The CO2 pipeline network most appropriate for a country
is clearly a function of the specific location of sources and
storage points, their capacity and a number of other factors
such as population centres and geographical features (rivers,
mountains, railroads, motorways, etc).
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• Few of the existing pipelines are transporting or
have transported anthropogenic CO2. None of the
reported CO2 compositions found in the public
domain include the flue gas impurities given in
the CO2 specifications discussed in the CCS
community i.e. the recommendations published from
the DYNAMIS project or the table with expected
impurities in dried CO2 published by IPCC.
• Water content in the 500ppmv range is referred to
and assumed acceptable in a number of publications
discussing CCS and CO2 transport. The question is
whether this apparently safe water level also applies
when glycols, amines, and flue-gas contaminants
like SOx, NOx, and O2, are present in moderate
amounts. These impurities dissolve readily in
water and induce an aqueous phase at a much
lower water concentration than the solubility limits
reported for pure CO2 and CO2 contaminated with
hydrocarbons.
• The water content in the anthropogenic CO2 that
has been transported has been low (<130 ppmv) and
it can be questioned if the field experience can justify
the much higher water content often referred to.
The paper will discuss (1) the gap and recent results
obtained in corrosion and solubility experiments
with dense phase CO2 containing small amounts of
impurities like SO2, NO2 and O2, (2) the need for more
experimental data, and (3) the experimental challenges
meet when data are generated in the laboratory.
Design of CO2 transmission pipeline systems, by Michael Istre,
Chief Engineer, Project Consulting Services, Inc., Lafayette,
LA, USA
One of the technologies that may play a role in reducing
emission of carbon dioxide is CCS. The widespread
adoption of CCS will require the transportation of the
CO2 from where it is captured to where it is to be stored.
Pipelines can be expected to play a significant role in
the required transportation infrastructure.
This paper will review how the current knowledge base
of CO2 pipeline design was implemented in a new
transmission pipeline system as part of a new electric
power plant in Mississippi. The 16-in diameter pipeline
is designed to transport over 10,000t/d of CO2 collected
from the power plant’s synthetic gas-from-coal process for
enhanced-oil recovery in depleted oil fields. The pipeline
includes approximately 98km of pipeline designed
to transport CO2 in dense-phase and deliver to two
independent CO2 consumers. This paper will discuss
the efforts made in designing pipelines for anthropogenic
CO2 mixtures, specifically for pipeline hydraulics,
running-ductile-fracture mitigation, and pipeline-rupture
dispersion modelling. The paper will also include a
discussion of the risk measures implemented in the
design to control release and protect population centres.
The phased roll-out and initial design of the onshore part of
a CO2 pipeline network for the UK, suitable to deal with the
distribution of forecasted CO2 amounts captured at major
sources, was proposed by Lone et al., 2010, based on a technoeconomics analysis. The analysis resulted in proposed sizing
and location of various pipeline segments in a three-phase
rollout, dealing with largest duties first, and details of CO2
flows and pressures for each segment in each roll-out phase.
This paper describes the quantitative risk analysis of this
pipeline network, and in particular an assessment of
consequences due to the possible CO2 releases. First, the
probability of various accidental events is determined. Then,
the estimation of consequences is made using PHAST
software using its ‘long-pipeline’ release model, for two types
of release: (i) from a hole with diameter equal to 20% of
section area; and (ii) from a full-bore rupture (catastrophic
release).
Accidental events in a CO2 pipeline can produce a spray
release followed by a dense gas dispersion, and the high
concentration of CO2 can cause fatalities. To determine
possible health effects it is important to quantify not only the
CO2 concentration but also the duration of the exposure,
as the gas cloud evolves. For the calculation of risk, the
consequences are associated to the Probit function, which
calculates the percentage of the death of the individual.
The network can pass near residential areas: for this
situation, the consequences produced by a possible release
are calculated and various corridors of risk are identified (in
terms of population at risk, using population distribution
data). Finally, the tradeoffs achievable between populationrisk decrease and additional pipeline costs arising from
alternative pipeline pathways are shown by means of a
specific example.
8
CO2 carrying pipelines: the research of the Energy Pipelines
Cooperative Research Centre, by Prof. Valerie Linton, C Lu,
N Birbilis, J Hayes, Peter Tuft, Phil Venton, and P Balfe,
Energy Pipelines Cooperative Research Centre, Wollongong,
NSW, Australia
The transportation of carbon dioxide in dense phase requires
much higher pressures than are typical for onshore natural
gas, and this results in increased pipeline wall thickness
being specified. The prescriptive routeing options no longer
provide adequate guidance due to the pipeline pressure,
the variability of the consequences of the releases, and the
reduced benefit of increasing the wall thickness of an already
thick-walled pipeline. The individual risk-based approach is
also not generally appropriate. For example, the predicted
failure frequency for a dry, thick-walled, dense-phase pipeline
results in a very low (acceptable) individual risk and this does
not provide the control of risk required for the operator to
comply with the ALARP requirement of pipeline regulation.
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In Australia, gas and oil pipelines are designed, constructed,
and operated to the Standard AS2885: Pipelines – gas and
liquid petroleum. Should pipelines be built in Australia
to carry CO2 from capture sites to storage sites, AS2885
could also be used to cover the design and operation of
supercritical CO2 pipelines. A gap analysis was conducted
on the Standard to identify parts that required revision to be
applicable to CO2. This work produced a draft informative
appendix that has been incorporated into the Standard,
which is about to be published. The Energy Pipelines CRC
is currently conducting a programme of work to fill in gaps
in the current knowledge of CO2 behaviour so that this
information can be incorporated into later versions of the
Standard. Additionally, the Centre is carrying out work on
the public safety, community consultation, and organizational
requirements for CO2 pipelines. Finally, a cost-benefit exercise
is being conducted on the application of the results of the
work. This paper provides an overview of this work and the
benefits of CO2-carrying pipelines in Australia.
criteria have been directly based on the acceptability of
the societal risk of code compliant pipelines. Previously,
however, difficulties with the concepts and calculawtion
of societal risk led to the use of individual risk or even
consequence distances as a surrogate measure for societal
risk. The approach of using individual risk is included
as an option in the British Standard for pipelines, and
is the basis of land-use planning advice in the vicinity of
existing pipelines.
Through-life management begins with planning, by Lynn Andrews,
Head of Transportation & Offshore Consulting, and Paul Bryant,
CEO, CCS TLM Ltd, Woking, UK
Increasingly on pipeline projects the work of applying for
planning permission and pipeline works authorizations is
becoming more complex. Traversing populated and congested
areas is more common due to the increasing variation in
the type of uses for pipelines such as carbon-capture and
sequestration transportation. On these projects the progress
of planning applications can have a significant impact on the
project timescale and cost. Even an approved application
maybe unsuccessful in project terms if it does not bring with
it the general public and key interested parties.
The routeing of dense-phase CO2 pipelines, by R Philip Cleaver, GL
Noble Denton, Loughborough, UK, and Harry F Hopkins, Pipeline
Integrity Engineers Ltd, Newcastle upon Tyne, UK
The routeing of high-pressure natural gas transmission
pipelines has been governed by industry codes and standards.
These are set out to allow simple prescriptive routeing
guidelines to be employed while providing control of the
individual and societal risks in the vicinity of the pipeline.
This has been achieved by the use of separation distances,
the classification of populated areas, and the control of
the design factor (by increasing wall thickness). More
recently, quantified risk assessment has been available to
supplement the code approach but this has not generally
been used for routeing purposes for natural gas. The
operation of a pipeline is seen by the operator as posing
a societal risk issue and hence industry approaches and
It is proposed that routeing should be based directly on a
societal risk assessment, without the prescriptive requirement
for area classification and reduced design factors. The general
approach to the risk assessment for dense-phase pipelines is
described, from which a simplified approach for the initial
route selection has been derived. The approach is illustrated
for a dense-phase carbon dioxide pipeline and a natural gas
pipeline. The pair of examples illustrate how this approach
provides additional information and control for a densephase pipeline.
Design based on ductile-brittle transition temperature for API 5L
X65 steel used for dense CO2 transport, by Julien Capelle, Z Azari,
and Prof. Guy Pluvinage, LaBPS – Ecole Nationale d’Ingénieurs
de Metz, Metz, France, and J Furtado and S Jallais, Air Liquide,
Centre de Recherche Claude Delorme, Safety, Materials and
Processing Group, Jouy-en-Josas, France
Safe and reliable transport of dense CO2 by pipes needs a
careful choice of the constitutive pipe materials to prevent
brittle crack propagation after ductile or brittle failure
initiation. This unexpected phenomenon can occur after
failure or leak promoted by external interference. In this
case, the rapid decompression of dense CO2 into gas leads
to a very low local temperature of about -80°C.
To prevent risk of brittle fracture initiation and propagation,
the material must remain ductile at this temperature. In other
words, its ductile-brittle transition temperature (DBTT) has
to be lower than -80°C minus a margin.
It is admitted that the DBTT is not a material characteristic
but depends on specimen geometry, loading rate, and loading
mode, i.e. on constraints. A loss of constraint leads to a lower
1st Quarter, 2012
9
brittle-ductile transition. Generally designers use a DBTT
given by the Charpy impact test, and more precisely the
so-called TK27 transition temperature. The high constraint
involved by bending the specimen at high strain rate leads
to a conservative value of the transition temperature.
Constraints can be estimated by different types of parameters:
stress triaxiality, Q factor, or T stress. Constraints in a pipe
submitted to internal pressure are close to those given by
a tensile specimen.
Another conservative approach considers that if fractureinitiation occurs, the conditions for a running crack to
be arrested should be verified. The arrest criterion is
based on a critical value of CTOA which has also been
determined on API 5L X65 steel.
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In order to select a steel for transportation of dense CO2,
transition temperatures Tt (from the tensile test), TK27 and
TK50 (from the Charpy test), and TK100 (from the fracture-
mechanics’ test) have been determined on an APIX65 steel.
These transition temperatures have been reported versus
a constraint parameter, the T stress, in a master curve.
Differences between different brittle-ductile transition
temperatures and temperature corresponding to the T
stress acting on a pipe submitted to internal pressure on
the master curve give an estimation of the conservatism
of the chosen transition temperature.
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18–21 June 2012
Hilton Hotel, Newcastle, UK
ORGANIZERS
Join the industry in Newcastle, UK, to take the challenges of CO2
transportation by pipeline head on.
As governments around the world search for answers to mitigate climate change through
carbon capture and storage, the pipeline industry will be meeting in Newcastle, UK, to
develop the missing link: CO2 pipelines.
Forum programme
Over two days industry experts will meet to address the challenges presented by the
transportation of anthropogenic CO2 by pipeline including:
»
»
»
»
»
The economics of pipeline transportation;
The materials to be used;
Regulations and risk assessment;
Hydraulic modelling; and,
Operations and maintenance.
Know where the pipeline market is heading – make sure you register for the
International Forum on the Transportation of CO2 for CCS.
For more information visit www.clarion.org
18-19 JUNE 2012
TRAINING COURSE
19-21 JUNE 2012
EXHIBITION
20-21 JUNE 2012
CONFERENCE
1st Quarter, 2012
11
On the protection of landfall
pipelines installed by HDD
by Dr Antonio Martinez Niembro1, Naim M Dakwar1, and Dr Roger King*2
1
2
Saudi Aramco, Dharan, Saudi Arabia
Corrosion Services, Manchester, UK
P
IPELINES ARE INCREASINGLY installed using horizontally-directionally-drilled (HDD) procedures, with
varying results.The open annulus around the installed pipe may be fully or partially filled with grout and
drilling mud, or the hole sheathed with steel or non-metallic pipe before the pipe is installed. In the past,
the use of casings for road crossings has not been completely successful; an attempt to define appropriate
standard procedures for the protection of pipes in HDD and similar trenchless installations appears overdue.
T
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This paper reviews HDDs for river and road crossings, and landfalls, in an attempt to aid installation
contractors with the successful application of corrosion control by the combination of coatings and cathodic
protection. A field trial of abrasion-resistant coatings to protect pipelines coated with FBE and installed by
the thrust boring method is included.
RENCHLESS TECHNOLOGY IS a convenient and
widely used method of installing pipelines beneath
roads and rivers, and at landfalls. The pipeline is installed
into a prepared pre-drilled hole, either formed by boring
or a form of tunnelling. The final hole may be lined with a
casing depending on the nature of the ground. The various
options that will be discussed in this paper are shown in Fig.1;
though road crossings and other applications are mentioned,
the emphasis in this paper is on landfalls as these represent
more complex arrangements.
Horizontally-directionally-drilled
installation
In horizontally-directionally-drilled (HDD) installations the
normal procedure is to drill a small hole through the soil, the
direction of which is either controlled using a bent section
behind the drill that is rotated as necessary to adjust the
direction of the drillhead, or by use of a downhole motor. The
location of the drillhead is identified by a ‘beacon’ that will
include a gyroscopic or magnetic transponder. On completion
of the initial hole, the drill pipe is retrieved while pulling back
a ‘washover’ pipe and reaming tool to widen the hole. The
reamer provides a hole about 1.5 times the pipeline diameter.
This paper was presented at the Best Practices in Pipeline Operations & Integrity
Management conference held in Bahrain in March, 2012, and organized by Tiratsoo
Technical and Clarion Technical Conferences.
*Corresponding author’s details:
tel: +44 (0)161 740 6434
email: [email protected]
Fig.1.Trenchless installation of pipelines.
In most cases the pipeline is pulled through the widened hole
conjoint with the reaming process. HDD is suitable for a wide
range of soils, including relatively hard rock such as sandstone
and limestone. The pipe is usually of a heavier schedule than
the main pipeline, though marine pipelines at landfalls are
normally thick wall compared to onshore pipelines and this
requirement may not apply. The diameter/wall-thickness ratio
is normally less than 50. The pipe should be coated with an
anti-corrosion coating and should have an additional antiabrasion coating.
Drilling mud is used to lubricate the drilling and reaming
tools and to prevent collapse of the hole. When the pipeline
is in position it may be protected from external corrosion by
filling in the annular space between the pipeline and the hole
with a modified drilling mud, though grout is more widely
used. The presence of uncemented cobbles and gravels may
12
prejudice the HDD because collapse of these into the hole
would prevent the reamer or the carrier pipe from being
pulled back through the hole. It is usual for vertical holes to
be drilled to 10-15m below the intended pipeline path and
cores extracted to allow assessment of the underground
materials and conditions.
If the soil is permeable, and the grout would be lost, the
hole may be cased with a steel or non-metallic pipe through
which the pipeline is subsequently pulled. Typically the
casing is 1.5 times the diameter of the production pipeline.
The pipeline may be protected from external corrosion
by sealing both ends of this casing by link and/or rubber
end seals, installing non-metallic annular spacers, filling
the annulus with modified mud, grout, or anti-corrosive
gel, or by installing zinc ribbon anodes inside the casing,
sometimes followed by filling of the annulus.
Providing a more-conventional tunnel into which the pipe
can be installed is a more-expensive method and is used
when the ground is too hard for the alternative techniques
or where the pipeline will be in deep water. Tunnels are
generally large diameter and multiple pipelines may be
installed in one tunnel; for example, the Troll landfall
tunnel in Norway accommodates 36-in, 40-in, and 42-in
pipelines. After the pipeline is installed the tunnel may
be sealed with a concrete plug such that the pipeline is in
the dry, or filled with seawater. Examples of tunnels are
Bacton, Statpipe, Oseberg, Sleipner, Asgard, and Troll
[4], and the 3.5-m diameter tunnel for the 40-in Europipe
landfall on the German coast [5].
Protective coatings for HDD
installation
Coatings that have been applied to pipelines include threelayer polyethylene, and polypropylene and fusion-bonded
epoxies. Typical coating breakdown values are not available
but studies on coating tolerance to abrasion by rock and
stone indicate that 10mm HDPE performed well with
3-mm polypropylene being of similar tolerance [6]. Where
very abrasive conditions are likely it is prudent to provide
a sacrificial abrasion-resistant coating.
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More details of the engineering of HDDs in marine
environments are given elsewhere [1]. Drilling represents
about 75% of the total cost of the installed pipe, with the
linepipe being about 10% and the coatings and field joints
being 6% and 1% respectively. Engineering and inspection
account for the remainder [2].
pull through the 2-m diameter concrete-lined tunnel [3].
Pipe-jacking installation
Pipe jacking is similar to HDD except that the hole is
drilled to a smaller diameter and the pipe is then forced
through the hole. Friction is reduced by either providing,
in advance or by circulation, a lubricating mud during the
jacking process. Pipe jacking is almost exclusively used to
insert relatively short lengths of pipe into open holes in
firm ground. This method is not usually preferred since
it causes a lot of coating damage.
Tunnelling and microtunnelling
Microtunnelling is an alternative to directional drilling but
more expensive. Microtunnels are formed by pre-drilling a
hole using tunnelling equipment followed by immediate
jacking of steel or reinforced-concrete sleeves into the hole
as it is formed to create a lined tunnel through which
the pipeline can be installed. An intermediate technique
is Arrowbore in which the direction and depth of the
drilling are monitored by periodic checks on the progress
of the bore. This is done by installing vertical shafts to
allow the exact location of the bore hole to be measured
and its alignment adjusted. Because of the higher cost,
microtunnelling is used when HDD is impractical, for
example if there are environmental issues (the Livorno
landfall under the Arno River in Italy) or if the pipeline
requires a high level of protection (the Langeled landfall
under unstable cliffs at Easington, UK). The pipe should
be coated with an anti-corrosion coating and should have
an additional anti-abrasion coating. For example, the 44-in
Langeled pipeline landfall used a neoprene coating and
polyurethane spacers to protect the pipeline during the
To date, extra-thickness FBE coatings (approx. 700 micron)
appear to be the most widely used coatings, and dual-layer
FBE coatings are becoming more common. These coatings
combine a conventional 400-micron coating with a thicker
600-micron FBE coating specifically designed to provide
the abrasion resistance.
The anti-abrasion coatings that are available can be applied
over most corrosion-protection coatings. These coatings
are 4-5 times the cost of the corrosion-protection coating,
and consequently there is often resistance to their use: this
may, however, be a false economy as a pipeline with an
extensively damaged coating may require either replacement
within the planned service life or an extensive retrofit of
the cathodic-protection system. Abrasion-resistant coatings
are usually 100% solids’-content urethanes, epoxy polymer
concretes, or external wraps of polyolefin or polyethylene.
The liquid-applied coatings are applied in thicknesses
of 500-1000 microns, while the thermoplastic layers are
thicker, with up to 2000 microns being applied; these are
fixed to the FBE corrosion coating with adhesive.
If the risk of coating damage is only identified after the anticorrosion coating has been selected and applied, the range
of available abrasion coatings will be reduced. Retrofitting
an abrasion coating is possible but the additional pipe
handling and transport to and from the coating plant will
increase cost. Good adhesion between the anti-corrosion
coating and the abrasion-resistant coating is necessary,
1st Quarter, 2012
13
and there are a variety of methods used to test the quality
of the adhesion. Perhaps the most common is to attach a
small stud to the coating, cut around the stud through the
abrasion coating, and then use a screw thread instrument
to pull off the stud. Details for this test are given in ASTM
D-4541 [7].
Abrasion-resistance coatings do not normally require high
flexibility (deflection is typically less than 1o per pipe
diameter) or impact resistance; these will be provided
by the anti-corrosion coating. However, the abrasion
coatings require good resistance to gouging and abrasion.
If the installation will be during a cold period, it would
be prudent to check the flexibility of the coatings and
the impact resistance at the expected lowest ambient
temperature. Some abrasion-resistant coatings do have
limited flexibility, – for example, epoxy polymer concrete
– and selection must take this into account.
Fig.2. Detail of coating damage at a girth weld.
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The field joints at the girth weld areas also require to be
protected and this is often overlooked. Liquid- and sprayapplied coatings and shrink sleeves have been used. Double
shrink sleeves or shrink sleeves over the coating provide a
sacrificial layer to resist gouging and abrasion. Curing time is an
important factor to consider in microtunnelling installations.
Where the soil surveys indicate that there could be substantial
damage to the protective coatings on the pipe it is a practice to
pull sacrificial joints through the hole to evaluate the extent of
the damage that will occur on the pipeline, including a girth
weld. Excessive damage to the coating may be overcome by
additional cleaning of the hole or the application of additional
protection to the pipeline coating. Despite such precautions,
it is usual in such cases to evaluate the damage to the coating
on the installed pipeline so that the cathodic-protection system
can be adjusted to prevent corrosion. Techniques used such as
‘swing’ or current-requirement tests can be conducted before
tie-ins have been made, in which the required protection
current can be known and maintained. Coupons have been
used to simulate coating damage and demonstrate/prove
that enough cathodic protection is provided. Such tests can
only provide ‘traffic light’ information, however, since there
are some assumptions.
Many efforts have been developed by oil and gas operating
companies to assess any coating damage during thrust-boring
installations by HDD and/or microtunnelling, and to further
control and mitigate adverse effects of corrosion under
aggressive conditions such as Sabkha and contaminated soil.
One example is the coating damage during a microtunnelling
installation where it was estimated that approx 8.3sqm (1.3%)
of bare pipeline at the girth and spiral welds were exposed
directly to the soil under a road crossing, see Figs 2 and 3.
To ensure the protection of the pipeline at damaged coating
locations it was recommended to reinforce cathodic protection
at both sides of the crossing by installing magnesium anodes
with test stations at each end of the crossing, and investigate
Fig.3. Detail of coating damage at a spiral weld.
attenuation of potentials under the crossing. To monitor
the effectiveness of the CP a bare steel coupon (500mm x
100mm) was installed at one end of the crossing at the 12
o’clock position of the pipeline, immediately on top of the
pipeline and inside the bored section of the crossing, to
determine current density and instant-off potential, and to
perform field tests to ensure good levels of polarization at
both ends of the crossing [8].
Abrasion-resistant coating trials
Saudi Aramco recently conducted field testing using
non-metallic composite wrap systems to act as an abrasionresistant overlay (ARO) to protect FBE-coated pipelines
from erosion-abrasion damage during thrust borings by
HDD. Coating damage during thrust boring is costing the
company a significant amount of money in repairs and
replacement, as well as traffic interruption for pipelines
under major road crossings [9].
Six coatings and composite-wrap systems, composed with
different composite materials, were applied on a 24-m long,
32-in diameter, dummy pipe, each system occupying 4m in
length (Fig.4). Several butt welds were made in the 24-m
test pipe to test some of these coatings over butt welds.
The 32-in diameter pipe was pulled through a 133-m
length of a highly rocky area across a highway using the
HDD technique.
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Fig.4. Detail of the tested spool before testing.
The objective of the trial was to assess the integrity of each
system and its effectiveness in protecting the underlying
FBE coating. On completion of the trial, the pipe was
pulled out and a close visual examination was carried out
on each system (Fig.5). Two composite wraps passed the trial
successfully without any damage to the underlying coating
and minor damage to the reinforced fibre of both wraps.
The remaining composite-wrap systems and the underlying
FBE abrasive-resistance coating system, badly deteriorated,
and the initial FBE coating showed severe damage. The
evaluation team agreed to continue testing more types of
coating and non-metallics, such as dual-FBE and others, with
the main objective of improving thorough new technologies
the mitigation and control of corrosion in such critical and
high-consequence areas.
Pipeline corridors
and environmental constraints
Pipelines at landfalls are often severely constrained by planning
permission to fit within a narrow corridor which may contain
other pipelines and services, and precise location of the new
pipe will therefore be required. Environmental protection is
also increasingly important and this may restrict the volume
of drilling mud that can be lost during installation.
One approach to meeting precise installation requirements
while minimizing the volume of drilling fluid required is
to pre-drill vertical sight/relief holes along the pipeline
route. These holes are a slightly larger diameter than the
final pipe diameter and are drilled 0.6-1m deeper than
the pipeline depth; they may be lined with MDPE to
prevent collapse. During drilling the pilot stem can be
seen through each sight hole in sequence and adjustment
made to the direction and depth of the initial bore; this
results in a more-accurate installation. The sight holes also
act as relief holes for the spoil and drilling mud mixture
being pushed ahead of the pipe during the back-ream/
augur process; relieving pressure during pull-back of the
pipe reduces the risk of drilling fluid fracturing local soil
and being lost or contaminating the area. The relief of
pressure reduces the volume of mud required and allows
a tighter fit of the pipe within the hole.
Open holes
The pipeline is pulled through the bore hole lubricated
with a bentonite-based mud. After the pipeline is in
position it is usually not possible to replace the residual
mud and consequently the mud properties need to be
considered to ensure that they do not contain anything
that will exacerbate corrosion. If the bore is below the
1st Quarter, 2012
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water table then it is likely that, given time, the mud will
be permeated by the salts in the water.
Pulling the pipeline into the open hole can result in damage
to the coating if rock is present. The use of an abrasionresistant coating can reduce the coating damage but will
not obviate all damage. The extent of damage cannot
normally be estimated in advance with any reliability, but
an examination of the front section of pipeline that has
been pulled through will usually give a reliable estimate of
the coating damage. Cathodic protection will be applied to
the pipeline and the CP system can be adjusted to ensure
that corrosion is controlled.
Fig.5. Detail of the tested spool after testing.
protectiveness of mud and grout more rapidly than mildly
brackish waters. Acidic ground water, usually containing
humic acids from decaying vegetation, would also be
expected to initiate corrosion more rapidly than neutral
waters. River bed sediments may also be infested with
micro-organisms, in particular sulphate-reducing bacteria
that can flourish adjacent to pipelines because of the
evolution of hydrogen from the pipeline surface when
cathodic protection is applied.
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In both open- and cased-hole installations it may be necessary
to seal one or both ends of the hole. This would almost always
be necessary for a landfall as, without a seal, there would
be tidal movement of water in the hole. The movement of
water may be erosive as the velocity in the annular space may
be sufficiently high to carry abrasive particles and coating
damage, and consequent corrosion could be localized and
severe. Since the tides operate twice a day there are nearly
1,500 occasions for abrasion each year.
One option is to grout the pipeline in place. The cement
grout may be placed at only one end of the hole, both ends,
or the complete length of the hole grouted. Cement is highly
alkaline and the grout will provide a protective environment
around the pipe. Protective oxide layers are formed on the
surface of the pipe at areas of coating breakdown and the
oxides prevent continued corrosion. The level of protection
depends on the quality of the cover afforded by the grout and
the density and thickness of the grout layer. Though initially
protected by the alkalinity, chloride ions in the ground water
will permeate the grout and when the chloride-hydroxide
ratio falls below a critical value (2.5 – 6) the oxide layers
cease to form correctly and pitting corrosion will ensue [10].
Grout can be treated to improve its protective properties,
and the most suitable approach is to include nitrite into the
grout. Nitrite is widely used as an additive to concrete for
reinforced-concrete constructions in marine atmospheres.
The nitrite is released into the water film around the pipe
and improves the protectiveness of the oxides formed at the
areas of coating breakdown. The additional protectiveness
allows a higher chloride-hydroxide ratio before corrosion
initiates.
Though grouting the annulus is an option, there are
attendant risks. Bare areas of pipe where there is no grout
present will become anodic to the grouted areas. This issue
was first observed on reinforced-concrete gravity structures
where severe corrosion was noted on steel connected to
embedded steel. Provided cathodic protection is effective
this would not be an issue.
The nature of the water in the soil is important.
High salinity water would be expected to reduce the
Cased holes and tunnels
When there is risk of the drilled hole collapsing or of
the drilling mud being lost, the hole must be lined with
a casing. The casing may be a steel or non-metallic pipe.
Plastic pipe has been used (such as for the Minerva landfall
in Australia) though reinforced concrete is common. In
both cases the option of secondary protection of the pipe
by a remote CP system will be reduced or lost. If the hole
is of sufficient diameter, then it may be possible to pull the
pipeline through the hole with bracelet anodes installed
on the pipeline or ribbon anodes installed along or as
a spiral about the pipeline section, and this option has
been used for microtunnelled installations. The risk of
anode damage would be low for a concrete-weight-coated
pipeline but the increased weight of the pipeline could
present difficulties if the hole is of great length. There is
a general reluctance to pull a pipeline fitted with taper
anodes through a hole as the electrical connection to the
anodes might be lost or, in the worst case, the pipeline
could be damaged if the anodes twist.
With steel casings it is important that the pipeline does
not make contact with the casing as this may establish a
galvanic cell and leave section of the carrier pipe without
cathodic protection in the case where the annulus is filled
with an electrolyte for any reason. For a pipeline with a 5%
coating breakdown, because the casings are not internally
coated and the diameter is 1.5 times the pipeline diameter,
the bare area of the casing represents around 30 times
the expected bare area of the pipeline. Anodes would be
16
Environment
Resistivity (ohm-m)
Seawater
0.2 to 0.4
River water
0.3 to 1
Potable water
0.5 to 50
Loam
7 to 90
Clay
20 to 200
Chalk
20 to 200
Limestone
10 to 100
Sandstone
10 to 100
Sand and gravel
100 to 1,000
Granite
10 to 2,000
Table 1. Resistivity of soils.
rapidly depleted. Non-metallic casings do not present this
risk; however, anodes may need to be installed inside to
protect the pipeline.
necessary to increase the voltage setting of the transformerrectifier and this will reduce the potential of the pipeline
close to the groundbed. Combinations of such effects can
result in potentials close to the groundbeds becoming at or
below the coating-tolerance potential.
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Fig.6. Reduction in potential beyond a low-resistivity section.
In all cases it is required to seal the annulus either with a
mechanical plug or a grout section at the seabed end of the
pipeline or to seal the upper section of the annulus at a
level that prevents tidal movement of water in the annulus.
In some cases the complete annular space is filled either
with grout or treated drilling mud, though reliance on a
mud is less certain than using a grout.
With respect to protection, tunnels and microtunnels
may be regarded as large-diameter HDDs. A microtunnel
will be lined with a casing and will have similar issues to
a lined HDD. A tunnel through hard rock will present
similar issues to a lined HDD, with rock presenting the
high resistance to CP current flow.
Isolation from other CP systems
Sections of pipeline installed by HDD may need to be
isolated from the other sections of the pipeline, and the
need for this depends on the length of the HDD section.
A short length of open hole may be accommodated by the
pipeline’s cathodic-protection system. The requirement
should be based on an estimate of the relative cathodicprotection requirement of the HDD section. The pipeline
may be in ground of high resistivity, while the HDD section
may be through soil of low resistivity because the HDD
usually needs to go deeper. In this case, the HDD section
will require a higher current density for protection than
an equivalent length of main pipeline. Depending on the
damage to the coating and the location of the CP groundbed,
this can result in a reduction in the current available to the
section of the pipeline beyond the HDD section. A reduction
in current results in a less-negative potential on this moreremote section of the pipeline, and this is illustrated in Fig.6.
To restore the potential of the more-remote section, it will be
The HDD section of the pipeline may be isolated on one or
both sides of the HDD using flanges or a monobloc joint.
The HDD section may then be protected with a dedicated
CP system or could be protected from one of the CP systems
that are protecting the respective sections of pipeline. Test
stations should always be installed to allow periodic checks
that the isolation flange is functioning. Additional testing and
monitoring will be required for such an option.
Isolation flanges may be suitable for modest-diameter pipelines
but are less reliable for larger-diameter pipelines or those subject
to thermal or pressure cycling. If isolation flanges are used,
it is essential that they are hot boltable in the case that a bolt
isolation sleeve is damaged and allows electrical connection
across the flange. Monobloc joints are more reliable but are
also subject to fatigue. Thermal cycles appear to be the main
fatigue loading, and consequently oil pipelines are more at
risk than gas pipelines. If the pipeline carries water-wet fluids
then it will be necessary to internally coat the upstream and
downstream sections of the isolation joint to prevent current
discharge across the isolation joint due to electrical short.
Protection of pipelines in
microtunnels and tunnels
A pipeline may be left suspended on spacers or other
supports in a microtunnel or tunnel. In this case it cannot
be cathodically protected; protection will be provided by the
coating. In larger-diameter tunnels that will be flooded, or
where the annular space filled with a conductive medium, it
is possible to install sacrificial anodes in the tunnel or onto
the pipeline at sufficiently short intervals to ensure adequate
1st Quarter, 2012
Environment
17
Resistivity (ohm-m)
Effect
0.2 to 0.4
Negative
River water
0.3 to 1
Negative
Potable water
0.5 to 50
Negative
Loam
7 to 90
Negative
Clay
20 to 200
Negative
Chalk
20 to 200
Negative
Limestone
10 to 100
Negative
Sandstone
10 to 100
Negative
Seawater
Table 2. Factors related to corrosiveness of soils.
Fig.7. Options for cathodic-protection systems: isolation
landward side of landfall.
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protection. To be effective, the annular space must be filled
unless the microtunnel or tunnel is below the water table, in
which case it is possible to allow the tunnel to flood. In dry
tunnels, but where there is risk of complete or partial flooding,
CP may be installed as a back-up protection that will activate
only when there is electrolyte in the annulus. This is similar
to the protective systems used in road casings.
In this case the pipeline would be isolated from the main
section of pipeline though the interference between sacrificial
and impressed current systems will be modest, depending on
the diameter of the tunnel. To isolate the pipeline within a
tunnel requires two isolation joints and this presents some
increased risk to operation of the pipeline.
Cathodic protection
Soil resistance
In most cases the soil resistivity will be known or can be
obtained by tests on core samples. Resistivity is a good first
line indicator of the corrosiveness of soils, and a typical
listing of soil resistivities is given in Table 1. Other factors
are also relevant and these are listed in Table 2; negative
factors will make the sediment more corrosive while positive
factors will reduce risk of corrosion.
Application of CP
Cathodic protection may be applied using an impressedcurrent system or by a dedicated system specific for the HDD
section of the pipeline. At a landfall there will be a sacrificial
system installed on a submarine pipeline. There are several
configurations possible, illustrated in Figs 7 and 8. Though
feasible there is generally great reluctance to installing
isolation joints on a subsea pipeline and there would be severe
complications in achieving this. The preferred procedure is
to install the isolation joints on land in access pits to avoid
the risk of current bridging externally across the joint, and
there will need to be a test point to check the integrity of the
isolation joint. A submarine isolation joint is possible but
is generally seen as a last resort. Consequently, the options
given in Fig.7 are more likely. These all have the disadvantage
Fig.8. Options for cathodic-protection systems: isolation
seaward side of landfall.
of isolating the pipeline from the impressed-current system
on the onshore section of the pipeline.
For river crossings and landfalls a separate sacrificial system
is more common, as shown in Fig.7 Scenario D, using
sacrificial systems for the river-crossing section. There
is also the option of avoiding use of isolation joints and
accepting that there will be interference between the CP
systems. In Fig.7 scenario A the isolation joint is shown
close to the HDD; however, it may be 1-2km distant from
the landfall in some cases, as scenarios B and C. Reliance on
the submarine anodes to protect the onshore section of the
pipeline up to the isolation joint is unreliable. Submarine
sacrificial anodes can generally only protect short lengths
of pipeline in resistive soil. The better option is to apply
a separate CP system using magnesium anodes to protect
the onshore section, either using discrete spaced anodes
or an array on the seaward side of the isolation joint.
The scenarios in Fig.7 are attractive because the impressedcurrent system has flexibility and can supply adequate
18
Fig.9. Equivalent circuit of cathodic-protection system at
HDD, where:
the submerged section and the isolation joint is short then
the sacrificial CP system on the submarine pipeline may be
able to protect the section of pipeline in the HDD that was
installed without anodes. The length of pipeline that can
be protected will depend very much on the resistivity of the
ground at the landfall. Attenuation calculations for a 24-in
pipeline suggest that zinc and aluminium alloy anodes can
protect 400-500m of pipeline provided resistivity of the HDD
section is consistently low (Fig.10).
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E is the driving voltage, which for some landfalls will be the closedcircuit voltage of a sacrificial system.
RANODE is the resistance of the anode, for example calculated using
the McCoy equation for bracelet anodes. RSOIL is the resistance of the current path through the bulk soil.
RHOLE is the resistance of the current path through the HDD.
RCATHODE is the resistance of the electrochemical reactions at the areas
of coating breakdown on the pipeline.
RPIPELINE is the return path resistance through the steel of the pipeline;
this is generally low for pipelines through HDDs because of the
heavy schedule wall.
RWIRING is the resistance of the electrical cable connecting the anode
to the pipeline; in most cases this resistance is very low as the
specifications normally require the resistance to be below 0.1ohm. Fig.10. Attenuation curves for -1050mV anodes in seawater
and sediments; example of 24-in x 12.7-mm wt, 3 LPE coating.
current in the case that the installation does not go to
plan, for example where excessive coating damage occurs.
Having an isolated pit and test point on a beach may not
be convenient for many pipelines because of limited access;
it is also visually intrusive, and there is reduced security for
the pipeline.
Open-hole HDD at landfall
Low-resistance landfalls
A CP system in an HDD can be envisaged as a simple resistive
circuit, as shown schematically in Fig.9. An open-hole HDD
to accommodate the pipeline at landfall is perhaps the most
common arrangement. At this type of landfall RSOIL and
RHOLE are essentially the same or similar resistances, and
can be replaced by a single resistance. There may be some
modification of resistance in the annular space because of
drilling mud being mixed with the soil/sediment but this is
unlikely to be significant. In most cases the application of
CP will follow Scenario A of Fig.7, with the isolation joint
fitted as close to the landfall as is feasible.
The onshore section of pipeline would be protected by
the impressed-current system and the seaward side by the
submarine pipeline CP system. If the landfall section between
It may be feasible to install a weight-coated pipeline though
the HDD with bracelet anodes on the pipeline because the
concrete will protect the anodes. In this case it is important to
determine the length of pipeline that each anode can protect
and to adjust anode spacing to allow for this. If the pipeline
will be buried on a relatively flat beach where the seawater
table is high then bracelet anodes should be adequate; most
beach sediments have resistivities below 5ohm-m. One risk,
often overlooked, is not associated with the spacing of the
anodes but with the risk of anode passivation. Most submarine
pipelines are protected using aluminium alloy anodes and
these are particularly prone to passivation where they are
subject to cyclic wetting and drying.
For bracelet anodes at spacings of up to 15 joints (180m)
attenuation calculations [11] for a typical 24-in pipeline
indicated that a sacrificial CP system would be functional
for ground with resistivities up to about 20ohm-m (Fig.10).
Most CP design engineers would recommend closer spacing
of the anodes as this would also allow for the higher risk of
damage to anodes during the installation.
Using bracelet anodes is generally not favoured for pipelines
that must run for more than a nominal distance (around
1km) before the isolation joint is installed, scenario B, and
there would thereafter be protection of the onshore pipeline
by the impressed-current CP system. For this type of landfall
it is more usual to provide an array of magnesium anodes
on the seaward side of the isolation joint to augment or
provide protection to the onshore section of pipeline and
the pipe in the HDD, scenario C. There will be some slight
1st Quarter, 2012
19
Fig.11. Attenuation curves for -1600mV anodes in marine
sediments; example of 24-in x 12.7-mm wt, 3 LPE coating.
interference between the magnesium and zinc/aluminium
alloy CP systems, but this can be allowed for and tolerated.
interference between the offshore and onshore CP
systems, scenario D. This approach avoids the risk
associated with a subsea isolation joint and the
onshore system can be designed to accommodate
the section of offshore pipeline that will be affected.
An ideal protection system would supply protection current
from a dedicated system, scenarios F or G. These options
have the disadvantage that a subsea isolation joint and the
provision of power to a remote landfall are often not feasible
because of the cost and/or environmental sensitivities.
A sacrificial system using magnesium anodes is favoured,
such as a magnesium-anode array as CP3 in scenario C.
Sacrificial anode arrays are cost-effective to install and reduce
maintenance costs, though the length of pipeline that they
can protect is markedly affected by the resistivity. Discrete
anodes are effective but have a higher maintenance cost.
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An alternative to an anode array is to use individual magnesium
anodes spaced at intervals along the landfall up to the isolation
joint, a variation on scenario C, and this is a standard onshore
pipeline protection approach. The normal spacing for onshore
sacrificial anodes is 1km, but this may not be sufficient and
variable spacing may be necessary.
Fig.12. Landfall with HDD through cliff.
The use of a sacrificial-anode array, scenario C, is also attractive
for cases when a pipeline will land on a steeply rising beach or
at a cliff landfall. The resistivity of the ground will rise fairly
rapidly as the height above the beach increases. Resistivity
may shift from about 0.3ohm-m in seawater to 1-2ohm-m
on a sandy beach, to 10-20ohm-m or higher further up
the beach. A chalk or sandstone cliff may have a resistivity
above 50ohm-m and, at this resistivity, magnesium anodes
or an impressed-current CP system would be required. The
higher open-circuit potential of the magnesium improves
the distance that can be protected for a given soil resistivity
(Fig.11). Note that, for convenience and consistency, the
potentials given are all referenced to the copper-copper
sulphate reference electrode.
It is often argued that a separate impressed-current system
should be used for landfalls as there is the availability of
higher driving potentials from the system. This is correct
but the potential on the pipeline remains limited to the
coating tolerance potential which is generally around a
potential of -1600mV.
High-resistance soil landfalls
At a high-resistance landfall, the options are:
• Place the isolation joint subsea and rely on the
onshore impressed current system to protect the
majority of the pipeline at landfall, scenario E of
Fig.7. Generally not favoured because of concern
about the integrity of the subsea isolation joint.
• Fit the isolation joint on the landward side of the
HDD and use an array of anodes on the seaward
side of the isolation joint, scenario C.
• Do not install an isolation joint and accept
HDD at a steep resistive landfall
A landfall at a cliff is perhaps the most problematical of
landfalls but is often the only option to bring a pipeline ashore
where it is necessary to minimize visual impact. Figure 12
illustrates this form of landfall. Typical example would be the
Minerva, Langeled, and Browse (Australia) landfalls, though
the Langeled pipeline landfall at Easington uses a microtunnel.
There is the option of using an isolation joint at the cliff base
and protecting the section of pipe through the rock by the
onshore CP system, scenario E. The isolation joint would
be at risk of external bridging and it would be difficult, if
not impossible, to replace the isolation joint in the event
of a failure. Placing the isolation joint at the top of the cliff
has advantage but a sacrificial system is unlikely to be able to
protect a pipeline passing through resistive rock.
If bracelet or other discrete anodes are installed along the
length of the pipe through the HDD or tunnel it is necessary
to modify the normal design approach used to calculate the
attenuation of the potential. The equivalent circuit of Fig.9
is relevant here with RSOIL >>> RHOLE. Essentially the majority
of the protective current must flow through the annular space
around the pipeline. Though soil resistivity will be low in the
annulus the resistance of this path will be high because of the
constraints on the volume through which the current must pass.
20
As an example consider a 24-in pipeline passing through
a 36-in HDD cut through resistive rock; a typical coating
breakdown is 2% and the protection current density 50mA/
sqm. The HDD is plugged at the top to prevent tidal water
movement within the hole but will be flooded with seawater
of resistivity 0.3ohm-m. The resistance per unit length through
the seawater will be r x 1/A where r is the resistivity and
A the area for current flow. The resistance to current flow
would be approx. 0.8ohm/m. The closed circuit voltage for
zinc and aluminium alloy anodes is 0.25V and the distance
that current can be supplied for is about 14m. This would
indicate the need to install an anode on every other pipe
joint. For an HDD of 48-in the anode spacing improves
to around 20m, allowing one anode every three joints. An
anode array at the mouth of the HDD would only provide
current for a similar length of pipe.
References
1. N.Smith, 2010. Aspects of design and construction
relating to marine HDD installations. PetroMin Pipeliner,
26-30, Jul-Sept.
2. A.I.Williamson and J.R.Jameson, 2000. Design and
coating considerations for successful completion of a
horizontally directionally drilled (HDD) crossing. NACE
International.
3. W.Vercruysse and M.Fitzsimons, 2006. Landfall
and shore approach of the new Langeled pipeline at
Easington, UK. Terre et Aqua, 12-18, 102, March.
4. S.Ryfetten and E.Bjertness, 2001. Asgard transport gas
pipeline - new landfall solution at Kalste. Proc. 11th Int.
Offshore and Polar Engineering Conf., Stavanger, June.
5. R.Lauritzen, O.K.Sande, and A,Slatten, 1996. A
Europipe landfall tunnel. Norges Geoteknisca Inst., 1-10,
197.
6. K.Christiansen, 2006. Testing pipeline coatings for
severe construction conditions. 23rd World Gas Conf.,
Amsterdam.
7. ASTM. D-4541, Standard test method for pull-off
strength of coatings using portable adhesion testers.
8. Private Communication, Saudi Aramco Pipelines
Department, Dhahran, 2012.
9. Confidential Report, Saudi Aramco Pipelines
Department, Dhahran, 2012.
10.K.Thangavel and N.S.Rengaswamy, 1998. Relationship
between chloride/hydroxide ratio and corrosion rate of
steel in concrete. Cement and Concrete Composites, 281-92,
20 (4), and also NACE Resource Centre: Corrosion –
Concrete.
11.ISO 15589-2: Petroleum and natural gas industries cathodic protection of pipeline transportation systems,
Part 2: Offshore pipelines.
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Using a magnesium array increases the protected length,
but not by much. For the 36-in HDD, the distance would
be about 24m, and for the 48-in HDD it would be about
36m. It is clear that achieving adequate CP potentials for
a long HDD may be difficult and reliance must be placed
on quality of coating and reducing the corrosiveness of the
environment around the pipe. Grouting appears to be the
favoured option for protection of a pipe in an open hole
HDD where the resistivity is high.
the establishment of microbial corrosion cells, in particular,
because of the likely presence of sulphate, and the activity
and growth of sulphate-reducing bacteria. Grout clearly has
advantage because of the creation of alkalinity around the
pipe and because it is not biodegradable.
Closed-hole HDDs and tunnels
When a casing is installed through the HDD the application
of cathodic protection would be restricted in a similar way
to the case of an HDD through resistive rock. Tunnels are
also sealed systems, though the greater width of the tunnel
would permit use of cathodic protection when the tunnel
was flooded.
The casing in an HDD or tunnel provides a more-reliable
method of isolating the environment around the pipeline.
The use of grout or treated drilling mud should be able to
prevent corrosion over the long term if they are formulated
correctly. The main risk to the enclosed pipeline would be
1st Quarter, 2012
21
Enbridge Northern pipeline:
25 years of operations,
successes and challenges
by Ingrid Pederson*1, Millan Sen1, Andrew Bidwell2, and
Nader Yoosef-Ghodsi3
Enbridge Pipelines Inc., Edmonton, AB, Canada
AMEC Earth & Environmental, Calgary, AB, Canada
3
C-FER Technologies, Edmonton, AB, Canada
1
2
E
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NBRIDGE PIPELINES HAS operated a 324-mm (12.75-in) diameter, 869-km long, crude oil pipeline from
Norman Wells, Northwest Territories, to Zama, Alberta, since 1985.This pipeline is the first completely
buried oil pipeline constructed within the discontinuous permafrost zone of Canada. This pipeline was
constructed over two winter seasons, and since 1985 has transported roughly 200 million barrels of crude
oil to southern markets without significant interruption.
This paper reviews the design, construction, and operational challenges of this pipeline through the past
25 years. Unique and innovative aspects of this pipeline include measures taken during construction to
minimize thermal disturbance to the soil, insulating permafrost slopes to minimize post-construction thaw,
operating at temperatures that minimize thermal effects on the surrounding ground, accommodating ground
movement caused by frost heave/thaw and slope instabilities, and evaluating the effects of moving water
bodies adjacent to the pipeline right-of-way. The use of in-line inspection tools (Geopig) has been valuable
as a supplement to conventional geotechnical monitoring for the evaluation and assessment the effects of
ground movement to the pipeline. Finite-element pipe-soil interaction models have been developed for
selected sites in order to assess the potential for slope movement to generate strains in the buried pipeline
that exceed the strain capacity.
New monitoring data and findings since previous publications are also reviewed. In addition, the implications
of long-term trends of increasing ground temperatures and associated changes to the geotechnical and
permafrost conditions along the pipeline route will also be discussed and are relevant to other proposed
pipeline and linear infrastructure projects along the Mackenzie Valley.
T
HE NORMAN WELLS PIPELINE is the first pipeline
to be fully buried in the permafrost regions of North
America. The 869-km long pipeline was constructed
over the 1983-1984 and 1984-1985 winter seasons, and
has been in operation since April, 1985. The effects of
discontinuous permafrost on a pipeline are different from the
geotechnical conditions experienced by more typical North
American pipeline routes. Some of the resulting additional
considerations that are evaluated during operation of a
northern pipeline include frost heave, thaw settlement,
This paper was first presented at the International Pipeline Conference held in
Calgary in 2010, and is published by permission of the organizers.
tel: +1 780 420 8522
slope instability, and forest fires affecting the ground thermal
conditions along the right-of-way.
One of the key design considerations is the operating
temperature of the pipeline. In consideration of the
temperature of the permafrost soil, the crude oil is chilled
leaving the oil processing facilities at Norman Wells before
entering the pipeline. The low viscosity of the oil allows for
flow at very low temperatures; during the warmer periods
in the year warmer oil is transported without impacting
pipeline performance. This is offset by greater chilling
of the oil during the non-summer months in order to
minimize the net effect on the ground thermal conditions
along the first 50-60km of the pipeline that are affected by
variations in the input oil temperature. Variations in the
input oil temperature attenuate with distance from Norman
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22
Fig.1. Slope 11 in 1984 during construction, and in 2009.
Wells: beyond the first 50-60km, the pipeline operates as
an ambient-temperature pipeline with the oil temperature
varying in step with natural variations in the surrounding
ground temperature.
A large number of slopes along the Norman Wells right-of-way
were initially considered subject to instability, and mitigation
measures were employed to ensure pipeline integrity for the
expected operating life. Many slopes were provided with
insulation in the form of wood chips to retard the postconstruction thaw of ice-rich permafrost soils, which would
otherwise be expected due to the changes in ground cover
and the loss of natural insulation from the organic layer and
vegetation along the right-of-way that occurred during the
pipeline construction. The wood chips have proven effective
beyond their original design. Much of the pipeline right-ofway followed pre-existing cut lines to reduce the amount of
disturbance along the route. Figure 1 shows the graceful ageing
of slope 11, Heleva Creek North. Thaw behaviour along the
right-of-way has been consistent with the historical data that
was gathered in the 1970s and early 1980s in support of the
initial design [1].
The challenges of building and operating the pipeline are
documented in the paper IPC2002 – 27357 Right-of-way and
pipeline monitoring in permafrost [2]. Early efforts to restore
original conditions included some major maintenance activities
in the first five years of operation: ditch subsidence greater
than 200mm was backfilled and settlement surveys performed,
additional rock rip-rap was placed at selected watercourses,
the right-of-way was reseeded and revegetated, woodchip hot
spots were cooled, and right-of-way brushing were some of the
maintenance activities performed. The restoration programme
was determined to be successful and minimal rework has
been required. Since 1989, ditch subsidence has become an
insignificant issue [2].
When the Norman Wells pipeline was designed there was a
limited body of knowledge and experience available, although
it was known that gas pipelines that had been constructed in
northern Russia earlier were experiencing problems because
permafrost conditions had not been considered. Accordingly,
the design criteria for the Norman Wells pipeline incorporated
a limit-states’ design to accommodate the variety of groundmovement conditions expected along the permafrost locations
of the right-of-way. This approach allowed the pipeline to
exceed its yield strength under certain external loads while
remaining within safe operating limits. The strain limit was
set at a conservative 0.5%, although subsequent tests on the
pipe have revealed it is capable of much higher strain limits.
An in-line inspection tool has been developed that accurately
measures pipe position and curvature. Using this tool the
strain levels of the pipe subject to movement can be compared
to the design limits. The inertial inspection runs, performed
annually, are used as the primary monitoring tool for changes
in pipe condition.
Ground temperature response
to pipeline construction and
operation
The design of the pipeline considered the thermal effects of
right-of-way clearing, pipeline construction, and the operation
on permafrost slopes along the pipeline route. The
1st Quarter, 2012
23
Permafrost
Continuous
Extensive discontinuous
Sporadic discontinuous
Mountain
Known subsea
Ice caps
oct oct oct oct oct oct oct oct oct oct oct oct oct oct oct oct oct oct oct oct oct oct oct oct oct
84 85 86 87 88 89 90 91 92 93 94 95 96 97 98 99 00 01 02 03 04 05 06 07 08
Fig.3. Permafrost distribution along the pipeline route.
permafrost slopes along the route were categorized by soil type
and soil ice content. Below the cut-off angles for frozen slopes,
mitigation against the thermal effects of pipeline construction
and operation was not necessary in order to have the required
slope factor of safety, as described in Ref.1. Where required,
the primary thermal mitigation measure for permafrost slopes
was surface insulation via a layer of wood chips placed on the
right-of-way slope after installation of the pipeline. The wood
chips were intended to insulate the ground along the right-of-way
with an overall design intent to permit long-term thawing of the
right-of-way slopes but to retard the thaw rate and prevent rapid
thawing. This was conducted because, under a rapid-thawing
scenario, it was expected that high piezometric pressures could
develop in the slopes due to free water from the thaw of ground
ice not draining freely from above the thaw front. This would
create a situation of potential slope instability.
of seasonal thaw at their locations due to the changes in the
ground thermal conditions by clearing of the right-of-way and
construction/operation of the pipeline. The seasonal thaw
depths at these sites would also be affected by climate change:
however, the magnitude and timing of such affects are not
known with certainty.
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Fig.2. Example of a thaw-depth plot along the right-of-way.
Oswell and Skibinsky [1] present a detailed discussion of
factors influencing the thaw behaviour of the slopes along the
pipeline right-of-way. Since pipeline construction, continuing
monitoring has been performed by thermistor cables installed
in both insulated and non-insulated slopes, combined with biannual physical probing to estimate the seasonal thaw depths
at selected sites along the right-of-way. This monitoring has
shown that the thaw behaviour of slopes along the right-of-way
has been generally consistent with historical data used in the
design of the pipeline. The effect of ‘pre-clearing’ of segments
of the Enbridge right-of-way that follow cut lines that pre-date
the Enbridge pipeline has been noted as being particularly
important in estimating post-pipeline-construction thaw depth.
In addition to the ground-temperature data from slopes along
the right-of-way, thermistor cables installed in uninsulated
upland area segments of the right-of-way provide data relevant
to broader research by the Geological Survey of Canada (GSC)
and its collaborators on ground temperature and permafrost
conditions along the Mackenzie Valley and other areas in
northern Canada. This includes modelling of the thermal
response of permafrost terrain to right-of-way disturbance
and climate warming [3]. Figure 2 shows a plot of groundtemperature data from two such thermistors installed along the
right-of-way at sites between Norman Wells and Tulita, NT. The
data from both thermistors clearly show long-term deepening
The data from these instruments are part of the continuing
monitoring and surveillance programme for the right-of-way
to ensure the safe operation of the pipeline and protection
of the environment.
Pipeline strain conditions
Due to the discontinuous permafrost ground conditions of the
Norman Wells Pipeline route as described in Fig.3, the difference
between the product temperature and ground temperature can
lead to the degradation of permafrost or, alternatively, to ground
freezing where the ambient temperature pipeline crosses a
frozen-unfrozen boundary in ground conditions along the route.
Such changes in the ground thermal conditions can result in
ground movement and associated strains and deformations of
the pipeline. These geotechnical loading conditions are unique
to pipelines within a northern environment.
In regions with fine-grained frozen soils, the melting of the
ice within the ground from either warming environmental
conditions, or downstream of an unfrozen-to-frozen ground
transition along the pipeline route, can cause thaw settlement
of the soil around the pipeline (as the volume of ice decreases
during melting). As this settlement is not uniform along the
pipeline route, bending strains may be induced in the pipeline.
Correspondingly, freezing of saturated fine-grained soils during
the winter months, or pipeline downstream of a frozen-tounfrozen ground transition along the pipeline, can cause ground
uplift conditions. If these fine-grained soils are located between
regions of large-grained soils (which will exhibit reduced frost
heave due to well-drained conditions), the uplift displacements
along the pipeline can occur over a relatively short length.
Finally, in regions where the pipeline traverses a slope, seasonal
ground thawing or thawing of permafrost can result in excess
24
84-1
84-2
84-3
85-7
84-4
85-8
Fig.4.The Geopig ILI tool.
pore-water pressures developing in the slope. These porewater pressures can lead to slope movement, and this can
generate significant axial and bending loads on the pipeline
buried within the slope.
85-11
85-19
84-5
84-6
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If the ground movement of the pipeline induces strains to
the pipeline that are sufficiently large, the strain capacity of
the pipeline can be exceeded. This would cause wrinkling
of the pipeline on the compression side of the pipe, or
alternatively tensile fracture could occur on the tensile side of
the pipe. The compressive-strain and tensile-strain capacities
of the Norman Wells pipeline have been evaluated using
a combination of full-scale testing and analytical methods.
The formation of wrinkles has occurred at various locations
along the pipeline, and there have been no tensile failures.
85-9
85-10
85-12
Pipeline strain monitoring
The primary method to mitigate the pipeline strain
threat along the Norman Wells pipeline route is through
measurements provided by the Geopig in-line inspection
(ILI) tool as shown in Fig.4. Since 1989 it has been run
annually from Norman Wells to Wrigley, from Norman
Wells to Mackenzie every second year, and from Norman
Wells to Zama every fourth year: these locations are shown
in Fig.5. The northern end of the pipeline is inspected more
frequently because of the greater proportion of permafrost
ground in that area relative to the portion of the pipeline
south of Wrigley. The tool runs are generally conducted in
September to roughly correspond to the timing of maximum
seasonal ground thawing.
The caliper arms of the Geopig tool have the capability of
detecting and sizing radial-direction pipe-wall anomalies,
including dents, ovalities, and wrinkles. Based on the
Geopig measurements denting is relatively infrequent: there
is an average of only one reported dent per 35km over the
entire 869-km pipeline route. This low frequency is because
the pipeline route does not traverse rocky terrain. Ovalities
are also infrequent: there were only two ovalities reported
over the entire pipeline route. Ovality deformations that
coincide with areas of high strain are further scrutinized, as
a pipe section ovalization may precede wrinkling. Over the
past 25 years, six wrinkles have been detected by the caliper
arms of the Geopig, and these wrinkles were immediately
assessed and repaired as required.
Fig.5. Norman Wells stations.
The Geopig also contains a strap-down inertial-navigation
system (INS) that is able to provide the precise position of the
tool in global-positioning system (GPS) coordinates. As the
tool fits tightly against the pipe wall, the precise horizontal and
vertical profile of the pipeline centreline can be determined,
and the pipe bending strain is subsequently calculated directly
from the curvature of the Geopig trajectory. The positional
precision of this tool is dependent on the distance between
the tie points during the inspection run: for the 2009 Normal
Wells pipeline Geopig run, the positional accuracy was ±25mm.
In addition, the pipeline profiles from the annual Geopig runs
are compared with one another. This run-to-run comparison
compares the pipeline curvatures in areas where there are
changes in the pipeline profile at the same location of the
compared runs. From these changes in curvature, the pipeline
strain differential between the runs is calculated. The bending
strain is generally averaged over a length of three pipeline
diameters, and is accurate to within ±0.02% strain.
All pipeline locations along the Geopig run are analyzed for
vertical strain. Any locations along the pipeline route that
exhibit a strain differential of greater than 0.3% between
the run year and the first run in 1989 are noted as an area of
interest. In addition, locations that exhibit a consecutive run
strain difference greater than 0.15% are also noted as an area
of interest. These strain limits are considerably below the strain
capacity of the pipeline. In 2009 there were 60 areas of interest
locations between Norman Wells and Wrigley. Strain locations
that do not meet the strain-reporting criteria are also considered
to be an area of interest if the geotechnical monitoring and
inspections indicates actual or potential ground-movement
conditions. Area of interest locations are further scrutinized
through analysis and site investigations as required.
1st Quarter, 2012
25
Dec Dec Dec Dec Dec Dec Dec Dec Dec Dec Dec Dec Dec Dec Dec Dec
95 96 97 98 99 00 01 02 03 04 05 06 07 08 09 10
Fig.6. Elevation survey data from uplift site.
Fig.7. Slopes 44 and 45.
Two sites downstream of the Norman Wells pump station
experienced an uplift of the pipeline shortly after a revised
temperature restriction on crude oil receipts at the Norman
Wells station was instituted in 1993 in order to allow warmer
temperatures during the summer months. As described in
Doblanko et al. [2], a review of the Geopig data for these
sites showed that the pipe strain levels at these locations
did not exceed the maximum design limit.
In recent years, the plot of the survey data has become ‘noisy’
due to less-frequent readings between 2003 and 2008. However,
a long-term attenuating trend of reduced pipe uplift from 1997
to 2009 is evident. This site, along with the second pipe uplift
location that was similarly mitigated, continue to be part of
the continuing monitoring programme and are assessed on
an annual basis. The Geopig data for these sites since 1993
have not shown any significant pipe strains or deformations.
A physical survey of the elevation of reference points along
the top of the pipeline was initiated to monitor the pipe
elevation with greater frequency than that annual Geopig
runs. Figure 6 illustrates the pipe movement at one of the
reference points from November 1996 to November 2009
and is an update of the same plot with data up to 2001
shown Ref.2. This plot shows that the mitigation measures
implemented in December 1997 (burial of the uplifted
segment with select borrow material) remained effective
in suppressing the continuous upward movement of the
pipeline at this location between 1993 and mid-1998;
however, seasonal upwards/downwards movements are
still evident in the survey data.
Pipe strain assessment
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Pipeline uplift monitoring
Fig.8. Slopes 44 and 45 estimated slip-plane surfaces.
At slopes 44 and 45, which are adjacent slopes that are located
on either side of an unnamed creek as shown in Fig.7, there
has been considerable slope movement recorded by the slope
inclinometers that have been installed at the site (in the order
of 100-140mm over a five to seven year monitoring period).
These large slope movements are judged to be primarily due
to increased thaw depth on the slope and associated increase of
pore-water pressures near the thaw front. The increase in thaw
depth is largely attributed to the clearing of the pipeline right-ofway first as a cut line that pre-dated the Norman Wells pipeline,
and then for the subsequent construction and operation of the
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Fig.9. Strain comparison between model and Geopig for slope 44.
pipeline. Regional warming trends in recent decades may also
be a contributing factor. The geotechnical assessment of the site
was that the steady ground movements would continue for the
foreseeable future; however a rapid, large-magnitude, increment
of ground movement could not be ruled out with certainty.
This possible rapid large-magnitude slope movement could
potentially cause the pipeline to experience longitudinal strains
that are beyond its strain capacity, and this could cause either
wrinkling or tensile failure of the pipe along the slope, and
a possible loss of containment. Accordingly, an engineeringcritical assessment (ECA) was conducted which assessed the
effect of a large-magnitude slope movement on the structural
integrity of the pipeline, using a large-displacement, non-linear,
pipe-soil interaction analysis using the ABAQUS software
package. The results of the analysis evaluated the strains that
would be induced to the pipeline if there was a mass soil
movement, and thereby assisted in the decision of whether or
not costly mitigation measures would be warranted to eliminate
the potential for large-scale slope movement at the site.
During a ground-movement event, the relative motion between
the pipeline and surrounding soil subjects the pipeline to
lateral and axial forces, and this pipe-soil interaction at slopes
44 and 45 was modelled through a series of soil springs. The
force displacement behaviour of the soil springs was based
on the estimated soil strength at the slope site. Different
soil-spring strengths were modelled in the downward-vertical,
upward-vertical, horizontal, and axial directions. The ultimate
soil strength and the displacement required to mobilize
the ultimate strength in each direction were based on the
methodology provided in the ASCE Guidelines for the design
of buried steel pipe.
The ground profiles of the slopes were based on survey
measurements that were taken at the site. The estimated
slope-movement slip surface was based on the slope
inclinometer data, the ground profile, and available
information on the soil conditions. As described by the
moving ground-boundary line in Fig.8, the estimated slopemovement surface consisted of a circular/translational
surface roughly corresponding to the depth of thaw
along the slope, with a scarp daylighting around or
slightly behind the slope crest. There was also a toe thrust
daylighting around the creek, with the slope movement
being accommodated by deformation of a hypothesized
talik1 of unfrozen soil around and below the creek channel.
The magnitude of the estimated slope movement was
based on the slope-inclinometer data: both the estimated
current slope movement, and estimated worst-case largemagnitude sudden slope movement, conditions were
analysed in the model.
The pipeline was modelled as a continuous structural
beam in which pipe elements that were one-diameter long
were used to represent the pipe wall. The model material
stress-strain behaviour was based on pipe material coupon
results, and the pipe geometry along the slope was based
on the Geopig profile measurements.
1. A talik (from the Russian verb tait, to melt) is a layer of year-round unfrozen
ground that lies in permafrost areas. In regions of continuous permafrost, taliks
often occur underneath shallow thermokarst lakes and rivers, where the deep
water does not freeze in winter, and thus the soil underneath will not freeze
either. Closed, open, and through taliks are distinguished, depending on whether
the talik is completely surrounded by permafrost, is open to the top (such as
in a thermokarst lake), or open to both top and unfrozen layers beneath the
permafrost, respectively [6].
1st Quarter, 2012
27
Fig.10. Sleeve 1 with collar and wrinkle 2 at slope 84.
The strain capacity of the pipeline was determined using
analytical methods. The compressive strain capacity was
calculated using validated critical buckling strain equations
that were generated at the University of Alberta. The tensile
strain capacity was calculated using the Tier 2 approach
suggested in Annex C of CSA Z662-07 [5]. Sensitivity analyses
were conducted on the strain capacity using various material
mechanical properties and estimated pipe imperfections.
Fig.11. Pipe replacement at slope 84.
Wrinkle mitigation
The resulting maximum strain along the pipeline was output
from the model. The estimated strain demand under the
current slope movement condition was compared to the
strain profile from the Geopig. As shown in Fig.9, reasonable
correlation was achieved.
In order to provide a permanent repair solution, all four
wrinkles were cut out in 2007, and a 110-m section was
replaced with heavy-wall pipe, as shown in Fig.11. This
replacement section was sufficiently long to replace the
high-strain areas along the slope.
In order to assess the integrity of the pipeline in the event of
a sudden large-magnitude slope movement, it was necessary
to compare the expected strain demand with the strain
capacity. The strain capacity was dependant on the internal
pressure, whether the pipe is heavy-wall, linepipe, or contains
girth welds. Accordingly, the peak strains at these locations
were tabulated based on the ABAQUS results. As shown
in Fig.9 for slope 44, the peak strains occurred within a
region of heavy-wall, and further study demonstrated that
the strain peaks occurred away from girth-weld locations.
This was also the case for the slope 45 analysis. The pipe
strain capacity of the heavy-wall sections at these slopes was
approximately 3%. When the peak strain demands at the
heavy-wall, linepipe, and girth welds were compared to their
respective strain capacities, for the various loading conditions,
it was determined that it is extremely unlikely for the strain
capacity of the pipeline to become exceeded if there was a
sudden large-magnitude slope movement.
This pipe replacement served to relieve the strains along the
pipeline at slope 84 that were caused by the moving slope.
Review of the Geopig bending-strain comparison between
the 2006 and 2007 runs indicated that the strains at this
location reduced to zero following the pipe replacement,
confirming that stress-relieving had occurred during the
pipe replacement. This slope is currently closely monitored
using visual inspection, on-site instrumentation, and in-depth
review of the Geopig data.
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The pipe models were loaded with internal pressure
conditions that varied between 50 – 100% of the maximum
operating pressure. The temperature loading of the models
was based on the estimated installation temperature and
product temperature at the site. The slope movement was
modelled by applying horizontal and vertical loading to the
pipe that was based on the slip-plane direction and estimated
maximum slope-movement magnitude.
At slope 84 within the permafrost region between
Normal Wells and Wrigley, a wrinkle was detected by the
Geopig and repaired in 1999 using a pressure-containing
sleeve. In 2003 another wrinkle was detected, with both
wrinkles located at the bottom of a valley slope near a
creek. Figure 10 shows, from left to right on the pipe,
the first sleeve installed, the collar for the first sleeve,
and the second wrinkle prior to a second sleeve repair in
2005. Subsequently in 2006 third and fourth wrinkles
were detected at this site. This information indicated
that the compressive strain capacity of the pipeline along
a significant length of the pipe section was becoming
exceeded. As the ground movement at slope 84 would
increase with time, additional wrinkles outside of the
sleeve locations could be expected.
Summary
Along with the regular monitoring and surveillance
programme of the Normal Wells pipeline there are several
specific sites with geotechnical issues that are monitored
with additional instrumentation. These are subject to a
greater level of scrutiny within the monitoring programme,
based on conditions and assessments in the years since
the pipeline was constructed. These sites include slopes
44, 45, and 84, along with the pipeline uplift location
that were described here.
The Norman Wells pipeline has been successfully and
effectively operated for 25 years without significant
interruption. This has been conducted amid initial
concerns of excessive ground settlement, slope
movement, cover settlement, and environmental impacts.
The combination of experienced maintenance staff,
engineering professionals, and regular dialogue with
Regulatory agencies and stakeholders, has supported
this successful operation. Modern and flexible pipelinemonitoring programmes are key components in ensuring
the safety and integrity of this northern pipeline system.
The successful operation of the Norman Wells pipeline
has encouraged the progression of additional northern
pipelines such as the Mackenzie gas project and the
Alaska pipeline project.
References
1. J.M.Oswell and D.Skibinsky, 2006. Thaw responses in
degrading permafrost. Int. Pipeline Conf., ASME (OMAE
Division), Calgary, September, Paper IPC2006-10616.
2. R.M.Doblanko, J.MOswell, and A.J.Hanna, 2002.
Right-of-way and pipeline monitoring in permafrost
- the Norman Wells pipeline experience. Ibid., Paper
IPC2002-27357.
3. S.L.Smith and D.WE=.Riseborough, 2010. Modelling
the thermal response of permafrost terrain to right-of-way
disturbance and climate warming. Cold Regions Science
and Technology, 60, 1, January, pp 92-103.
4. S.L.Smith, M.M.Burgess, and D.W.Riseborough, 2008.
Ground temperature and thaw settlement in frozen
peatlands along the Norman Wells pipeline corridor,
NWT Canada: 22 years of monitoring. 9th Int. Conf. on
Permafrost. Eds D.L.Kane and K.M.Hinkel. Institute of
Northern Engineering, University of Alaska Fairbanks,
2, pp1665-1670.
5. CSA, 2007. Standard, Z662-07: Oil and gas pipeline
systems. Mississauga, Canadian Standards Association,
pp356-384.
6. Wikipedia.
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Looking forward
The inspection and maintenance of the pipeline after 25 years
of operation has been dominated by routine activities, such as
thaw-depth investigations, visual patrols, site reconnaissance,
instrumentation readings, and in-line inspections. However,
new measuring instruments and areas of interest are activated
as they are required. It is important to implement living
northern pipeline monitoring programmes, especially with
the potential climate-change impacts along the right-of-way.
Enbridge has collaborated with the Canadian government
since the mid-1980s in geotechnical, permafrost, and
terrain-monitoring studies along the Norman Wells
pipeline. In addition, GSC has studied five frozen peatland
sites in the vicinity of the pipeline. These observations
have supported a study on the long-term evolution of the
thermal regime and ground movements associated with
thawing of peatlands from pipeline construction and
operation, and climate change. The results of this study
have indicated that warmer climate changes have been a
factor in the thawing of the thinner layers of permafrost
in northern Canada [4].
Due to these warming environmental conditions, there
has been widespread thaw deepening in upland areas, and
this can potentially cause groundwater seepage discharge
along valley slopes, which would act to destabilize some
slopes. Slope inclinometers have been installed at these
sites prior to this expected slope movement, in order to
capture the full magnitude of the future ground movement.
Bibliography
1. AMEC Earth & Environmental, 2009. 2008 stability
assessment report Norman Wells – Zama pipeline.
Enbridge internal report.
2. C-FER Technologies, 2009. Structural analysis of Norman
Wells pipeline for potential failure of slopes 44 and 45
at KP 133. Enbridge internal report.
1st Quarter, 2012
29
Use of lighter backfill materials
for delaying dent repair
by Abu Naim Md Rafi, Halima Dewanbabee, and Prof. Sreekanta Das*
Centre for Engineering Research in Pipelines, University of Windsor, Windsor, ON, Canada
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OCK DENTS ARE common defects found in onshore buried pipelines.The pipeline operator becomes
concerned if such dents are diagnosed in its pipelines since dents pose a threat to the structural integrity
and safety of the pipeline. Current pipeline standards and codes provide dent-assessment guidelines based
on dent depth, which is usually limited to 6% of the outer diameter of the pipe.These codes and standards
recommend removing a dent if its permanent depth exceeds the limit of 6%. Pipeline operators may use
their own guidelines to decide whether or not a dent needs to be repaired or replaced. However, repair
and replacement operations for a dent are costly affairs since they require mobilization of maintenance
crew and heavy equipment at the location of the dent which may not have an easy access. In addition, the
pipeline operation may need to be pushed for an unscheduled and undesirable shutdown, resulting in a
loss of revenue.
This project was undertaken to develop a cost-effective and less-troublesome dent-management approach
called ‘do-a-little’ approach that will allow the pipeline operators to strategically delay the repair and
replacement operation of a dent while still ensuring the structural safety of the pipeline.
T
HE OIL AND GAS INDUSTRIES in North America
use steel pipelines as the primary mode for transporting
natural gas, crude oil, and various petroleum products. In
Canada alone, about 700,000km of energy pipelines are in
operation [1]. A real threat to the structural and operational
integrity of oil and gas transportation pipelines is created
by the formation of defects caused by external interference,
which can produce defects in the form of cracks, punctures,
dents, gouges, or a combination of these defects. These
defects are often termed as mechanical damage and are
the primary causes of pipeline ruptures. A rupture can
cause explosion and fire, human and/or animal injuries
and casualties, damage to the environment, and a huge
loss in revenue for the pipeline operator. One of the major
types of mechanical damage is the formation of a dent
defect in the pipe wall. A dent is an inward permanent
plastic deformation of the pipe wall which causes a gross
distortion of the pipe cross section, and it can form due
to many reasons. Onshore pipelines are often subjected to
transverse loads, often concentrated on a small area of the
pipe wall, and as a result a dent can form. Dents can also
form due to transverse loading from the impact of excavating
equipment. However, the most common dent in a pipeline
is the rock dent which forms in the buried pipeline if resting
on a rock for a considerable period (Fig.1). The rock is a
hard surface and hence it provides a concentrated reaction
tel: +1 519 253 3000 ext. 2507
Fig.1. Field pipe on a rock after removal of backfill.
force on the pipe wall equal to the weight of backfill material
and self-weight of the pipe segment. A plain dent is one
when no other defect, such as a crack, gouge, or corrosion,
exists in the dent.
The pipeline operator becomes concerned when its inline
inspection tool detects a dent in one of its pipeline. Then the
operator needs to decide if the pipeline can be left operating
or if remedial action such as repair or replacement of the
damaged section of the pipeline needs to be undertaken.
It is understood that pipeline operators may use their own
guidelines and/or use the general guidelines available in
various pipeline standards and codes [2-5] to take such a
critical decision. Most pipeline standards and codes consider
the dent depth is the only parameter for analysing the
severity of a dent. Depending on the severity of the dent,
30
Specimen
Parameter and range
Dent shape, size, and depth
Number
Name
Pressure
1
C50P20D11
0.2py
2
C50P40D11
0.4py
3
C50P60D11
0.6py
4
C100P20D11
0.2py
5
R100P20D11
6
R200P20D11
7
R300P20D11
8
R400P20D11
9
C50P40D13
Rectangle
(length in mm)
Circular
(dia in mm)
Total depth
Unloading
operation
(Yes or No)
50
Not applicable
50
50
100
100
200
0.2py
300
11
No
13
Yes
Not applicable
400
0.4py
Not applicable
50
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Table 1. FE parameters.
the pipeline operator may chose a ‘do-nothing’ approach
and let the pipeline remain in operation until the dent
becomes severe enough to pose an imminent threat to the
pipeline’s structural safety. On the other hand, a pipeline
operator may chose to take costly remedial action which
could be either to repair or replace the dented section
depending on the severity of the dent. The ‘repair’ option
requires excavating the soil or backfill material above the
dented segment of the pipe and installing a steel sleeve
or other strengthening materials around the dent. The
‘replacement’ option requires excavating the soil or backfill
material above the dent and replacing the dented segment
of the pipe with a new pipe piece. It is obvious that repair
is a cheaper alternative than replacement, though repair
could also cost millions of dollars depending on the
accessibility of the pipeline where the dent has formed
and the time of the year when the repair needs to be
undertaken. Therefore, this project was undertaken to
develop a delaying option called the ‘do-a-little’ approach
that allows the pipeline operator to strategically delay the
repair or replacement of a plain rock dent, thus delaying
the disruption in pipeline operation.
The same test procedure was used for both pipe specimens.
First, the pipe specimen was filled with water and pressurized
using an air-driven hydrostatic pump to the desired
pressure level. Next, a monotonically increasing denting
load was applied using the displacement-control method
while keeping the level of internal pressure unchanged.
The internal pressures for these two specimens were 0.2py
and 0.4py, where py is the internal pressure that causes
yielding of pipe material in the circumferential direction.
The monotonically increasing quasi-static denting load was
applied through an indenter mounted on a universal loading
actuator (Fig.2). The denting load and dent-displacement
data from the tests were obtained through the load cell and
displacement transducer (LDVT) attached to the loading
actuator, and internal pressure was controlled through a
pressure transducer attached to the pipe specimen. The
denting load-deformation data obtained from these two
tests are shown in Fig.3, which also shows the similar loaddeformation behaviour obtained from the finite-element
(FE) models which will be discussed later.
Test procedure and results
The finite-element model was developed using a commercially
available general-purpose finite-element code, and the test
data were used to validate the model. The model was then
extended to study the effect of parameters such as dent depth,
dent shape, unloading of primary load, and internal pressure.
The objective was to develop a cost-effective solution scheme
that pipeline operators would be able to use to delay the
repair or replacement work of a dented pipeline in the field.
Two full-scale denting tests on 30-in (762-mm) nominal
diameter X-70 grade steel pipes with diameter-to-thickness
ratio of 85 [6] were undertaken in the structures’ laboratory
of the Centre for Engineering Research in Pipelines (CERP)
to obtain the denting load-deformation behaviour of this
pipe under two different internal pressures. The schematic
of the test set-up is shown in Fig.2: a rectangular indenter
was used to produce a rectangular-shaped dent in the pipe
wall; the length and width of the indenter were 100mm
and 65mm, respectively.
FE model development
A four-node quadrilateral doubly symmetric shell element
with reduced integration was chosen for simulation of the
pipe specimen. Each node of this shell element has three
1st Quarter, 2012
31
Fig.3. Denting load-deformation behaviour.
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Fig.2. Schematic of test setup.
Fig.4. Finite element model.
translational and three rotational degrees of freedom.
It considers finite membrane strain formulation and is
able to account for the effect of plate and shell thinning
as a function of in-plane deformation. The indenter was
modelled using eight-node solid elements. The boundary
conditions were chosen such that they simulate boundary
conditions similar to the test specimens. Both material and
geometric non-linearities were chosen, since large plastic
deformations and changes in the shape of the pipe wall were
observed in the test specimens. The loading steps applied
to the FE models were identical to those applied in the
test specimens, and a typical pipe model used in this study
is shown in Fig.4. It should be noted that a half-pipe FE
model was used to save computational time. The denting
load-dent deformation obtained from the FE models of
the test specimens are shown in Fig.3, which shows that a
good agreement between the test specimens and FE models
was obtained.
Dent-management scheme
A numerical technique using the finite-element method was
used for further analyses and development of a cost-effective
solution scheme that pipeline operators can adopt for dent
management. Table 1 shows the numerical specimens
(models) considered in this study and the parameters chosen
Fig.5. Effect of pressure on load-deformation behaviour.
Fig.6. Effect of dent shape on load-deformation behaviour.
in the FE analyses. All the specimens were analysed for a
total dent depth of 84mm (approximately 11% of the pipe’s
nominal diameter) or a higher value. Current pipeline codes
and standards allow a maximum permanent dent depth of
6%, which translates to a total dent depth of about 11% for
this pipe. A unique name was assigned to each numerical pipe
specimen to highlight the values of various parameters chosen
for this model: for example, C100P20D11 indicates that a
circular dent of 100mm diameter (C100) was introduced
in this specimen with an internal pressure of 0.2py (P20)
32
rock from the weight of backfill soil and the pipe, and the
internal pressure develops from the operating pressure of
the pipeline. Hence, this figure suggests that the higher
the operating pressure, the stronger is the pipe when it is
subjected to a denting load. Thus, this study finds that it is
beneficial to operate the pipe at a higher internal pressure
if a dent has formed in the pipeline.
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Fig.7. Effect of dent length on load-deformation behaviour.
Two different dent shapes were modelled and analysed:
rectangular and circular dents. This study shows that the
dent shape also has a significant effect on the denting loaddeformation behaviour and denting load carrying capacity.
For example, at a total dent depth of 11% and internal
pressure of 0.2py, the load-carrying capacity of this pipe
increases by about 34% if the shape of dent changes from
circular to rectangular: in Fig.6, the length and diameter of
the two dents have the same value of 100mm. Therefore,
this study finds that a dent-management programme can
be strategically altered and adjusted to take advantage of
the dent shape. In the field, the shape of a rock dent is
governed by the shape of the rock on which the pipe is
resting (Fig.1).
Fig.8. Loading-unloading-reloading of pipe with circular dent.
Fig.9. Dents shapes from FE models(a) loaded condition; (b)
unloaded condition.
and the total dent depth was 11% (D11). The first letter R
instead of C indicates the shape of the dent is rectangular.
Figures 5-7 show the effect of internal pressure, dent shape,
and dent length on denting load-deformation behaviour
of this pipe, and demonstrate that the effect of internal
pressure is the greatest on the load-deformation behaviour.
Figure 5 shows the denting load-deformation behaviour
when a circular dent of 50-mm diameter forms in this
pipe with three different levels of internal pressure, which
are 0.2py, 0.4py, and 0.6py. From this figure, it can be
observed that for a total dent depth of 11%, the denting
load carrying capacity of this pipe increases by 56% when
internal pressure increases from 0.2py to 0.6py. In the
field, the denting load develops due to the reaction of the
Figure 7 shows the effect of dent length for a rectangular
dent when the internal pressure is 0.2py. From this figure,
it is obvious that a longer dent is more favourable than a
localized or small dent, since a longer dent allows the pipe
to carry a higher denting load. In the field, the length of a
rock dent is controlled by the length of the rock on which
the pipe rests. Thus, this study finds that a longer dent is
a matter of less concern than a localized dent. Hence, the
dent-management scheme can be adjusted depending on
the actual shape of the dent.
Figure 8 shows the denting load-deformation behaviour of
the pipe when the internal pressure is 0.4py and the dent
was formed with a 50-mm diameter (C50P40D13) circular
indenter. The denting load was gradually removed when
the total dent depth reached 81.3mm or about 11% (point
C in Fig.8); the dent shape at this stage is shown in Fig.9a.
After complete unloading, the permanent dent depth
reached 45.5mm, or about 6% (point E in Fig.8); the shape
of the dent at this stage is shown in Fig.9b. The permanent
depth is that which is found and measured when the soil or
backfill above the dented segment of the pipe is removed
for its inspection. Hence, the unloading path (path C-D-E)
in Fig.8 simulates the removal of soil or backfill material
above the dented segment of the pipeline in the field.
Once the inspection is completed, the pipeline operator
may decide to do nothing, or repair or even replace the
dented segment of the pipe, depending on the dent depth.
Current codes and standards recommend removing the
dented segment of the pipeline if the permanent dent
depth (dent depth at point E in Fig.8) is 6% or larger
[2-5]. Thus, according to these guidelines, the pipeline
operator probably has no option other than bringing the
pipeline operation to an undesirable halt and continuing
with a costly replacement.
1st Quarter, 2012
33
Figure 8 shows that this pipeline at this stage (point C) still has
large a reserve of strength and ductility to allow continued
pipeline operation safely, since the denting-load-carrying
capacity does not reduce even when the total dent depth
is 13% (point G) and the permanent dent depth is well
above 6%. Hence, this study finds that a pipeline is safe to
continue in operation if the total load resulting from the soil
above the pipe does not increase. However, inspection for
other defects such as cracks and corrosion is recommended
since, in this study, only plain dents have been considered.
Conclusions
The following conclusions are made based on the results
obtained from this study, and are therefore necessarily
limited to the pipe specimen and loading history that were
considered in the study.
The current assessment criterion for plain dents based on
a dent depth of 6% is conservative.
Pipeline operators have the choice of taking advantage
of operating pressure, dent shape, and dent length when
deciding about the repair or replacement of a dent.
A dent-management scheme using lighter backfill material
can ensure the structural safety of the dent. This scheme
allows the pipeline operator strategically to delay the dent
repair or replacement operation, thus saving revenue.
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As discussed earlier, the path C-D-E in Fig.8 represents
the removal of soil or backfill above the dented segment
of a pipeline for inspection of the dent. At this stage, the
total and permanent dent depths are approximately 11%
and 6%, respectively. The pipeline operator may decide to
backfill the pipe with same (native) material if is engineering
judgment and guidelines allow so doing. However, the
pipeline operator may still be concerned about the safety of
the pipeline associated with such a dent since the re-loading
path E-F1-F2-C indicates that the total dent depth reaches
the same value of 11% (point C in Fig.8) if the same (native)
backfill material is used.
shut-down takes place. Hence, this dent-management
approach can avoid unnecessary loss in revenue from the
unscheduled pipeline shut-down and from the resulting
repair or replacement of the dent.
This study finds that a dent can be constrained from further
growth, and the total dent depth can be reduced considerably,
if a lighter material is used to backfill the pipeline. For
example, the total dent depth can be reduced to 8.7% or
66mm (point F2 in Fig.8) if the weight of backfill material
is reduced to two-thirds; and the total dent depth can be
reduced to 7.8% or 60mm (point F1 in Fig.8) if the weight
of the backfill material can be reduced to half. Hence, this
study finds that use of lighter backfill material ensures the
safety of a dent by restricting the dent from further growth.
A mixture of wood mulch and regular soil would be an
example of such lighter material. Hence, this study shows
that it is perfectly safe to continue pipeline operations if the
denting load is reduced by using a lighter backfill material.
This finding leads to a new dent-management approach
which is named the ‘do-a-little’ approach in this paper.
According to this approach, a lighter material needs to be
used as the backfill where a dent is found so that denting
load that develops from the reaction force of the rock can
be reduced, resulting in a significant reduction in the total
dent depth. This allows the pipeline operator to delay the
repair or replacement operation for a while, and this may
possibly be extended until the next scheduled pipeline
Acknowledgements
This work was completed with financial assistance from
the Natural Science and Engineering Research Council
of Canada.
References
1. Yukon Gov’t, 2011. Frequently asked questions: oil and
gas information. www.emr.gov.yk.ca/ oilandgas/faq.
html#pipe1. Updated on 10 November, 2009, viewed
on 5 May 2011.
2. ASME, 2007. B31.8-2007: Gas transmission distribution
piping systems. ASME International, New York, NY,
USA.
3. CSA, 2007. Z662: Oil and gas pipeline systems. Canadian
Standards Association, Mississauga, ON, Canada.
4. DNV, 2010. Offshore Standard OS-F101: Submarine
pipeline systems. Det Norske Veritas, Hovik, Norway.
5. ASME, 2006. B31.4-2006: Pipeline transportation
systems for liquid hydrocarbons and other liquids. ASME
International, New York, NY, USA.
6. API, 2008. Specifications for line pipe: API 5L. American
Petroleum Institute, Washington, DC, USA.
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15 – 18 October 2012
Berlin, Germany
Visit
www.piperehabconf.com for more information
‹‹‹‹‹‹‹‹‹‹‹‹‹‹‹‹ Exhibition
Organized by
and sponsorship opportunities still available ‹‹‹‹‹‹‹‹‹‹‹‹‹‹‹‹‹‹
1st Quarter, 2012
35
Validation of the latest generation
EMAT ILI technology for SCC
management
by Jim E Marr1, Elvis Sanjuan1, Gabriela Rosca1, Jeff Sutherland2, and
Andy Mann2
1
2
TransCanada, Calgary, AB, Canada
PII Pipeline Solutions, Calgary, AB, Canada
T
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RANSCANADA MANAGES the integrity of its gas transmission pipelines that are susceptible to
stress-corrosion cracking (SCC) by periodically performing hydrostatic testing. Interest in an alternative
approach to manage pipeline integrity in the presence of severe SCC and other forms of longitudinally
oriented defect resulted in the endorsement of the latest generation of dry-coupled in-line inspection
(ILI) tool. PII’s (PII Pipeline Solutions, a GE Oil & Gas and Al Shaheen joint venture) ILI tool uses the
electromagnetic-acoustic-transducer (EMAT) technology to meet this requirement.
This paper will summarize field experience results of the latest-generation EMAT ILI tool, which has been
commercially available since September, 2008.This ILI programme review demonstrates the challenges that have
been overcome, targets that have been achieved, and that the tool delivers the specification functionality to
detect,size,and discriminate which are key parameters to support an effective SCC pipeline-integrity programme.
T
RANSCANADA PIPELINES HAS been collaborating
with PII Pipeline Solutions for over 10 years on the
development of an ILI tool to locate and determine the
severity of SCC in dry, sweet, natural gas pipelines. The
PII EMAT ILI is now a third-generation tool. This paper will
present some of the most recent results from the TransCanada
and PII EMAT SCC programme.
TransCanada SCC overview
TransCanada has had a history of SCC primarily within tapeand asphalt-coated pipelines. In the case of tape-coated lines,
there is the presence of both toe cracks in the crotch of the
double-submerged-arc-weld (DSAW) longitudinal seam and in
the associated tented disbonded region across the long seam.
Five of six failures from 1986 in Canada have been associated
with tape coatings and were toe cracks. For the Canadian assets
over the past 25 years, asphalt-coated lines were in a state of
condition monitoring. In the United States, all in-service and
hydrotest failures have been in the body and associated with
asphalt-coated lines.
This paper was presented at the Pipeline Pigging & Integrity Management conference
held in Houston in February, 2011, and organized by Tiratsoo Technical and Clarion
Technical Conferences.
tel: +1 403 920 5410
The results of these failures and ongoing maintenance activities
have resulted in an extensive, repetitive, hydrostatic testing
programme over the past 25 years. Hydrostatic testing may be
potentially harmful to the pipe but in many cases has been the
only reliable option to remove injurious axial defects from the
pipeline. As some research indicates, consecutive pressure tests
may cause the sub-critical cracks to propagate thus worsening
the condition of the pipeline. Another observation has
been the coalescence of SCC may have changed the severity
signature of a valve section resulting in a shortened hydrotest
re-assessment interval.
Recent advancements in ILI technology have made it possible
to assess for cracking and the overall SCC severity of a pipeline.
At the present time for liquid pipeline systems, the leadingedge technology is ultrasonic (UT) crack-detection tools which
have enjoyed success in locating and classifying the severity
of SCC. The major obstacle for natural gas operators is the
required use of a liquid slug that envelops the tool to ensure a
continuous sound wave between the sensor and the pipe wall.
A more recent technology that has now moved past validation
is the utilization of EMAT.
In the management of SCC, TransCanada has also had an
extensive programme of data integration utilizing the predictive
models, elastic-wave ILI, UT/ILI, and extensive investigative
excavations. Initially, the predictive soils’ models enabled the
recognition of susceptibility but could not delineate severity
36
Property
EMAT GEN III Tool
Size range (inches)
Inspection range (Km)
24 to 36
170
Speed range (m/s)
0 – 2.5
Bend passing
1.5 D
Minimum defect size* (mm)
2 x 50
POI (%)
> 66
POD (%)
> 90
Detection redundancy
Disbondment detection
5
All coating types
Table 1. EMAT third-generation specifications. Note: *base
material and seam weld for all coating types.
• The PII EMAT third-generation modifications include
a decreased spacing of sensors (15°) which improves
the coverage and redundancy.
• There has been an increase in the number of carriers
from second- to third-generation which improves the
redundancy and coverage of the inspections.
• Additional UT sensors to advance discrimination have
been added to the tool.
• Operationally, modifications were done to the sensors
to reduce signal-to-noise ratios aiding the ability to
detect and discriminate SCC.
PII EMAT tool specifications
A primary goal is to continue to work with PII to improve its
EMAT tool and enable the better detection of cracks. Table
1 summarizes the current EMAT ILI tool’s specifications as
reference for an evaluation of performance.
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until an excavation or series of sites were available for inspection.
When utilized in conjunction with EMAT, the predictive
SCC model can provide locations that are deemed susceptible
and, with time, improve the analytical reliability of the tool.
This combination effort is simpler and less disruptive than
the implementation process required for a hydrostatic testing
or conventional liquid ultrasonic ILI operational challenges.
tape- and asphalt-coated pipelines, delineating toe and body
cracks, has been very promising. Listed below is a brief summary
of recent EMAT modifications:
In another application, the data obtained from historical
elastic-wave SCC ILI have been integrated into current SCC
planning activities. These historical runs have enabled some
success with multiple run-to-run comparisons to determine
potential crack locations and potential severities.
The objective of the EMAT ILI was to detect and size
longitudinal cracks and related crack-like defects with lengths
≥50mm and depths ≥2mm. PII’s EMAT tool is designed to
identify and size cracks and crack-like defects both in the plate
material and weld areas having a 90% probability of detection
(POD) and 66% probability of identification (POI) on or
above the detection threshold. As described below, these
specifications in some cases have been exceeded.
Another initiative is the utilization of historical and present
MFL ILI results to identify areas of ‘low-level’ corrosion which
infers an area of coating disbondment. Coating disbondment
is required for SCC to initiate and propagate.
The crack depth sizing specification is reported as a depth
band of ±0.5mm at 80% certainty (all defects within sizing
specification). Length sizing specification is ±10mm or ±10%
of reported length at 80% certainty, whichever is greater.
EMAT and TransCanada history
In time, quite significant cost-saving opportunities may be
achieved if hydrostatic testing can be selectively removed from
the integrity programme (mostly likely following a few years
of EMAT, direct examination, and hydrostatic testing) taking
into account that hydrostatic testing can be one of the most
expensive mitigation options available.
Listed below is a summary of the TransCanada and PII
EMAT history.
• 2000 - PII delivers 36-in EmatScan crack-detection
tool, first-generation
• 2004 - release of second generation – TransCanada
ran in 2005 with excavations between 2005 to 2006
(small success, POI issue)
• 2005 - decision to build third generation; first run
in TransCanada 30-in inch (approx. 40km) in 2008
• 2010 - the latest generation of the 24-36-in EMAT
crack-detection tool was the subject of the last IPC
in Calgary 2010 [1].
Further collaboration is ongoing to improve the tool’s
capabilities to detect and identify SCC accurately and reliably
for different types of similar-appearing defect and signal loss
(attenuation) for various coating systems and pipe-surface
anomalies. This past year the tool’s detection ability for both
Recent TransCanada and PII
EMAT collaboration
The PII EMAT tool has now completed over 800km of
inspections with TransCanada in both the USA and Canada.
The results of these inspections have been confirmed with
over 31 field verifications. Comparatively, the results from
the in-line crack inspection provide far greater information
relative to a hydrostatic test.
Through a collaborative effort consisting of an extensive
engineering assessment and multi-department company review
process, it is believed that the majority of injurious cracks
1st Quarter, 2012
37
have been detected and mitigated (for the sections analysed),
but also that all the colonies from sub-critical downwards
to insignificant were addressed, aiding in the progression
of the reliability and maturity of the tool. This ability to
detect colonies within tool specifications makes it possible
to prioritize the defects, allowing for a planned mitigation
action and to monitor their growth by repeating the
inspection in a desired time period.
TransCanada SCC EMAT
management philosophy
TransCanada uses a risk-based system and has developed
performance-based integrity plans to manage its pipeline
assets. EMAT’s recent promising results are encouraging,
but TransCanada is most likely going to continue to use
EMAT plus direct examination, followed potentially
by hydrotesting in the near term, to manage SCC.
TransCanada has proposed EMAT runs where:
System
• move towards to a probabilistic defect management
process;
• provide more data for targeted dig-site selection:
improve models and SCCDA process to address
susceptibility;
• should not create a major outage impact; and
• expanded opportunities with MFL, caliper, or other
ILI programmes
Excavation and correlation
programme results
(2008 – present)
During the last couple of years TransCanada has conducted
a series of EMAT ILI runs across the TransCanada system.
Analysis of the EMAT data suggested sites which may fail prior
to a hydrostatic retest. Conversel y, PII reported a number
of significant ILI features as ‘non-decidable’ which will
require further investigation for future tool development and
refinement of the analysis and discrimination capabilities.
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• one or more valve sections are on the hydrostatic
test programme (possibility of EMAT as a hydrostatic
test replacement);
• SCC-susceptible valve sections, where limited or
no information is known about the presence or
severity of SCC; and
• lines with no company experience but subject to
regulatory compliance.
Some of the additional advantages of running the EMAT
tool are:
Consequently, 31 excavations were completed to confirm
both the integrity of the line and the validity of the ILI
inspection. All excavation sites were verified in the field by
the SCC threat-management team.
A 30in
B 36in
C 36in
D 36in
2008
2009
2009-2010
2010
2009-2010
2010
2010-2011
2011
Reference wall thickness (mm)
8.4 - 12
8.9
9.1
9.525
Total accepted ILI length (Km)
39.2
38.3
387.1
112.2
576.8
Total length analyzed (Km)
39.2
38.3
210.85
38
326.35
No. of digs to date
10*
10
11
-
31
No. of digs planned to date
1
4
12
4
21
No. of joints excavated
10
14
14
-
38
Total excavated length (m)
120
168
161
-
449
POD % (Field excavations to date)
100
91
100
-
93
POI % (Field excavations to date)
70
79
77
-
76
POD - No. features above spec. present
5
22
19
-
46
POD - No. features above spec. detected
5
19
19
-
43
POI - No. features reported by EMAT
10
42
31
-
84
POI - No. features correct classification
7
33
24
-
64
ILI Year
Excavation year
Total
Table 2.TransCanada third-generation EMAT summary results, 2008 – present. Note: * three digs were done in the 30-in
system to prove feature classification.
38
The excavations were intended to:
Fig.1. 2009 site (141mm max. interlinking length and
maximum depth of 43.5% WT).
• remove assumed near-critical features from the line;
• enable TransCanada’s pipeline-integrity group to
develop an understanding of the ILI tool tolerance
and nature of the features;
• establish correlations among ILI calls (detection
and sizing of SCC features) and non-destructive
examinations (NDE) to prove and improve the
EMAT technology related to feature classification;
• enable the reliable calculation of the failure pressure
of the features that will be left in the line and predict
when they will need to be repaired;
• allow TransCanada to improve an already robust
integrity-management plan for both inspected pipeline
segments and to further support integrity decisions for
the entire system.
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Table 2 shows a summary of TransCanada third-generation
EMAT results since 2008 until the present. To date, the PII
EMAT system has shown a 93% POD and a 76% POI inspection
performance based on field excavation results, with ongoing
cooperative excavation activities in progress. Some specific
examples of field results and correlation are discussed in the
following sections.
Eastern Canada
Fig.2. 2010 excavation toe-crack (256mm max. interlinking
length and maximum depth 66.3% WT).
In 2009, TransCanada conducted five investigations in this
area. During these excavations the tool was successful with the
discrimination of mid-wall indications from SCC. This was a
milestone in EMAT ILI as this discrimination development
overcame one of the bigger analysis hurdles (SCC from non
SCC) but functionally saved TransCanada a costly replacement.
Figure 1 illustrates one of the colonies detected by the EMAT
tool. Five SCC colonies from this programme were classified
as significant. This programme had 182 grind repairs and one
sleeve applied to the pipeline [1].
Interestingly, the direct-examination programme completed in
the mid 1990s never detected a colony greater than 15% in depth.
All Canada
Fig.3. 2010 excavation SCC in corrosion (100 mm max.
interlinking length and maximum depth 60.2% WT).
In 2010, TransCanada conducted 27 investigations based on
the EMAT analysis, and a total of 33 joints with an approximate
length of 390m was inspected. Some examples of the SCC
detected during these excavations are presented in Figs 2-5.
Field NDE practices and limitations found in
correlation
During the 2009 and 2010 excavations, the following limitations
in NDE evaluation techniques for crack sizing were noted:
Fig.4. 2010 excavation shows accuracy of ILI call box
(120mm max. interlinking length and maximum depth
75.8% WT). Note: white straight edge is a piece of pH paper.
• average crack depth and maximum crack depth from
the EMAT analysis differs from field NDE techniques
due to the fact that the crack classification is in ranges
or buckets (2-3mm; 3-5mm; and > 5mm);
1st Quarter, 2012
39
Crack Depth mm
Axial Distance metres
• EMAT crack-length measurement could be affected
by the effective length that corresponds to a crack
depth deeper than 2mm. So the conditions of a 50mm length by 2-mm depth by the tool specification
must be achieved.
GW 25450 023 - 005703
Distance from u/s weld m
Defect length
Fig.7. Example of crack length using phased-array techniques.
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Figure 6 illustrates the correlation between crack length
and crack depth from a grinding profile. The EMAT tool
can only really see crack depths below 2mm and the tool
should only be able to discriminate the area within the
rectangular area, although in reality the crack length exceeds
the rectangular area of Fig.6.
Fig.6. Example of crack length and depth below threshold or
detection specification [1].
Depth mm
Fig.5. 2010 excavation adjacent to long-seam weld (85mm
max. interlinking length and maximum depth 33% WT).
GW 14250 no call at 3.07m
Distance from u/s weld m
Depth mm
Figure 7 illustrates the crack profile of a colony measured
using phased-array techniques. In this example, the field
NDE would have recorded a total colony length of 400mm.
The EMAT tool would have only seen the area within
the rectangle box representing 300mm. There is also a
NDE evaluation point noted on the relative coarseness
of the grinding method compared to the phased-array
examination to determine crack depth.
Grind profile
Corrected
profile
Programme lessons and
developments
This paper presents and summarizes the most recent
findings of the EMAT programme. Overall, 38 joints,
totalling 449m of inspected pipe, were evaluated between
2009 and 2010. In one asset evaluation there were nine cutouts and one sleeve applied to mitigate the SCC detected
by the EMAT tool across 11 excavations. Described below
are some of the ‘lessons’ and developments from the past
two years.
During the validation of results, few excavations showed
that some crack-like and crack-fields were incorrectly
classified. These classification anomalies included:
• Situation A: a crack-like feature was found after the
NDE but not reported by the EMAT tool.
• Situation B: crack-like or crack-field reported by the
EMAT tool. There was no colony detected by the NDE.
These two groups of features were challenging and were
collaboratively investigated in order to provide clarification
of these issues, enabling the refinement of the EMAT
tool analysis.
Fig.8. 2010 no-call feature classified: top – MPI; middle –
B-scan data, cross section profile after NDE.
40
Situation B
There were three situations across the system over the
past two years, although most of these misclassifications
occurred during the 2010 programme. This type of
misclassification consisted of the following types:
• ‘non-decidable’ features
• external corrosion miss-call
• external corrosion deposits masking EMAT signals
‘Non-decidable’ features
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Following the excavations, TransCanada and PII discussed
the need to report some specific features that do not fully
meet the existing classification criteria. One crack with
a relatively short length-vs-depth ratio was identified
as a non-decidable feature based on PII’s original
classification, although upon excavation it was discovered
to be a through-wall leak. The EMAT tool detected strong
signals during the analysis of this indication but the
existing procedures guided the decision of the reported
call. Originally, the EMAT analysis classified it as an
inclusion, based upon the relatively strong shear- and
Lamb-wave classification signals.
Fig.9. Excavation results through-wall leak, ‘non-decidable’
feature: top – symmetric fit example; middle – nonsymmetric fit example; bottom – MPI of the feature found
at the non-decidable location.
Situation A
Some cracks were initially classified as geometry feature
during the analysis and were not reported for any further
field investigation. After the NDE was performed on the
same joint for a confirmed colony, a number of other
features under this misclassification of geometry were found
to be intermittent SCC that fluctuated between being
either over or under the tool depth specification. These
features were and can be detected by the EMAT tool but
were originally classified as geometry following the existing
company procedures. Based on the field confirmation and
improvement of the discrimination analysis, all similar
features have been subsequently reanalysed and re-classified.
The investigative programme will continue to evaluate and
refine this type of feature.
Figure 8 is an example of this type of call. Some sensor
indications are coincident with this feature but could be not
be originally resolved during analysis to be classified as a crack.
The lesson established from this feedback was to refine
the guidance in analysis, as this pattern of cracking results
in a differing disruption to the ultrasonic energies than
expected. In the past, signal characterization was based
upon long, deep (symmetric) crack profiles. Short and deep
(non-symmetric) profiles were not considered in initial
testing, but now will be considered as possible cracks.
Figure 9 illustrates the difference between a symmetric and
non-symmetric crack profile: these non-symmetric deep/
short features were originally ‘non-decidable’ features as
they had a typical aspect ratio and signal response.
TransCanada and PII have decided that whenever there
are conflicting signal characteristics, PII will apply a
more-conservative approach and classify the indication
as a crack-like feature (for example, ‘non-decidable’ to be
characterized as a crack with depths provided). Therefore
a ‘non-decidable’ feature classification has been created
and included in all future reports.
Misclassified external corrosion (corrosion
coincident with crack-like indications)
In some circumstances conservative calls were made in
reported feature areas. The following NDE showed that
there was no cracking associated with the reported EMAT
features. The misclassified features were located at, or
coincident with, the worst areas of external corrosion.
The external corrosion was characterized as being steep
sided and narrow and was aligned axially in an area of
general wall loss associated with a disbonded coating.
Each feature had numerous areas of external corrosion
indications (see Fig.10). Although the EMAT data did
have some characteristics normally associated with
1st Quarter, 2012
41
Fig.10. Examples of misclassified crack-like features within
external corrosion areas.
corrosion, some indications had high amplitudes and were
linear which indicated they could be cracking and hence were
conservatively reported.
Misclassified external corrosion deposits: EMAT
signal masking
It seems that the density of these iron-dominated deposits
may attenuate the EMAT signals and could be interpreted as a
possible colony. Signals may be enhanced by coating variation
or deposit thickness and chemistry, but the EMAT data
indicated something physically different about this location.
In these cases the iron-rich deposits seemingly causing data
mis-interpretation.
Summary
and they are immediately incorporated into the
analysis process. Training sessions have taken place
with the analysis team to teach how to use the
excavation information to improve classification.
Quality-control procedures have also been modified
to take into account the results of these investigative
excavations.
• Based on excavation results, it has been proved that
the EMAT tool is able conservatively to define valvesection severities and locate severe SCC features
present on the line.
• The tool identified 62 crack-like or crack-field
features, with the majority exceeding tool
specifications and indicating a heightened integritythreat awareness. The results supported the decision
to add more sites for excavation, and to complete
the analysis for the entire length of one of the
EMAT runs.
• The recent results from the PII EMAT tools are
most encouraging. The EMAT tool can discriminate
between mid-wall laminations and SCC; it also can
find SCC in the body and seam welds, as well as
locating SCC in both tape and asphalt coatings. The
2010 programme had several sites with immediate
sleeves and cut-outs. The tool is improving, with
the lessons-learned being applied on mis-calls and
results that are not SCC within EMAT data analysis.
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In two cases, one in tape and the other in asphalt, corrosion
deposits were found at the location of the reported features. In
one example, very hard cathodic-protection-derived (assumed)
deposits with yellow, black, and brown colouration were
found in a disbonded area underneath the asphalt-coated
pipe (Fig.11). The measured on-potential (pipe-to-soil) was
-2.330mV. The NDE showed that there was no cracking
associated with the reported EMAT features.
Fig.11. Misclassified crack-like features: top – deposits as
found; bottom – MPI of the ILI reported feature area.
Listed below is a summary of both the results and expected
future actions based on the most recent programme:
• TransCanada has extended the excavation programme
to 2011 in order to address the remaining features from
one of PII’s 2010 reports. A total of 21 excavations
are planned for 2011.
• With confidence, the EMAT tool is anticipated
to delineate valve section severities within tool
specifications and have the ability to locate and
measure SCC features existing within the line [1].
• TransCanada and PII will continue with the
improvement in analysis, software sizing, and
classification and discrimination. The results of the
excavations are returned to PII upon field discovery
Acknowledgements
Thanks are given to the efforts of the EMAT PII group in
Stutensee, Germany, and Calgary, and to TransCanada
personnel in Calgary.
Reference
1. J.E. Marr and E.Sanjuan Riverol (TransCanada),
S.Jiangang, A.Mann, and S. Tappert (GE), and
J.Weislogel (PII), 2010. Validation of latest generation
EMAT in-line inspection technology for SCC
management. IPC 2010-31091, ASME.
20
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25 th
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1st Quarter, 2012
43
Comparison of multiple crack
detection in-line inspection
data to assess crack growth
by Mark Slaughter1, Kevin Spencer2, Jane Dawson*3, and Petra Senf4
GE Oil & Gas, PII Pipeline Solutions, Houston, TX, USA
GE Oil & Gas, PII Pipeline Solutions, Calgary, AB, Canada
3
GE Oil & Gas, PII Pipeline Solutions, Cramlington, UK
4
GE Oil & Gas, PII Pipeline Solutions, Stutensee, Germany
1
2
U
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LTRASONIC INLINE INSPECTION (ILI) tools have been used in the oil and gas pipeline industry
for the last 14 years to detect and measure cracks. The detection capabilities of these tools have
been verified through many field investigations. ILI ultrasonic crack detection has good correlation with
the crack layout on the pipe and estimating the maximum crack depth for the crack or colony. Recent
analytical developments have improved the ability to locate individual cracks within a colony and to define
the crack-depth profile.
As with the management of corroding pipelines, the ability accurately to discriminate active from non-active
cracks and to determine the rate of crack growth is an essential input into a number of key integritymanagement decisions. For example, in order to identify the need for and timing of field investigations
and/or repairs, and to optimize re-inspection intervals, crack growth rates are a key input. With increasing
numbers of cracks and crack colonies being found in pipelines, there is a real need for reliable crack-growth
information to use in prioritizing remediation activities and planning re-inspection intervals. So as more and
more pipelines containing cracks are now being inspected for a second time (or even third time in some
cases), the industry is starting to look for quantitative crack-growth information from the comparison of
repeat ultrasonic crack-detection ILI runs.
This paper describes the processes used to analyse repeat ultrasonic crack-detection ILI data and the crackgrowth information that can be obtained. Discussions on how technical improvements made to crack-sizing
accuracy and how field verification information can benefit integrity plans are also included.
T
HIS PAPER DESCRIBES recent advances in ILI
data -analysis techniques for improving the sizing
accuracy of longitudinal cracks and SCC colonies. Crack
profiling and crack-field mapping are improved signalprocessing techniques that are now being used today.
These new techniques have leveraged the 40,000km of
ILI crack-inspection and field-verification work done by
tel: +1 403 920 5410
GE. These techniques allow analysts to estimate a more
accurate size of the effective area of the flaw and of the
most significant cracks within a crack field. By using this
data it is possible to perform comparisons between cracks
detected in repeat ILI runs to obtain information on crack
growth [1] and to improve the accuracy of engineeringcriticality assessments, leading to more cost-effective
decision-making on crack mitigation and repair. These
new techniques are especially valuable when combined
with the elements described below.
The elements shown in Table 1 are key to achieving
a reliable assessment of crack-like and SCC features
reported by ILI.
44
Element 1
A reliable tool performance in detecting, discriminating, and sizing SCC and crack-like features.
Element 2
A comprehensive excavation programme with accurate field and laboratory direct observation to
evaluate ILI tool performance and provide reliable data feedback to the ILI vendor for improvement.
Element 3
A fracture-mechanics’-based method with material-testing data to identify significant SCC and cracklike features for prioritizing excavation investigation and life cycle/re-inspection interval prediction.
Table 1. Elements for reliable assessment of cracks [2-4].
Crack profiling and field statistics
Key element 1 – a reliable tool performance to detect,
discriminate, and size SCC and crack-like features
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Fig.1. Field verification of a crack profile.
Traditional reporting methods from ultrasonic crack detection
ILI tools are fairly standard across the industry and tend to be
conservative. For crack-like flaws, the length and maximum
depth category are reported. For crack-field features, the field
length, width, longest indication, and depth category are
usually reported. The detection capabilities specified state
the thresholds below which defects are not detected and
reported. These thresholds are usually a minimum crack
length of 30mm and minimum crack depth of 1mm. The
crack-depth dimension is not usually reported as an absolute
number but is usually categorized into ranges, for example <
12.5%, 12.5-25%, 25-40%, and > 40% of the wall thickness.
Fig.2. Illustration of a flaw profile and the ‘effective dimensions’.
Crack profiling
It is well documented [5] that idealizing all flaws as semi-elliptical
in profile and then using an upper-bound depth value produces
overly conservative results in the majority of cases. Jaske et al.
[5] considered the effective area of a flaw assuming that the
equivalent flaw has a semi-elliptical profile. The effective area
based semi-elliptical flaw uses the effective length and the effective
area of the worst flaw identified by an RSTRENG-type analysis
of the profile, recalculated to give an effective depth for a semielliptical flaw of the same effective area and failure stress [6].
Fig.3. Crack detection in an SCC colony.
Fig.4. Reporting of the crack field based on the mostsignificant cracks (crack map).
An amplitude-based sizing model has been developed to
predict actual crack profiles from the crack-detection tool
data. The sizing model uses a variety of variables as inputs
and includes orientation and location of the flaw, product
medium, and the distance from the sensor. With this improved
analysis technique a detailed profile can be determined, with
a depth prediction given along the longitudinal direction.
The amplitude-based depth-sizing model and subsequent crack
profiling has been verified during its development with the
help of several pipeline operators. Figure 1 shows an example
of one such field verification: the black line represents the
predicted profile whilst the blue line shows the actual profile
as determined in the field. Once the profile is known it can
be idealized as a semi-ellipse using the area to calculate the
‘effective dimensions’: an illustration of the profiling and
effective area is shown in Fig.2.
1st Quarter, 2012
45
Crack-field statistics
SCC colonies can consist of several hundred individual
crack-like flaws (Fig.3), all aligned perpendicular to the
principal stress. Identifying individual cracks from within
these colonies is difficult due to the sheer density of cracks
and the corresponding signal noise they produce.
These colonies of cracks will interact, and some account must
be taken of this. Signal-filtering techniques are applied to
the data to determine accurate crack maps of the significant
cracks within a colony and interaction criteria can be applied
to identify the most likely failure path (Fig.4).
Using field-verification data: key element 2 – a
comprehensive excavation programme to evaluate
ILI tool performance and provide reliable data
feedback to the ILI vendor for improvement (SCC
Case Study [7])
Fig.5. Crack-depth /length profile.
A case study
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This section of the paper discusses the direct benefits in
using an in-depth NDE programme to improve the reliability
and accuracy of ILI crack-inspection data. The process used
in this study clearly demonstrates the benefits realized by
pipeline operators, whether it is used to improve a single
set of crack-inspection data or data sets for a reliable crackgrowth assessment.
The following case history relates to an ILI crack-inspection
project on the Centennial pipeline system for Marathon
Pipeline LLC (MPL).
Background
In 2005 GE delivered Ultrascan DUO the first phased-array
inspection tool, to the oil and gas pipeline inspection market.
Since its introduction, the tool has inspected 7600km of
pipeline; a portion of this work has been conducted in
crack-detection mode only, and another in a combined wallthickness measurement and crack-detection (DUO) mode.
This case study involves the inspection of three lines with
a total length of over 1086km in the DUO mode. The two
primary threats being assessed were transportation fatigue
cracking, and stress-corrosion cracking (SCC). Following
the inspection programme and delivery of the final report,
the pipeline operator selected and excavated 76 crack
features. Since all defects were located on the pipeline’s
external surface, the sizing of the defects in the report
could be confirmed through an accurate method involving
incrementally grinding-out the defects. Accurate field
verification is not always conducted, but due to the need to
try to correlate tool data with field results, MPL determined
to proceed with the data collection in this case, allowing for
a valuable comparison of inspection data.
Fig.6. Progressive grinding: NDE crack measurement.
The pipeline system is over 1200km long and a liquid
products’ pipeline system.
Report and verification process
After receipt of the initial report, the pipeline operator
proceeded with verification digs and began implementing
its ILI response plan. During many of the subsequent
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Fig.7. DNV 02 chart: comparison of sizing from original to revised algorithm. Courtesy of CC Technologies, DNV.
excavations within this plan it was discovered that
grinding to 40% of the wall thickness did not remove
all cracks (many of the indications had ILI reported
depths of 12.5-25% WT and 25-40% WT). To collect
more accurate field data for better analytical correlation,
the operator and GE developed an improved grinding
procedure.
Experience has shown that the method of grinding defects
in incremental steps leads to reliable measurements [9].
The grinding procedure incorporated first measuring
the wall thickness at the area of the defect using an
ultrasonic wall-thickness-measurement device. Then the
wall is ground and the defect is measured in incremental
steps of 10% wall thickness until the deepest portion
of the defect is completely removed or a maximum grid
depth has been reached. By documenting the results of
each step, a profile of the crack can be generated for
both the maximum individual crack and the maximum
interlinking crack (using CEPA guidelines [8]). An
example of a depth profile is shown in Fig.5.
Improving the sizing model
For SCC, the maximum depth, the length of the crack
field and the length of the largest interlinked crack are
reported for each crack field. In order to obtain optimum
defect sizing, the first dig results were used to finalize
GE’s crack-sizing algorithms. The ‘blind test’ was then
used to validate (improve confidence in) the revised
algorithms prior to the operator requesting a re-grade.
Figure 7 shows the effect of the revised algorithm on
the reported depth. Since the original ILI report did
not include exact estimates for the reported depths,
the results are presented in depth categories. As shown
in Figure DNV02, both algorithms showed the same
general trend of increasing maximum grind depth as
the reported depth bin increased. However, the original
algorithm consistently under-called the maximum grind
depth. The revised algorithm, on the other hand, shows
a dramatic improvement in the number of features with
correctly categorized depths.
Figures 7 and 8 show further validation of the revised
sizing algorithms for depth developed by GE. After the
crack anomalies were re-analysed using the revised crack
algorithms, 64 of 76 reported depths were within the
±0.039-in (±1-mm) band indicated by the red lines, and
41 of 53 verified lengths of interlinked cracks were within
the +1.57/-0.78 (+40/-20mm) range indicated by the black
dashed lines. This means, that the depths measurement
of the ILI complied with the 90% certainty statement
(with 95% confidence, according to API 11639) of the
tool specification.
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1st Quarter, 2012
Fig.8. Unity plot after algorithm change on ILI data.
It should be noted that the current method for reporting the
depth of features with the conventional ultrasonic crack tools
is to state a depth band, usually expressed as a percentage of
wall thickness (e.g. 0-12.5%, 12.5 – 25%, 25-40% and >40%)
with a tolerance added to that band. If the actual depth band
plus tolerance range were plotted on the graph in Fig.10 for
each corresponding feature, the area bounded by that tolerance
would be much wider than the width of the red lines shown.
Crack growth rate investigation
When the UltraScan crack-detection (USCD) vehicle is run
twice in the same pipeline, the ultrasound signals recovered
will not be exactly the same even from an unchanged reflector.
This variation arises for a variety of reasons, including variations
in pipeline medium density, medium composition, precise
positioning of the tool sensors, alignment of sensing distances,
variability in sensors, and temperatures. The pipeline medium
effects and any systemic variation are calibrated in the process
of initial data assessment for each inspection. Samplingbased and dynamic effects remain as effects that are variable
between defects, even if there is no other change. Hence a
different response does not necessary indicate a particular
feature has changed (i.e., grown) between the two inspections.
Understanding and accounting for such variations is a key
component of assessing and quantifying crack growth between
two ILI data sets.
For comparison purposes the data sets are aligned to each
other using spool numbers. If no sections of pipeline have
been replaced then this information will be consistent
between the two data sets. Anomalies reported in each
inspection can then be compared to the corresponding
location associated with each anomaly. This process is
automated using analysis software capable of synchronizing
between two inspections and supplemented by visual review
and context matching from the experienced analysis team.
As with all inspection technologies, any reported value
represents an interpretation of the measured values of
the inspection process and the interpretation of those
values by skilled analysts. As such, the values given are
associated with a tolerance range that represents the
variation to the actual value that would be found on more
detailed field investigation. The tolerances defined for the
GE USCD tool are included as part of the performance
specification in the ILI report and they correspond to the
possible differences between a real flaw and the ultrasound
signals recovered by the vehicle. In assessing matched
defects for quantitative change in the period between
the two inspections, the tolerance on measurement is
considered as part of the process. Matched defects are
flagged as changed based on a variation from the signal
parameters outside the expected deviation based upon
the tool tolerance.
48
Assessment process
Once reported, anomaly signals are matched between the
two inspections, using the following process.
Measurement bias is the difference between the mean
of repeated measurements of the same defect under the
same conditions and the actual size of the defect (i.e. the
measurement precision). It can change between ILI tools
if systemic, and/or from defect to defect. Systemic bias is
present if one ILI inspection is found to consistently underor over-size the defect when compared to another inspection.
Systemic bias could also vary along the pipeline, for example
when one inspection has over-speed areas.
To study the effect of the measurement error the tool tolerances
and test-loop data can be studied. Test-loop data is very
useful but is often idealized, in that the run is under optimal
conditions and the anomalies are machined typically with
regular profiles, quite different from operational conditions
and cracking defects found in pipelines. Another practical
approach is to consider ‘static’ defects and compare the signal
response from these defects that have not changed between
inspections.
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• The analyst located the corresponding area in both
data sets using the software as described above. The
corresponding region in the other inspection data set
will contain either an ultrasonic signal or no signal
at that location.
• When the corresponding location contains an
ultrasonic signal, the data is reviewed and the areas
compared. For areas that were previously analysed the
classification and sizing are reviewed and adjusted if
necessary. This adjustment is performed to ensure that
the same classification and sizing rules are applied to
both data sets, reducing the effect they may have on
the growth estimations.
• When the corresponding area does not contain any
ultrasonic signal it is assumed the feature is new.
• From a detailed comparison of the sensor-by-sensor
signal for each of the two inspections, an analyst makes
a judgment on whether there has been a change to
the feature that produced this signal.
• A number of parameters can then be extracted from
each signal in order to make a comparison between
features on a quantitative basis to supplement
the experienced interpretation and comparison
undertaken by the analysis team. In order to extract the
parameters from each feature, a detailed information
file is generated for each anomaly in both inspections.
This contains details of the constituent crack
indications in the case of crack fields, and a relative
profile in the case of isolated cracking indications.
• The parameters extracted from both data sets are then
compared and a quantitative assessment of change is
made for each feature, in accordance with expected
variation due to tool tolerance. From these assessments
a composite rating of change/no-change is assigned
to each feature.
• The last step in the assessment process is to compare the
qualitative and quantitative assessments and to check
those features having differences in their assessments.
After re-visiting the features, a final assessment is made
distributing the features in two categories:
and is associated with the deviation of repeated measurements
of the same defect under the same conditions. This scatter is
dependent on the inspection tool used and can be obtained
from test-loop data.
* Active: definite changes observed between
inspection signals consistent with growth.
* Not active: any changes observed between
inspection signals do not indicate feature growth.
Measurement error
When the ILI data sets are correctly aligned and matched then
the measurement uncertainty is essentially comprised of two
components, scatter and measurement bias [6].
Scatter is represented by the measurement standard deviation,
Identifying genuinely static defects in USCD data is difficult,
as the user needs to be certain that they are indeed static. In
addition, the sample size needs to be large enough statistically,
and representative of the reported depth ranges. To investigate
measurement error further, cracking indications were
analysed from the database of historical inspections. When
a re-inspection period is very short, i.e. less than on month,
then it is reasonable to assume that any anomalies identified
in the inspection are ‘static’ as the time interval is too small
to expect any significant change in the anomaly. When long
pipelines are inspected they are often done so in several passes
due to constraints on battery life. However, overlap areas exist
between each pass and cracking anomalies in these overlap
areas were considered for the measurement-error study.
Typically, overlap distances are quite small so multiple data
sets were collected to ensure a sufficiently large sample with
a representative population.
The same process, as detailed earlier, was used to calibrate,
match, and size the recorded signals for the inspection runs.
The signal pairs were then studied for variance in the recorded
parameters.
Although the actual sizes of the anomalies are unknown,
it can be seen that under operational conditions, for real
pipeline anomalies, the recorded signals are very consistent,
as seen in Fig.9. The resulting growth error had a standard
deviation of 0.45mm; in other words, the predicted depths
were within ±0.88mm, 95% of the time. So considering a
typical re-inspection period of five years, the crack-growth rate
can be estimated within ±0.18mm/year at a 95% confidence
level. Also the threshold level above which crack growth rates
can be determined with this accuracy would be 0.18mm/year.
1st Quarter, 2012
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Fig.9. Comparison of recorded amplitudes.
Fig.10. Example of a non-active cracking indication.
Example
After studying test-loop and operational data, several repeat
USCD inspection data sets were analysed specifically for the
identification of crack growth using the processes detailed in
this paper. Linear growth was assumed and calculated using;
depth growth rate =
d2009 - d2005
t 2009 - t 2005
where d2009 is the maximum depth of a feature in the run in
2009 on date t2009, d2005 is the maximum depth of the feature
in the previous run in 2005 on date t2005.
All reported anomalies were matched using automatic
algorithms and then a selection was subjected to further
detailed analysis. Anomalies were selected for detailed
comparison based on their reported dimensions, relative
severity calculated using fracture-mechanics’ techniques,
those identified as showing potential growth based on the
automatic comparison, and any areas of interest identified
by the operator. Figures 10 and 11 show a sample of the
recorded signals for an active and non-active anomaly. Based
on the detailed analysis, crack-growth rates were provided
for the selected anomalies.
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Fig.11. Example of an active cracking indication.
Fig.12.Typical
failureassessment
diagram (FAD)
Level II.
Further work
It is highlighted that whilst comparing ILI data sets to
quantify growth is not new, the process for crack-detection
ILI vehicles is still evolving. The knowledge gained from
developing processes for corrosion growth using magnetic
and ultrasonic tools can be leveraged to applications in
quantifying crack growth, and the results to date show
that the recorded signals are very consistent between
inspections. Yet further work still needs to be performed,
particularly with calibrating data sets to reduce the effect
of measurement bias, algorithm development to enable
automatic signal comparison, and further validation of
the obtained crack growth rates.
1st Quarter, 2012
51
Engineering criticality assessment
of reported cracks
Key element 3 – a fracture-mechanics’-based method
with material testing data to identify significant SCC
and crack-like features.
There is a range of accepted industry and proprietary methods
such as API 579 Level II FAD [10], BS 7910 Level II FAD [11],
CorLAS (corrosion life-assessment software) [12] and CEPA
SCC RP [8], that are commonly used to predict the failure
pressure and safe operating pressure for crack features reported
by ILI and from field investigations.
The Level II fracture-assessment methodology is described below
and illustrated in Fig.12. The vertical axis of the FAD is the ratio
(Kr) of the applied stress-intensity factor K (or, applied J-integral
J, or crack-tip-opening displacement CTOD) to the material’s
fracture toughness KMAT (or JMAT, or CTOD critical). The
horizontal axis is the ratio (Lr) of the applied stress to the
plastic collapse stress (generally the SMYS). In order to assess
the significance of a particular flaw in a structure, one must
determine the values of Kr and Lr associated with that flaw
and plot the point on the diagram. If the assessment point lies
outside the area bounded by the axes and the assessment line,
the flaw is said to be unacceptable; however if it lies inside the
line, the flaw is acceptable.
Kariyawasam et al. [13] compared the crack-interaction methods
and the predicted failure pressures vs a series of full-scale burst
tests (conducted by APIA RSC) on pipeline samples containing
SCC colonies that had been inspected using both ultrasonic
crack detection tools and in-the-ditch non-destructive testing.
The actual failure pressures and failure paths from the burst
tests were used to examine and validate the most-accurate
assessment methods and interaction rules for SCC colonies,
and provided insight on how various crack alignments within
a colony interact.
The FAD shows the proximity of a planar defect to plastic
collapse (Lr is typically between 1.0-1.3) and brittle fracture (Kr
= 1). It gives a visual indication of the acceptability of the defect
as a combination of stress, feature dimensions, and specified
material properties. The closer the defect lies (inside) to the
FAD curve, the higher the risk of failure.
Of the interaction rules considered, the CEPA method gave
the most-accurate prediction, whilst the API 579 and CorLAS
assessment methods both predicted the failure pressure within
12% of actual based on the in-the-ditch measurements.
In addition to the above assessment of the immediate integrity
of a crack found in a pipeline, a future integrity assessment
taking into account conceivable crack-growth mechanisms is
required. For SCC it is normal to take into consideration the
predicted SCC growth rate (see the previous section of the
paper). Note that if the pipeline is also subjected to significant
internal pressure fluctuations, an assessment of pressure-cycleinduced fatigue-crack growth should also be considered and
the minimum time to failure from fatigue or SCC growth
should be taken in developing a suitable future repair plan
and re-inspection interval. API 579 provides an approach for
assessing the remaining fatigue life.
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The failure pressure is calculated by forcing the given crack to
become a critical crack, i.e. by determining the pressure at which
the given crack dimensions lie on the FAD curve.
Using the ILI-reported crack-field length and maximum-depth
dimensions, the percentage error on the predicted to actual
failure pressure was as high as 39%. However, using the ILI
crack-field details (see the section on crack profiling and field
statistics, above) together with the CEPA crack-interaction
method, the percentage error dropped to within 15%.
Sensitivities to material testing procedures were also evident
in the burst-test results. The toughness characterization was
performed using both Charpy V-notch testing and J-testing.
J-testing, as expected, gave less-conservative results than the
Charpy values. Approximately 9-12% difference was seen
for the samples tested. Tensile testing of both longitudinal
and transverse coupons was performed, as the tangential or
transverse strength is more appropriate giving a 3% better
match with the actual burst pressures.
API 579 Level II FAD
The API 579 FAD (failure-assessment diagram) approach
outlines fracture-mechanics’ methods for analysing the
acceptability of flaws in many types of structures and
components. Three levels of assessment are described in the
recommended practice: Level I, the simplified assessment
method; Level II, the normal assessment method; and Level
III, a ductile tearing instability assessment. The advantage
of the API 579 approach is that it is a two-parameter failure
assessment that simultaneously considers failure through both
(brittle) fracture and net-section (plastic) collapse.
Input data required for the API 579 Level II FAD
The results of the Level II failure-assessment diagram can be
conservative depending upon the input data used. The main
inputs required are:
• crack dimensions (length and depth, although equivalent
dimensions can be used);
• loading conditions (for example, for an axial crack the
hoop stress induced by the local internal pressure); and
• material properties (material toughness, yield and
tensile strength).
Each of these inputs can be represented by conservative values
– such as upper-bound crack dimensions, specified minimum
material properties, and MAOP value – which will result in a
conservative failure-pressure prediction. However, the difficulty
comes in deciding what level of safety factor is then required
on the predicted failure stress in order to determine the safe
operating stress or pressure value. A better approach is to utilize
the most-accurate predictions available for these inputs and
52
then benchmark the results against known information before
deciding on a suitable safety factor to use. For example, if any
failures have occurred in the past this information can be used
in order to benchmark the assessment method and inputs.
Alternatively, if any of the assessed ILI results are indicating
that failure should have occurred already, yet the line has
remained in-service, this indicates inherent conservatism in
the approach or inputs being used, and again can be used as a
benchmark on which to decide whether an additional safety
factor is required or not.
The authors would like to thank GE Oil & Gas for the
permission to publish this paper.
References
1. M.Slaughter, 2010. Comparison of multiple crack
detection in-line inspection data to assess crack growth.
Australian Pipeline Industry Association (APIA),
October.
2. M.Gao, R.Kania, C.Garth, R.Krishnamurthy, S.Millan,
and S. Fairbrother, 2008. SCC integrity management
for a gas pipeline using a combined approach, EW ILI,
calibration excavation, and FAD analysis. IPC 200864535, ASME.
3. US Department of Transportation. Pipeline safety:
pipeline integrity management in high consequence
area (gas transmission pipelines). 49CFR Part 192.
4. US Department of Transportation, 2003. Pipeline
safety: stress corrosion cracking (SCC) threat to gas
and hazardous liquid lines. Advisory Bulletin, Federal
Register, 68, 195, 8 October, Notices.
5. C.E.Jaske, J.A.Beavers, and B.A.Harle, 1996. Effects
of stress corrosion cracking on integrity and remaining
life of natural gas pipelines. NACE International
Conference.
6. S.J.Dawson, J.Wharf, and M.Nessim, 2008. Development
of detailed procedures for comparing successive ILI runs
to establish corrosion growth rates. PRCI EC1-2.
7. T.Hrncir and S.Turner, Centennial Pipe Line, LLC;
S.J.Polasik and P.Vieth, DNV Columbus; D.Allen,
I.Lachtchouk, P.Senf, and G.Foreman, GE Oil & Gas,
PII Pipeline Solutions; 2010. A case study of the crack
sizing performance of the GE ultrasonic phased array
inspection tool on the Centennial pipeline, using DNV
for the defect evaluation, including the field feature
verification and tool performance validation. IPC.
8. Canadian Energy Pipeline Association, 2007. Stress
corrosion cracking recommended practices. SCC
Working Group, Canada. 2nd Edition, December.
9. API, 2005. In-line inspection system quantification
standard. Standard 1163, First Edition, August.
American Petroleum Institute, Washington, DC.
10.API, 2007. 579-1/ASME FFS-1 2007 Fitness for service.
American Petroleum Institute and The American Society
of Mechanical Engineers Publishing, June.
11.British Standards, 2005. BS 7910: Guide to methods for
assessing the acceptability of flaws in metallic structures.
12.C.E.Jaske and J.A.Beavers, 1998. Review and proposed
improvement of a failure model for SCC of pipelines.
Vol.1, Proc. 2nd Int. Pipeline Conf., IPC-98, pp439445, Calgary, Canada. ASME, June.
13.S.Kariyawasam et al., 2009. Stress corrosion crack
detection, analysis, and assessment improvements for
effective integrity management. 16th Biennial Pipeline
Research Joint Technical Meeting of APIA, EPRG,
and PRCI.
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As described earlier in the paper, advances in the interpretation
and signal analysis of cracks detected by ultrasonic ILI has
resulted in the ability to report more-accurate crack profiles
and crack-field information. Using these more-accurate crack
dimensions together with established crack-interaction and
fracture-analysis methods allows for significant reductions in
the unnecessary conservatism previously associated with the
assessment of cracks in pipelines based on ultrasonic ILI data.
This enables a more-realistic determination of a pipeline’s
fitness-for-purpose, and allows for better-informed integrityand maintenance-planning decisions, such as repair plans,
setting re-inspection intervals, and establishing safe operating
pressure levels.
Acknowledgments
Conclusions
This paper has described recent advances in ultrasonic crack
detection ILI data analysis techniques for improving the
sizing accuracy of longitudinal cracks and SCC colonies.
These advances have resulted in the crack-profiling and
crack-field-mapping signal-processing techniques. These
techniques enable the determination of a more-accurate size
of the effective area of the flaw and of the most significant
cracks within a crack field.
The direct benefits in using an in-depth NDE programme to
improve the reliability and accuracy of ILI crack inspection
data has also been discussed in this paper. A case study,
in which this process was applied in order to determine
absolute depth measurements, clearly demonstrates the
benefits realized by pipeline operators, whether it is used
to improve a single set of crack-inspection data or data sets
for a reliable crack-growth assessment.
The paper has described the process used to analyse repeat
ultrasonic crack-detection ILI data in order to identify active
from non-active cracks and to estimate crack-growth rates.
The accuracy and level of confidence associated with the
estimation of crack-growth rates are also discussed.
Overall, the key benefits to the pipeline operator resulting
from the advancements described in this paper are associated
with the ability to use the more-accurate crack-dimensional
data and estimated crack-growth rates in engineeringcriticality assessments, leading to cost-effective and confident
decision making on crack mitigation, repair, and setting
re-inspection intervals.
1st Quarter, 2012
53
Independent validation of in-line
inspection performance
specifications
by Taylor Shie*1, Dr Tom Bubenik1, and Daniel J Revelle2
1
2
DNV Columbus, Dublin, OH, USA
Quest Integrity Group LLC, Boulder, CO, USA
U
NDERSTANDING THE CAPABILITIES of available in-line inspection tools is a key component of
accurately managing and assessing pipeline integrity. Det Norske Veritas, USA, (DNV) was retained
by a pipeline operator to provide support in evaluating the Quest Integrity Group (Quest) InVista tool.
A
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The Quest InVista tool is a straight-beam ultrasonic tool that is capable of detecting and sizing dents, metal
loss, and dents with metal loss.This multiple-phase project evaluated the performance of the inspection tool
against its stated capabilities.The Quest InVista tool is an emerging technology and was designed to navigate
tight bends (up to 1D) and back-to-back bends. By running this test the operator gained an independent
verification of the performance specifications of a new inspection technology. To evaluate the InVista tool
DNV: created a list of defects to be used for testing the tool; manufactured the defects on test sections of
pipe; supervised the testing of the test sections; and reported the results of the testing. Each stage of the
project is reviewed in detail in this paper.
PIPELINE OPERATOR was interested in understanding
and documenting the capabilities of a new in-line
inspection (ILI) tool. The InVista tool from Quest Integrity
Group (Quest) provided an opportunity for the operator
to inspect a set of lines that were previously considered
unpiggable. While appreciating the ability of a bidirectional
tool to navigate tight bends, the operator wanted to have
an independent evaluation of the anomaly detection and
sizing capabilities of the InVista tool.
Det Norske Veritas (DNV) was retained by the operator to
design and run a test of InVista’s capabilities. The particular
focus of the operator was the ability of this ultrasonic tool
to detect and size dents and dents with metal loss. The
operator was interested in using the InVista tool in a highly
urbanized area where excavations cost in the hundreds
of thousands and of dollars a leak would be guaranteed
to affect a high-consequence area. Because of this, the
operator needed to have a high confidence that the tool
would perform to the stated capabilities without costly and
unnecessary validation digs.
tel: +1 614 761 1214
The operator also had a very tight decision timetable to
determine whether it should use the InVista tool or another
inspection technology. Being able to make a decision on the
whether the tool was appropriate for its purposes sooner
would prevent the operator from performing two or three
surveys on the same pipeline.
The operator sought out DNV for its expertise in a wide
variety of ILI technologies as well as its track record of getting
projects done technically accurate and quickly. Based on
discussions with the pipeline operator, the following phases
of this project were developed:
• Phase 1 – creation of defect list for testing
• Task 1: Determine the type of defects to assess
• Task 2: Determine the number of defects to
examine
• Task 3: Determine the number of runs through
a test section
• Task 4: Determine how to manufacture the defects
on the test section
• Phase 2 – Manufacturing defects on test sections
• Phase 3 – Supervision of testing at Quest’s facility
• Phase 4 – Assessment of flow loop testing results
A description of each of these phases and the results of
each phase are provided in the sections following.
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Table 1. Primary focus
defect list.
Phase 1: creation of a defect list
for testing
Phase 1 of this project was to determine the type and number
of defects to assess, determine the number of runs through
the test sections, and determine how to manufacture the
defects. The operator was most concerned about obtaining
accurate information about dents and dents with metal loss
that may exist in its pipelines. This was particularly important
in areas that were difficult or prohibitively expensive to access
in an urban area. Because of the urban area and the high
volume of third-party activity near the pipeline operator’s
assets, dents and dents with metal loss were the most likely
threat to the pipeline.
The results of this work are seen in the subsections below.
Task 1: types of defect to assess
Defects were identified as either a primary focus or as a
secondary focus. Dents and dents with metal loss were
identified as primary focus defects. Metal loss was a secondary
focus defect.
Task 2: number of defects to assess
Prior to determining the number of defects to assess,
important characteristics of the primary defects were
determined. The characteristics chosen are shown below
with the variation within the characteristic:
• dent depth (% of outer diameter): 0.5%, 1%, 1.5%,
2.5%, and 4%
• Metal-loss depth (% of nominal wall thickness): 0%,
10%, 20%, and 30%
• Metal-loss area (equivalent area): 2t x 2t, and 3t x 3t
• dent area: round ball and wedge indenters
Dent depths were chosen to represent the range of dent
depths that are typically found on pipelines. Two dent
depths were selected to test the ability of the tool to detect
at a common reportable threshold for dents. Some pipeline
operators request a reportable depth of 0.250in on 10-in
nominal diameter pipe from ILI vendors. The 1.5% dent
was selected to be just below the reportable depth, and the
2.5% depth was selected to be just above the reportable
depth. The other three depths of 0.5%, 1%, and 4% were
selected to assess the tool’s performance with features that
are both shallower than the reporting threshold and deeper
than the reporting threshold.
The metal-loss depths were selected based on the reporting
1st Quarter, 2012
55
threshold typically requested by pipeline operators from an
ILI vendor (10%). Two times the reportable depth (20%),
and finally three times the reportable depth (30%), were
also included.
The areas of the metal-loss features were selected based on
the defects Quest assessed in its test loop (2t x 2t and 3t
x 3t). The majority of metal loss was selected to be on the
bottom of the dent because that is primarily where metal
loss is seen in dents. Some metal loss was also selected to
be made on the slope and shoulder of the dents. Equivalent
areas were selected to be used for metal loss so the length
and width of each feature could be varied.
Two indenters were selected to distinguish the difference
between a dent formed by a rock and a dent that could
potentially be caused by an excavator. A round-ball indenter
was used to be approximately the size of a rock, while the
wedge indenter was approximately the size of the tooth on
an excavator.
63 primary-focus defects and 41 secondary-focus defects were
manufactured on the test sections as a result of this phase,
totalling 104 defects manufactured on the test sections.
This number of defects represented the greatest number of
defects that could be manufactured on the test sections of
pipe without affecting the ability of the ILI tool to detect
and size the defects.
Task 3: number of runs through a test section
The data set designed in Task 2 of Phase 1 was a statistically
sufficient number of defects to assess the performance of
the tool. DNV recommended that at least three successful
surveys be performed. DNV also recommended that Quest
perform as many surveys of the test sections as possible within
the time allowed. As more data are collected, the confidence
is higher in the probability of detection, the probability of
sizing, and the sizing accuracy that are obtained.
Phase 2: manufacturing defects on
test sections
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A factorial approach was used to create a balanced statistical
design to the experiment that simultaneously considers all
parameters stated above: every combination of the above
parameters was determined and then pared down. The
list was pared down by eliminating redundant defect types
to eliminate any potential bias in the defect set toward one
type of defect.
uses the interaction criteria defined in API 579-1/ASME
FFS-1 (API 579).
The results of the factorial approach can be seen in Table 1,
which presents the 28 dents that were created with both the
ball indenter and the wedge indenter. The table also shows
the seven 0.5% dents that were made with just the wedge
indenter for a total of 63 primary defects on the test sections
of pipe. This provides a statistically valid data set to assess
all possible combinations of the defect characteristics (dent
depth, metal-loss depth, metal-loss area, and indenter type).
DNV also determined the number of secondary-focus defects
to manufacture on the test sections. A factorial approach
was used for metal-loss depths, metal-loss area, and location
(internal or external). The parameters for the secondary-focus
defects were as follows:
• metal-loss depth (% wall thickness): 10%, 20%,
and 30%
• metal-loss area (equivalent area): 1t x 1t, 2t x 2t,
and 3t x3t
• location: internal, and external
Using the factorial approach, there are nine combinations
of metal-loss depth and metal-loss area. Four of each of the
secondary-focus defects were manufactured on the pipes.
The metal loss on the external surface was manufactured
with one set on each test section, one set on the internal
surface (split between the two test sections), and one set
used to assess the interaction criteria of the tool. Quest
The purpose of this phase was to manufacture defects on
the test sections of pipe that were used for evaluation of the
ILI tool. It was important for all the 104 defects that were
created to resemble real-world defect shapes and sizes in
order to ensure that the tool was tested against the defects
that it was most likely to encounter.
Creation of test sections
To create the test sections of pipe, two 40-ft sections of API
X-42 pipe with high-frequency ERW longitudinal seam weld
and 0.365-in nominal wall thickness were purchased. The
40-ft sections were each cut to the 23-ft length of the test
sections to accommodate sizing requirements of the Quest
test loop. The actual wall thickness of the pipe was measured
to be 0.355in prior to the manufacturing of the test sections.
The bend test section was manufactured from two long-radius
90o elbows welded together to form a 180o bend that had a
3-D radius. The elbows were both API grade B pipe with a
0.365-in nominal wall thickness.
Ball-shaped dent manufacture
The ball-shaped dents were manufactured to mimic the size
and shape of dents caused by rocks. To create these dents,
a 3.5-in diameter steel ball bearing and a 20-ton press were
used. An example of a dent that was created using this
method can be seen in Fig.1.
Wedge-shaped dent manufacture
The wedge-shaped dents were designed to mimic a third-party
strike on a pipeline. To accomplish this, DNV welded a 4-in
long backhoe tooth onto the 20-ton press. An example of the
dent that was created using this setup can be seen in Fig.2.
56
Phase 3: supervision of testing
The Quest tool is not an ILI tool that was originally designed
to the API 1163 standard. Because of this, DNV sent a
staff member to Quest’s facility to supervise the testing of
the defects created as well as to review the process used for
analysing the data collected by the tool.
Fig.1. Example of a 4% dent created using a ball bearing.
It was important to the operator that the test be performed
blind (i.e. Quest having no knowledge of the defect set).
Having a blind test gave more confidence to the operator
that Quest was not gearing its tool to size and detect a certain
type of defect. Prior to manufacturing the test sections, DNV
discussed maximum defect sizes with Quest to ensure that no
damage was done to the Quest tool during testing. This was
the only information discussed with Quest prior to testing.
For the testing, two representatives from the operator and
one representative from DNV were present. Quest was very
transparent with its operation and answered all questions
that were asked of it to the observing group’s satisfaction.
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Test loop set-up
Fig2. Example of a 4% dent created using a backhoe tooth.
Quest has a series of test loops outside its Kent, WA, facility
that are used for testing various sizes of its ILI tools. The
test loops range in diameter from 3in to 12in and have a
number of features, such as tight bends, that can make a
pipeline unpiggable. A photograph of the test loops for the
10-in and 12-in pipe is shown in Fig.4, in which the 10-in
test sections are painted blue while the 12-in test sections
are painted yellow. The 10-in and 12-in sections are one
continuous loop.
The testing for this project took place in the modified test
loop that is shown in Fig.5. In this loop, the test sections
created in an earlier phase were wrapped in black plastic
with grey tape and placed above the existing 10-in and 12in test loops to provide a blind test for Quest. The bend
manufactured by DNV was attached with a flange to Pipe
2 and can be seen with the protective plastic wrap covering
the bend.
Fig.3. Example of a 1.5% wedge dent with metal loss of 2t x
2t and 30% depth.
Metal loss
The metal-loss defects were created using either a rotary
tool or an angle grinder depending on shape and depth.
Because the Quest tool is ultrasonic and not magnetic,
changing the electromechanical properties of the parent
material was not a concern for manufacturing these defects.
The shape of the areas used for the 1t x 1t, 2t x 2t, and 3t
x 3t areas of metal loss were varied from defect to defect.
The depth profile of the metal-loss defect was varied from
defect to defect, and an example of metal loss in a dent can
be seen in Fig.3. Two additional metal-loss defects were
created in the pipe sections than were specified in Phase
1, yielding 104 defects and not 102 as designed.
When the surveys were performed in the test loop, the tool
was launched and received from the same launcher/receiver
and navigated the 10-in sections of the loop. Following the
10-in sections of pipe there is a bend that contains a stopper
that prevents the 10-in tool from entering the 12-in sections
of pipe. Once the ILI tool reached the stopper bend, flow
is reversed and the tool returned through the loop in the
opposite direction to which it had just travelled.
Pre-testing
Prior to the testing of the ILI tool in the test loop, a brief
diagnostic review of the tool was performed to ensure that
the tool was charged and properly set-up for testing. Quest
was able to confirm the diagnostics of the tool with the
calibration sections that are built-into the test loop.
1st Quarter, 2012
57
Fig.4. Original 10-in (blue) and 12-in (yellow) test loop set-up.
Testing
The 10-in test loop has a built-in unbarred tee and a gate
valve immediately following the 10-in tool launcher, and
these are two elements that are considered to be unpiggable
by some ILI vendors. There are also 1-D bends, 90 o
elbows, and multi-directional bends in the test loop that
the tool navigated without issue.
Following completion of the pre-test procedures the
surveys were performed. Because the tool is bi-directional,
the tool collected data in both the forward and reverse
directions. Five complete loops of the survey were
performed which resulted in ten passes of the test sections:
this represents a sufficient statistical sample of the test
sections, and the results of the surveys are analysed below.
Post-testing
Table 2. Percent detected for dents.
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A test run was performed in the loop prior to performing
the surveys for evaluation, and a foam pig was used to
push air out of the test sections. Following these steps,
the testing proceeded without any issues.
Fig.5. Modified 10-in test loop set-up.
Following the completion of the surveys, the tool was
removed from the test loop and appeared to be in the same
condition coming out of the loop as it did going into the
loop. Once the tool was returned to the shop, the tool
was coupled to a computer that checked the quality of
data that were collected and then downloaded the data.
Quest staff stated that the data appeared to be of good
quality and all of the sensors of the tool collected data
for the entire series of surveys. The data collected were
then sent through the Quest proprietary filter software
and then scans of each of the surveys were available for
review. During preliminary review of the survey scans,
the defects that were created in an earlier phase of the
project could be seen. The tool navigated the test loop
at the desired speed of 1.5ft/sec.
Table 3. Percent detected for wedge dents.
Table 4. Percent detected for ball dents.
Phase 4: assessment of test results
The operator wanted to be sure that the Quest tool provided
results that were at least as good as results that were expected
from API 1163 inspection technologies. In order to assess
the performance of the InVista tool, DNV used elements
of API 1163: specifically, section 7 of API 1163 was used in
the assessment of the Quest tool’s stated capabilities taken
from its published brochures. It was also important for the
operator to understand which features the tool tended to
overcall or undercall when making decisions on remediation.
Percent detected
The probability of detection (POD) is defined by API 1163
as “the probability of a feature being detected by an ILI tool.”
Tables 2, 3, and 4 show the percentages detected for all dents,
wedge-indenter dents, and ball-indenter dents, respectively.
As can be seen in Table 2, the percent detected for all dents
was approximately 97%. There was one dent that was not
detected and another that was detected but incorrectly
identified. Quest typically uses a dent-reporting threshold
of greater than 1%, and both of the dents that were not
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Table 5. Percent
detected for metal-loss
defects on straight
pipe (no dent(s)).
There were no false positives reported by the tool: in every
instance where the Quest tool detected a feature there was
a defect that had been manufactured by DNV. There was
one instance of a false negative for dents, and there were
five instances of false negatives for metal-loss defects on
straight sections of pipe. Each of these five false negatives
is discussed elsewhere. The same number of false positives,
true positives, and false negatives were seen in all five
surveys, giving a repeatability of 100%.
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reported were wedge dents that were less than 1% in depth.
For the dents that were above the 1% reporting threshold,
the percent detected was 100%.
As can be seen in Table 2, the percent detected for all dents
with metal loss was approximately 91%. One wedge dent
was not correctly identified as a dent with metal loss and
was identified as an external metal-loss feature which was
below the detection threshold of the Quest tool. There were
four dents with metal loss that were detected and not correctly
identified, the details of which are:
• ball dent: 1.5% dent depth with 20% deep 2t x 2t
metal loss
• ball dent: 1.5% dent depth with 30% deep 3t x 3t
metal loss
• ball dent: 4% dent depth with 30% deep 2t x 2t metal loss
• ball dent: 4% dent depth with 30% deep 3t x 3t metal loss
The first ball dent on the list above was identified as a plain
dent when it was actually a dent with metal loss; the other
three were identified as dents, but Quest stated that it was
not able to determine if the dent contained metal loss or
not. All four of these features had a signal that is associated
with metal loss in at least one of the surveys. However, this
was not enough for Quest to identify these features as dents
with metal loss.
Table 5 presents the percent detected of metal-loss
features in the straight test sections of pipe. On the
straight sections of pipe, five metal-loss features were
not detected by the tool, and all five features were below
the minimum area threshold for detection of the tool.
The minimum area threshold for detection of the tool is
0.25in2 (i.e. 0.5in by 0.5in equivalent area). One feature
was identified as an external metal-loss feature and was
actually a shallow wedge dent and was not included in
the assessment that follows.
The Quest tool was able to detect and size, within tolerance,
approximately 97% of the dents and approximately 91% of
the dents with metal loss. 36 of the 41 metal-loss features
manufactured on the straight sections of pipe were detected
and sized. The five metal-loss features on straight sections
of pipe that were not detected were below the minimum
area required for detection.
Detection and sizing threshold
The detection and sizing thresholds stated by Quest in its
specifications appear to be accurate, and the company was
able to detect and size dents that were below these stated
capabilities. There were only two features that were not
identified as dents, both of which were less than 0.5%
dents made with the wedge indenter. One of the dents was
0.23% deep and was not detected by the tool in any of the
five surveys; the other 0.5% dent that was detected by but
not correctly identified had a 30% metal-loss defect that
was 3t x 3t and was reported to be an external metal-loss
defect. The depth and area of the corrosion manufactured
in the defect may have masked the tool’s ability to correctly
identify the feature.
Quest detected metal-loss features correctly provided the
area of the feature was greater than 0.25in2, which is the
tool’s stated capability. Of the 40 metal-loss features that
were manufactured on the test sections, the tool was able to
detect and size 35; the five that were not detected and sized
1st Quarter, 2012
59
were all 1t x 1t features. With a nominal wall thickness of
0.365in, the area of a 1t x 1t feature is 0.133in, which is
below the detection threshold of the tool.
Quest detected all of the 1t x 1t features that were on the
internal surface of the pipe and 70% of the 1t x 1t features
on the external surface of the pipe. The tool did not detect
1t x 1t features in any of the 10%, 20%, and 30% depth
categories; because of this, it appears that area of metal loss
was the limiting factor of the tool’s performance.
Sizing accuracy
The sizing accuracy of the tool was also assessed during this
project. The tool was assessed for its ability to accurately size
the following:
dent depth
depth of metal loss in dents
depth of metal loss in straight pipe
axial length of metal loss in straight pipe
circumferential width of metal loss in straight pipe
Of the 24 ball-dent defects that had metal loss manufactured
into the dent, the Quest tool was within its metal loss sizing
tolerance for 17 of the features. There were two metal-loss
defects of the seven that were outside of the sizing tolerance
by 5 mils or less; these two features could be considered in
tolerance when accounting for slight inaccuracies of external
metal-loss measurements.
MFL vendors typically state tolerances of reported metal loss
features as ±10%2 for straight pipe. MFL vendors do not typically
state a sizing tolerance for metal loss in dents.
The Quest report provided one measurement for axial length
and circumferential width of the features that it detected and
sized. For dents and dents with metal loss, these measurements
were for the dent size and not for the metal loss in the dent.
Because of this, no comparison was made of the axial length
and circumferential width sizing of the metal loss in the dents.
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•
•
•
•
•
the 30 wedge dents that had metal loss manufactured into
them, the tool was within the stated metal loss sizing tolerance
for 22 of the features. Of the eight that were outside of the
sizing tolerance, four were in dents that were below the tool’s
detection threshold.
Dent depth-sizing accuracy
As outlined earlier, there are nine categories for the
dents that were manufactured on the test sections. Table 6
summarizes the mean dent depth as measured by DNV, the
dent depth as reported by Quest, the difference between the
two measurements in percent depth, the depth tolerance of
the tool, and whether the reported measurement was within
the tolerance band. The Quest tool has a dent depth-sizing
tolerance of ±0.020in, corresponding to a 0.186% tolerance
by percentage of diameter.
As can be seen in Table 6, the tool on average was within the
tolerance range in five of the nine dent categories, and there
was only one category (4% wedges) where the tool was more
than 0.1% outside the sizing tolerance. The 0.5% dents created
with the wedge indenter were below the detection threshold
of the tool; however, Quest was close to meeting its sizing
tolerance for these features.
The 4% wedge dents were measured by DNV technicians
to average 3.52% depth. The Quest tool measured the same
dents to average of 4.25% depth. The Quest tool oversized this
feature grouping by 0.74%. After applying the sizing tolerance
of 0.19%, the difference between the two measurements is
0.55%. Caliper tool specifications from other vendors show a
±0.25% tolerance1 for an equivalently sized tool for a nominal
10-in pipe. Applying this tolerance to the tool data, all but the
4% wedge dents were within the tolerance.
Depth of metal loss sizing accuracy in straight pipe
Of the 41 metal-loss features that were manufactured in
the straight sections of pipe, 26 were within the depth-sizing
tolerance, five were not detected, five were undersized, and
five were oversized. As mentioned earlier, the features that
were not detected were below the minimum area for sizing of
the tool. Eight of remaining ten features were not within the
sizing tolerance of the tool but were within 10 mils of being
within the tolerance of the tool. The feature that had the largest
difference in measured size to actual size was 16 mils away
from being in the tolerance range. MFL tool vendors typically
state a ±10%2 tolerance on reported metal loss depth. All of
the features detected would all be within that same tolerance.
Axial length of metal-loss sizing accuracy in straight pipe
Of the 41 metal loss features that were manufactured in the
straight sections of pipe, 31 were within the axial length sizing
tolerance, five were not detected, two were undersized, and three
were oversized. As mentioned earlier, the features that were not
detected were below the minimum area for sizing of the tool.
Circumferential width of metal-loss sizing accuracy in straight pipe
The Quest tool was able to detect and size metal loss that
was manufactured in dents on the test sections of pipe. Of
Of the 41 metal-loss features that were manufactured into the
straight sections of pipe, 32 were within the circumferential
width-sizing tolerance, five were not detected, three were
undersized, and one was oversized. As mentioned earlier,
the features that were not detected were below the minimum
area for sizing of the tool.
1. For example, Enduro third-generation DfL 10-in survey tool – 0.25% detection,
and ±0.03 inch sizing tolerance (specification sheet on Enduro’s website).
2. From tool specification sheets for nominal 10-in pipe from Enduro’s, Rosen’s,
and GE’s websites.
Metal loss in dent sizing accuracy
60
Axial and circumferential location accuracy
There were no obvious discrepancies in feature axial location
or circumferential location between what was measured by
DNV and what was reported by Quest. All of the features
that were detected by Quest were where DNV expected.
This accuracy pertains to both the axial location and the
circumferential location.
The Quest tool has an axial location accuracy tolerance
of ±0.5% from the nearest reference, and also has a
circumferential accuracy tolerance of ±10o. The tool
was within these tolerances for all of the features that
were detected.
Due to the short length of the test loop, the axial-location
performance may not be representative of how the tool
would perform in a longer pipeline. In the short test loop,
the tool did not have sufficient length to show whether
the odometer wheel would slip on a longer run of pipe.
The largest discrepancy in dent depth measurement was
in the 4% wedge-indenter category of dents. On average,
the ILI tool reported these dents as being 0.737% deeper
than they actually were. The tool performed better on
the 4% ball-indenter category of dents. This difference
may not be dependent upon the depth of the feature
but the orientation and sharpness of the feature. The
ball indenter produced a round dent while the wedge
indenter produced an oval-shaped dent.
Quest demonstrated similar ability to size metal loss in a
dent to its ability to size metal loss in a straight pipe. The
majority of the reported metal-loss depths in dents were
within the metal-loss sizing tolerance of the tool: for this
project, this was 0.020in, where an MFL vendor would
use a tolerance of 0.0372-in (10% of the wall thickness).
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Repeatability
the corresponding actual depth. For the purposes of this
project, a statistical R-squared value is how closely the
reported characteristic is to the actual characteristic.
For the reported dent depths, the R-squared value was
approximately 95%, which is an indicator of accuracy.
This value also includes the two dents that were below
the detection threshold of the tool, but were nevertheless
detected and sized.
Overall, the reported metal-loss depths, lengths, and
widths had minimal variation between the five surveys
that were performed. For the features that the Quest
tool was able to detect, the tool had 100% accuracy in
external or internal wall surface discrimination. This was
true for all surveys of the test sections.
Comments on dent feature performance
assessment
Overall, the performance of the Quest tool in detecting,
identifying, and sizing dents and dents with metal loss
was to its stated capabilities. The percent detected for
dents was approximately 97% for the dents that were
manufactured in the test section. When corrected for
dents that were below the detection threshold of the
tool, the percent detected becomes 100%.
The tool had a 91% percent detection rate for metal loss
in dents. There were five dents that were not correctly
reported as a dent with metal loss: one of these features
was reported as external metal loss and was in a dent
that was below the detection threshold for dents; the
other four were reported as either plain dents or Quest
was unable to determine whether metal loss was present
or not. In these four features metal loss was measured
in one or more surveys. However, Quest did not report
these defects as dents with metal loss. There were no
features that were reported as dents with metal loss that
were not dents with metal loss.
The sizing of the dents was also to the company’s stated
capabilities. The tool tended to undersize dents that
were less than 2% and tended to oversize dents that
were over 3.5%. Overall, the reported depths of dents
yielded an approximately straight line when plotted with
Not all of the metal-loss features that were manufactured
in the dents were in the bottom of the dent, and some
of the metal loss was manufactured on the slope of the
dent. Two of the reported metal-loss depths were within
the tolerance of the tool for metal loss and two were not.
Because of the small sample size, it is not possible to make
an assessment of the tool’s capabilities assessing metal
loss in the slope of the dent. The defects with metal loss
in the slope of the dent were:
• 1.5% wedge dent with 20% 2t x 2t metal loss
(sizing outside of tolerance)
• 1% ball dent with 10% 2t x 2t metal loss (sizing
inside tolerance)
• 2.5% ball dent with 20% 2t x 2t metal loss (sizing
inside tolerance)
• 4% ball dent with 30% 3t x 3t metal loss (sizing
outside of tolerance) – not reported as dent with
metal loss
Quest measured a slight wall thinning in some of the
plain dents manufactured by DNV. This wall thinning
probably occurred when the pipe steel plastically deformed
to allow the dent to be created. This reported thinning
is smaller for the shallower dents and becomes deeper
for the deeper dents.
Comments on metal-loss performance assessment
There were 41 metal-loss features that were manufactured
in the test sections of pipe and the tool was able to detect
36 of these on each of the five surveys. The five features
that were missed in each survey were below the minimum
1st Quarter, 2012
61
area of metal loss for detection. When adjusting for the area
detection thresholds of the tool, the percent detected was
100% for this project.
Quest assesses interacting metal-loss features using the
methodology outlined in API 579, and DNV manufactured
four clusters of metal loss to mimic this type of interaction.
There were four interacting features and each feature had
three separate metal-loss features that interacted according
to these interaction criteria. When Quest reported these
features, it reported three separate features at each location.
Because of this, it was not possible for DNV to assess how
Quest performs API 579 interacting calculations.
The tool was able to correctly discriminate between metal
loss that was internal and external for all of the features that
were detected.
Conclusions
For the locations where a dent with metal loss was detected
and sized, the tool’s performance was similar to a situation of
assessing metal loss in straight pipe. MFL tools are typically able
to detect dents with metal loss. However, DNV’s experience
has shown that the ability of an MFL survey to size metal loss
in dents is dependent upon a number of factors (such as tool
speed). The Quest tool was able both to detect and size dents
and the metal loss within the dents to its stated capabilities.
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The Quest tool was within the specified sizing tolerance for
26 of the 36 metal-loss features that were above the detection
threshold. Of the ten that were not within the sizing tolerance,
six were within 5 mils of being in tolerance, and none were
more than 16 mils out of tolerance. MFL vendors typically
state a ±10%2 of wall thickness tolerance for metal loss: all the
features detected by the Quest tool would have been within
this thickness tolerance.
The Quest tool was able to detect and size 61 of the 63 dents
that were manufactured on the test sections of pipe. The
two that were not detected and sized were below the depth
at which Quest felt it could reliably detect dents. The tool
was able to detect and size a dent and the metal loss in the
dent for 49 of the 54 that were manufactured. One of the
five features that were not correctly identified was below the
detection threshold; the remaining four features had a metal
loss reported in one or more surveys but did not warrant
identification as a dent with metal loss from Quest. In three
of these four cases, Quest made a comment that there was
“insufficient thickness data to determine whether or not metal
loss is present”. There were no features that were reported as
“dent with metal loss” that were not a dent with metal loss.
The operator saw this work as a way to blend the support
services of contractors together to get a more complete
assessment of a potential solution to a problem it was facing.
The operator was able to use the ILI technology expertise
of DNV to assess the true capabilities of Quest’s emerging
technology. DNV and Quest were able to work together to
provide a valuable solution to questions that the operator
was investigating.
Because the Quest tool was going to be used in an urban
pipeline system where there is a very active right-of-way, the most
important features for the tool to detect and size were dents and
dents with metal loss. These features were the primary focus
for this test. The tool’s ability to detect and size metal loss was
a secondary focus for the test because the UT ILI technique is a
proven technique in the industry. This project was undertaken
as an assessment of the tool’s performance with respect to the
stated capabilities in Quest’s literature.
The operator was on a very tight timetable for making a decision
on which type of ILI survey to perform in its urban pipeline
system. DNV was able to design a defect set to test the tool,
manufacture the defect set onto test sections, supervise the
testing of the defects, and then deliver a report on the capabilities
of the tool in time for the operator to make the engineering
decision. Making sure that the tool would perform to the
stated capabilities prior to being placed in a pipeline saved the
operator a significant amount of money on validation-dig costs
and potentially running more than one survey on its pipeline.
One of the secondary focuses of this project was to assess
the Quest InVista tool’s capabilities to detect and size metal
loss, and it was seen that the tool was able to detect and size
metal loss that was within the stated detection criteria. The
tool had difficulty detecting metal-loss features that were 1t x
1t because they were below the minimum area threshold for
detection. While individual features may not have been within
the tolerances of the tool, the metal loss data set as a whole
was within the stated tolerances of the tool. There was a slight
mean bias to undersize the axial length and circumferential
width of the external metal-loss features, although this bias
was still within the stated tolerance of the tool.
One of the main selling points of the Quest InVista tool is
that it can traverse 1-D bends. The testing demonstrated that
the tool could traverse 1-D and 3-D bends, as well as other
elements that can cause a pipeline to be considered unpiggable.
The tool also showed that it could be used bi-directionally,
although this capability was not a focus of this work.
Overall, the testing demonstrated that the Quest InVista
tool was able to perform to its stated capabilities, and the
operator was provided with a report stating that the Quest
tool appears to perform at least as well as an MFL tool in
detection and sizing capabilities.
By having such an independent study done, the operator
was able to have increased confidence in past and future
inspections performed by the tool. By running an
independent test in a controlled situation, the operator was
able to validate the tool’s performance without having to
perform as many proving digs: this reduction in validation
digs can lead to extensive cost savings for lines in urban
areas where digs can be costly.
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1st Quarter, 2012
63
Bacterial attachment to metal
substrate and its effects on
microbiologically-influenced
corrosion in transporting
hydrocarbon pipelines
by Faisal M AlAbbas*1, John R Spear3, Anthony Kakpovbia1,
Nasser M Balhareth1, David L Olson2, and Brajendra Mishra2
Inspection Department, Saudi Aramco, Dhahran, Saudi Arabia
Department of Metallurgical and Materials Engineering, Colorado School of Mines,
Golden, CO, USA
3
Department of Civil and Environmental Science and Engineering
Colorado School of Mines, Golden, CO, USA
1
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2
ARBON STEEL PIPELINES ARE considered the most efficient and economic method of transporting
hydrocarbon products in the oil and gas industry. During oil and gas operations, pipeline networks are
subjected to different corrosion deterioration mechanisms, including microbiologically-influenced corrosion
(MIC) which results from accelerated deterioration caused by different microbial activities present in the
hydrocarbon systems. The bacterial adhesion is a detrimental step in the MIC process. The MIC process
starts with the attachment of planktonic micro-organisms that establish biofilm and in turn lead to metal
deterioration. The tendency of a bacterium to adhere to the metal surface can be evaluated by using
thermodynamic approaches via interaction energies.This paper covers an overview of the thermodynamics
and surface-energy approaches of bacterial adhesion, the factors affecting the bacterial adhesion to the
metal surface, the subsequent physical interaction between the biofilm and substratum, and its implication
on the MIC in pipeline systems.
M
I C R O B I O L O G I C A L LY - I N F L U E N C E D
CORROSION (MIC) is of considerable concerns to
the oil and gas industry. MIC has been reported in oil and
gas treating facilities such as refineries and gas-fractionating
plants, pipeline systems, and exporting terminals. MIC can be
responsible for an increase in corrosion rate due the presence
of microbial metabolic activities that accelerate the rate of
anodic and/or cathodic reactions [1]. MIC does not produce
a defined type of damage; however, it mostly results in a
localized type of corrosion that manifests in pitting, crevice
corrosion, under-deposit corrosion, cracking, enhanced
This paper was presented at the Best Practices in Pipeline Operations & Integrity
Management conference held in Bahrain in March, and organized by Tiratsoo
Technical and Clarion Technical Conferences.
erosion corrosion, and dealloying [2-4]. It is believed that MIC
is one of the most damaging mechanisms to pipeline steel
materials. Microbial activities are thought to be responsible
for greater than 75% of the corrosion in productive oil wells
and for greater than 50% of the failures of pipeline system
[5, 6]. MIC has been estimated to account for 20-30% of
all internal pipeline corrosion costs. In 2006, MIC was
suspected as one of the two major factors that shutdown
the major Alaska Prudhoe Bay oil field pipeline. This leak
caused turmoil in the global oil market [7].
Different microorganisms thrive in oil and gas transporting
systems for the reason that all of the essential elements
for life are present in these environments. Microbial life
needs four basic things to thrive in an environment: a
carbon source, water, an electron donor, and an electron
64
Biofilm developmental stages
Fig.1. FESEM Image for a dense biofilm developed by SRB,
Desulfovibrio africanus sp., on a surface of carbon linepipe
steel [19]
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acceptor [8]. Hydrocarbon acts as an excellent food source
for a wide variety of microorganisms; water also exists in
mixed solution with hydrocarbon. Other elements including
sulphur, nitrogen, carbon, and phosphorus that are needed
to support microbial life are also present in the process feed.
The main type of bacteria associated with metals in pipeline
systems are sulphate-reducing bacteria (SRB), iron- and
CO2-reducing bacteria, and iron and manganese oxidizing
bacteria [9]. Among these, SRB has been recognized to be the
major MIC causative agent in pipeline systems. Sulphatereductive activity is thought to be responsible for more
than 75% of the corrosion in productive oil wells and for
more than 50% of the failures of buried pipelines and
cables [10]. Practically, MIC is really the result of synergistic
interactions of different microbes, consortia that coexist in
the environment and are able to affect the electrochemical
processes through co-operative metabolisms [11].
The MIC process starts with a biofilm formation on a
metal substrate. Immobile cells attach to the steel substrate,
grow, reproduce and produce an extracellular polymeric
substance (EPS) that results in a complex biofilm formation
[2, 3]. The biofilm formation encompasses three different
stages, the first of which starts with the absorption of
macromolecules, such as protein, lipids, polysaccharides, and
humic acids that work as a conditioner of the steel surface.
These macromolecules change the physical chemistry of
the interface including the hydrophobicity and electrical
charge. During this stage, microorganisms, and surface- and
aqueous-medium characteristics play a significant role in
the extent of bacterial transfer rate, adhesion, and resultant
biofilm size. The microbial characteristics include surface
charge, cell size, and hydrophobicity. Surface properties
include chemical compositions, roughness, inclusions,
crevice, oxides, or coating and zeta potential, whereas the
aqueous-medium properties include flow regime of the
system and ionic strength [2].
The MIC process starts by the attachment of planktonic
microorganisms to a metal surface that then leads to the
formation of a complex biofilm. During the growth of the
biofilm, and through their metabolic activities, bacteria
catalyze numerous invisible slow electrochemical reactions
at the cell/metallic surface interface. There, metabolic
reactions may be corrosive in nature or may dissolve a
protective surface-oxide films, or both [12].
The literature concerning bacterial attachment and
biofilm development is significant for MIC investigations.
This paper will provide concise reviews that address the
following:
• biofilm developmental stages
• factors that affect bacterial adhesion to the metal
surface
• thermodynamic and surface energies model
approaches of bacterial adhesion
• subsequent physical-chemical interaction between the
biofilm and substratum in pipeline systems with
a focus on SRB.
The second stage involves the microorganisms movement from
the bulk phase to the surface. The bacterial transportation
process is affected by kinetic mechanisms. The initial bacteria
attachment is formed through a reversible adsorption process,
which is governed by electrostatic attraction, physical forces,
and hydrophobic interactions [13, 14]. This initial attachment
is a crucial step in the process of biofilm development. Whether
the transporting cell will adhere or not to the surface depends
on the surface properties, hydrodynamics, and physiological
state of the microbe. The adhesion force is affected by the
physicochemical property of the substrate and the surface
property of the microbial cell. The attached bacteria are called
sessile bacteria and they are more important to the MIC
process than the planktonic bacteria [13]. When sessile cells
reside on a steel surface, their metabolic products introduce
multiple cathodic reactions and thus promoting corrosion.
The third stage includes extracellular polymeric substance
(EPS) production. The adhered microorganisms produce
a slime-adhesive organic substance known as EPS. It has
heterogeneous composition that includes exo-polysaccharides,
nucleic acids, proteins, glycoproteins, and phospholipids [1517]. It has been reported that exo-polysaccharides account for
40-95% of the macromolecules in microbial EPS [18]. EPS
promotes the colonization process on the surface as it makes
it possible for negatively charged bacteria such as SRB to
attach to either negatively or positively charged surfaces. The
further growth of the biofilm depends on the microorganism’s
colonization rate. The microbial transport to the interface is
mediated by: (1) diffusion by Brownian motion; (2) convection
by system flow; and (3) motile movement [2]. The biofilm
development on the surface is an autocatalytic process whereby
the initial microbial migration increases surface irregularities
and promotes the formation of dense biofilm. Figure 1 shows
a developed dense biofilm by SRB, Desulfovibrio africanus sp.,
on a surface of carbon linepipe steel [19].
1st Quarter, 2012
65
Factors affecting biofilm
development
Surface, bacteria, and medium characteristics play a
significant role in the adhesion process and the biofilm
development.
Surface properties
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The surface properties that have significant impact on
bacterial attachment and biofilm development include
surface roughness, polarizations, oxides coverage, and
chemical compositions. The initial roughness is known by the
pattern or texture of surface irregularities that are introduced
by the manufacturing process. There is conflicting literature
on the influence of the surface roughness on the bacterial
attachment process: some literature reports higher bacterial
colonization and adhesion on high roughness surface
while others found the opposite. Korber et al. (1997) [20]
postulated that the roughest surface increases surface area
at the microorganism-materials interface that may then lead
to more film attachment by providing more contact points.
Sreekumari et al. (2001) [21] tested the bacterial attachment
to 304L stainless steel welds and base metal. They reported
more attachment to the weld metal than the base metal,
which was correlated to the average grain size. A larger area
of attachment was associated with smaller grain size as weld
joints have smaller grains and grain boundaries. Little et
al. (1988) [22] confirmed that porous welds provide more
sites for bacterial colonization than base metal. Medilanski
et al. (2002) [23] demonstrated that smoother and rougher
surfaces enhance the bacterial attachment: they tested four
different bacterial strains on the surface of SS 304 that had
five different surface finishes with roughness values (Ra)
that ranged from 0.03 to 0.89µm. Minimal adhesion was
observed at Ra= 0.16µm while both smoother and rougher
surfaces showed more adhesion.
Surface polarization is another surface characteristic that
affects microorganism adhesion to the surface. Armon et
al. (2001) [24] investigated the polarization affects on the
adhesion of P. fluorescens to stainless steel and carbon steel
surfaces, and the maximum absorption was reported in
a potential range of -0.5-0.5V / SCE (standard calomel
electrode). Deviation outside that range caused a gradual
decrease in bacterial adsorption. De Romero et al. (2006)
[25] evaluated the cathodic protection influence on the
attachment of the SRB, Desulfovibrio desulfuricans, to a pure
carbon steel surface. It was found that an applied cathodic
polarization of -1000mV / SCE was not sufficient to
counteract the bacterial growth and attachment.
Surface coverage such as oxides and corrosion products has
detrimental influence on the microorganism attachment,
and the effect of metal oxides on adhesion is one of the
research interests for bacterial adhesion. Different oxides can
be developed over a surface during the corrosion process.
Examples include iron oxides (i.e. Fe2O3), chromium
oxides (i.e. Cr2O3) and titanium oxides (i.e.TiO2). Most of
Fig.2. Biofilm formed by SRB, Desulfovibrio capillatus, on a
surface of (top) low-alloy carbon steel (API 5L X80) and
stainless steel (SS 316) coupons (bottom).
the research work has focused on iron oxides [26] that are
known to increase bacterial adhesion. Iron hydroxides and
other forms of oxides on the metal surface provide firm
attachment sites to bacteria. The metal oxides provide a
positively-charged surface that can significantly increase the
bacterial deposition to the surface [2, 22, 26]. Baikun Li et
al. (2004) [26] reported that metal oxides can increase the
adhesion of negatively-charged bacteria to surfaces primarily
due to their positive charge and hydrophobicity. They found
significant increase in bacterial adhesion to glass surfaces
covered with different metal-oxide coating compared to
uncoated glass. The attachment increase was attributed to
the increase in surface roughness, surface charge, and surface
hydrophobicity due to the metal oxides. It has also been
shown that unstable or deteriorated corrosion products or
oxides can detach biofilm associated with them [2].
The chemical properties of the surface have been known
to directly influence the microorganism’s adhesion and
distribution in a biofilm [27]. Metals are the most common
and economical material that have been used in oil and
gas pipeline systems. Bacterial attachment and subsequent
biofilm formation can occur on wide variety of metals
including carbon steel, aluminium, stainless steel, and
copper alloys, with different extents. Some metals such as
66
Fig.3. Illustration of the different interfacial energies involved
during bacterial adhesion.
are several studies that concluded no correlation between
bacterial species attachment to hydrophobic surfaces and
changes in electrolyte concentration [34]. Again, this could
be due to the multitude of microbial metabolisms possible,
and what happens to be at one place at one time, or what
kind of microbe is used for the research study. Fletcher et
al. (1988) [36] found that increasing the concentration of
several cations in an electrolyte solution such as sodium,
calcium, and ferric ions affect the attachment of P.
fluorescens to a glass surface by reducing the repulsion
forces between the negatively charged bacterial cells and
a glass surface.
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aluminium or copper are considered toxic to bacteria [28].
On the other hand, copper has been reported to enhance
the growth rate of some bacteria, whilst decrease the growth
in other microbial populations [30, 31]. Microbes have
enormous physiological range of tolerance and use of metals,
and this is an example of that. When compared to low-alloy
carbon steel and stainless steel surfaces, copper displays the
most inhibitory effects on various microorganisms [32].
Gerchakov et al. (1977) [33] reported that a stainless steel
has more initial bacterial attachment compared to 60/40
copper-zinc brass and copper-nickel surfaces. Stainless steel is
generally known for its high corrosion resistance due to the
formation of thin passive chromium-oxide film. However,
it is vulnerable to bacterial attachment especially to the
metal-depositing organisms (MOB) that has been known
for MIC on stainless steel. Low alloy carbon steel is the
most common steel used in pipeline systems and has been
known for its high propensity to MIC. Addition of alloying
elements such as silicon and sulphur has been reported to
increase the low alloy steel susceptibility to MIC, and reports
show sulphide inclusion sites were the most favourable sites
for bacterial colonization [2-4]. Figure 2 shows the biofilm
formed on the surface of low-alloy carbon steel and stainless
steel coupons respectively.
Medium characteristics
Medium concentration, pH, and total organic and inorganic
ionic strength can influence the microbial settlement
potential [1-4]. The change in electrolyte pH influences the
microbial cell surface charge. Commonly, at neutral pH,
bacteria are negatively charged, but a few strains have been
reported that exhibit a net positive charge [34]. Increasing
the cell negative charge will increase the repulsion against
a negatively charged surface, subsequently decreasing the
bacterial attachment. Sheng et al. (2008) [35] examined
the effect of solution pH on the attachment of three
different bacteria, Desulfovibrio desulfuricans, Desulfovibrio
singaporenus, and a Pseudomonas sp., to a stainless steel
surface. They found that for all bacterial strains tested, the
adhesion force reached its highest value when the pH of
the solution was near the isoelectric point of the bacteria
at the zero point charge. The adhesion forces at pH 9 were
higher than at pH 7 due to the increase in the attraction
between iron ions (Fe2+) and negative carboxylate groups
(COO–). The carboxylate groups are highly ionized at pH 9.
These negatively charged COO– groups, in turn, bind with
positive Fe2+ by electrostatic interactions on the stainless
steel surface, and induce the large adhesion force in the
solution with a high pH.
The effect of electrolyte ionic strength (I) has been
investigated extensively inside and outside the laboratory.
Some studies have shown an increase of bacterial adhesion
in electrolyte concentrations that range from 0 to about
0.1–0.2M; above this concentration, an increase in I either
increased or decreased adhesion. Similarly, organic material
adsorption, such as protein, showed an increase with
increased I in an interval from 0-50mM KCl. However there
In general, increasing the total organic carbon (TOC) will
provide more nutrients to the bacteria and hence increase
the bacterial colonization. Cowan et al. evaluated the effect
of nutrients on bacterial colonization on a glass surface,
and related the bacterial colonization of a surface to their
ability to grow toward turbidity in the water column, and
the deposition onto the surface increased with the density of
suspended cells. Moreover, carbon limitations were shown
to influence the adhesive strength of attached bacteria.
Phosphorus and nitrogen are also important nutrients
for microorganisms [8]. Limitation on these elements
adversely impacts the growth of most microorganism. It has
been reported that an electrolyte with a carbon-nitrogen
ratio greater than 7:10 is considered ‘nitrogen-limited’ for
microbial growth. The nitrogen depletion in the medium
results in lower amounts of produced EPS and a thinner
biofilm [2].
Microorganism properties
Microbial cell characteristics have a significant role in the
adhesion process: the cell surface protects the microbe
and provides structural support. A microbial cell can
be classified based on surface charge into two major
groups; Gram-negative and Gram-positive microbes [8].
The difference between them is related to the cell wall
configuration, and the great majority of microbial cells
in the environment tend to be Gram negative. During
the adhesion process, a Gram-negative bacterium will be
more attracted to a positively charged surface, and vice
versa. It has been shown that proteinaceous appendages
including pili and flagella initiate the bacterial adhesion
by establishing bridges between surface and cells [39].
1st Quarter, 2012
67
𝑊𝑊!"! = (− 𝛾𝛾!" + 𝛾𝛾!" + 𝛾𝛾!" )𝑑𝑑𝑑𝑑 (1)
The terms gsm, gml, and gsl are the solid-microorganism, solidliquid, and microorganism-liquid interfacial free energies,
respectively. The free energy of adhesion (∆Gadh) is calculated
by the following:
∆𝐺𝐺!"! = – 𝑊𝑊!"! = 𝛾𝛾!" − 𝛾𝛾!" − 𝛾𝛾!" 𝑑𝑑𝑑𝑑
(2)
The microbial adhesion will be favourable when the ∆Gadh
is negative (< 0) and will not be energetically favourable if
∆Gadh is positive. Different theories are deployed to compute
the interfacial energies and are based on the measurement of
contact angles of a bacterial lawn on a solid surface. In these
theories, the contact angle is related to the interfacial energy
by Young’s equation:
𝛾𝛾!" 𝑐𝑐𝑐𝑐𝑐𝑐 𝜃𝜃 = 𝛾𝛾!" − 𝛾𝛾!" (3)
The subscripts denote the respective surface free energy
between the liquid (l), solid (s), or vapour (v). When contact
angles on microbial lawns are measured, the subscript
(s) should be replaced by (m) for microbial. Different
approaches have been used to calculate the interfacial
energies [40]:
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The interaction between the microbial cells themselves
plays an important role in biofilm formation. Research
has shown that chemical signalling plays an important role
in the formation of microbial biofilm. A class of diffusible
molecules known as N-acylated homoserine lactones (AHLs)
which are released by the bacteria into the local environment
can interact with neighbouring cells in a form of chemical
signalling or communication [39]. Consequently, with this
communication EPS is generally considered to be important
in cementing bacterial cells together in the biofilm structure,
making for a stronger, protected and communicative
community. Sheng et al. (2008) [35] measured the cell–cell
interaction forces of three different bacteria, Desulfovibrio
desulfuricans, Desulfovibrio singaporenus, and Pseudomonas sp. The
reported force curves indicate the long-range of repulsive force
for the cell-cell interactions. They reported that surface charges
for both bacterial cell and substratum greatly influenced the
adhesion force by controlling the electrostatic interactions.
The electrostatic interaction resulted in stronger repulsive
forces in the cell-cell interaction as compared to the cell-metal
surface interaction. The surface energies, charges, interaction
forces, and other properties for bacterial cell, surface, and
environment should be considered to compute the free energy
of the adhesion process.
Thermodynamic and surface
energies approaches of bacterial
adhesion
The bacterial adhesion to the substrate is complex and involves
different factors [2], and three different approaches have been
used to describe the process: thermodynamic, DLVO (Derjaguin,
Landau, Verwey, Overbeekand), and extended DLVO, which
was introduced by Van Oss et al. These approaches are based
on the fundamental interaction forces between the bacteria
and surface, and in order to have an adequate description of
this interaction, both long-range and short-range forces should
be considered [40].
Thermodynamic approach
The thermodynamic approach assumes the system is in
equilibrium and the bacterial attachment is a reversible process.
The interfacial free energies between the interacting surfaces
are compared and calculated, as schematically illustrated in
Fig.3. This comparison is expressed in the so-called free energy
of adhesion. Based on that, the work of adhesion (Wadh) and
free energy of adhesion (∆Gadh) is obtained. The work of
adhesion can be calculated by the Dupré Equation as follows:
!"
∆𝐺𝐺!"!
= −2 !" − 𝛾𝛾 !" 𝛾𝛾!"
!"
!"
∆𝐺𝐺!"!
= −2 !" − 𝛾𝛾 !"
𝛾𝛾!"
!"
!" − 𝛾𝛾 !" 𝑑𝑑𝑑𝑑
𝛾𝛾!"
!"
!" − 𝛾𝛾 !" 𝑑𝑑𝑑𝑑
𝛾𝛾!"
!"
Equation of state [41]: It requires one polar liquid
(i.e. water) for calculation and uses the following
equation:
!
𝛾𝛾!" − 𝛾𝛾!"
𝛾𝛾!" = (4)
1 − 0.015 𝛾𝛾 𝛾𝛾 !" !"
In the second approach, the surface free energies are
separated in a polar or Lifshitz-van der Waals (gLW)
and a polar or acid-base (gAB) component. So one
polar (i.e. water) and non-polar (i.e. Diiodomethane)
liquids will be required for calculation as follows
[42-44] and below (equations 7 and 8):
!
𝛾𝛾𝛾𝛾𝛾𝛾 =
!" − 𝛾𝛾 !" 𝛾𝛾!"
!"
!"
!"
∆𝐺𝐺𝐺𝐺𝐺𝐺ℎ = ∆𝐺𝐺!"!
+ ∆𝐺𝐺!"!
!
(5)
!" − 𝛾𝛾 !" 𝛾𝛾!"
!"
(6)
The third approach separates the acid –based component
to an electron-donating g and an electron-accepting
(7)
(8)
68
DLVO approach
Fig.4. Illustrations of bacterial cell interactions with the
electrical double layers: electrical double layer depicting the
inner Helmhotz plane (IHP) formed by a layer of solvent
and the outer Helmhotz plane (OHP) determined by the
alignment of hydrated cations.
∆𝐺𝐺!"! = ∆𝐺𝐺 !" (𝑑𝑑) + ∆𝐺𝐺 !" (𝑑𝑑) (12)
The attractive Lifshitz-van der Waals ∆GLW is calculated by:
−𝐴𝐴𝐴𝐴
∆𝐺𝐺 !" = 𝐴𝐴 = 24 𝜋𝜋 𝑑𝑑!! 𝛾𝛾!!" (13)
6𝑑𝑑 and
The repulsive or attractive electrostatic forces ∆GEL as shown
in Equation 14 below..
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g+. So two polar and one non-polar component will
be required for the calculation, as shown in equation
9 below [42-44]:
The drawback of the thermodynamics approach is that it
ignores the electrical double-layer interaction with the bacteria,
as illustrated by Fig.4. This assumption is invalid as the bacterial
cells have a surface-negative or -positive charge. In contrast, the
DLVO approach displays a balance between attractive Lifshitzvan der Waals (∆GLW) and repulsive or attractive electrostatic
forces (∆GEL). These two forces are function of the distance
(d) between the bacteria and surface. In order to calculate the
adhesion free energy (∆Gadh), the electrostatic interactions
between surfaces should be included. The inclusion of
electrostatic interactions requires that the zeta potentials of
the interacting surfaces be measured, in addition to measuring
contact angles [41-45, 46]. So the total free energy expression is:
!"
!"
∆𝐺𝐺𝐺𝐺𝐺𝐺ℎ = ∆𝐺𝐺!"!
+ ∆𝐺𝐺!"!
(10)
Equation of state is considered relatively easy method
to compute ∆Gadh (Equn 4). It becomes more
complicated when surface free energy components gLW,
gAB, and parameters g– and g+ are included as shown in
the second and third approaches [40-42].Furthermore,
and based on the thermodynamic model, Power et al.
[45] developed a novel model that calculates Gibbs free
energy (∆Gadh) of adhesion for the initial bacterial
attachment process. The merit of this model is that
it eliminates the need to calculate interfacial free
energies and instead relies on measurable contact
angles. In their work, they were able to calculate
the ∆Gadh of adhesion for a Pseudomonas putida
bacterium interacting with a mercaptoundecanol
and dodecanethiol self-assembled monolayer. They
developed the following Gibbs free energy:
1
∆𝐺𝐺!"# = 𝛾𝛾! 1 − cos 𝜃𝜃!" 1 − cos 𝜃𝜃!" 𝑑𝑑𝑑𝑑 (11)
2
The term gl is free energy of liquid, and qbl and qsl are the
contact angles measured from the bacteria/air-liquid
and substrate-air-liquid interfaces, respectively.
The term A is the Hamakar constant, f1 and f2 are the
zeta potentials of the bacteria and the flat surface, R is the
sphere radius assuming the bacteria is sphere shapes, eo and
er are the electrical permittivity of the vacuum and medium
respectively, k is Debye- Huckel parameter, and d is the
distance in nm [41, 46].
It has been found that the medium ionic strength has no
influence on the Lifshitz-van der Waals attraction, whereas
both the range and the magnitude of the electrostatic
interactions decrease with increasing ionic strength due to
shielding of surface charges. In case of high ionic strengths,
electrostatic interactions have lost their influence [41].
Extended DLVO approach
The extended DLVO theory relates the origin of hydrophobic
interactions in microbial adhesion and includes four
fundamental interaction energies: Lifshitz-van der Waals,
electrostatic, Lewis acid-base, and Brownian motion forces
as shown in Equation 15 below..
The effect of acid-based interaction is higher than those
for the electrical and the Lifshitz- van der Waals energies;
however, it is short range and requires a close distance (<
5nm) between the bacteria and the surface. On the other
!
𝛾𝛾𝛾𝛾𝛾𝛾 =
!" − 𝛾𝛾 !" 𝛾𝛾!"
!"
+2
∆𝐺𝐺 !" 𝑑𝑑 = 𝜋𝜋𝜋𝜋! 𝜀𝜀! 𝜋𝜋𝜋𝜋 2𝛷𝛷! 𝛷𝛷! ln
! 𝛾𝛾 ! + 𝛾𝛾 ! 𝛾𝛾 ! − 𝛾𝛾 ! 𝛾𝛾 ! − 𝛾𝛾 ! 𝛾𝛾 !
𝛾𝛾!"
!"
!" !"
!" !"
!" !"
1 + exp −𝑘𝑘𝑘𝑘
1 − exp −𝑘𝑘𝑘𝑘
𝛷𝛷!! + 𝛷𝛷!! ln[ 1 + exp(−𝜅𝜅𝜅𝜅)] ∆𝐺𝐺!"# = ∆𝐺𝐺 !" 𝑑𝑑 + ∆𝐺𝐺 !" 𝑑𝑑 + ∆𝐺𝐺 !" 𝑑𝑑 + ∆𝐺𝐺 !"
(9)
(14)
(15)
1st Quarter, 2012
69
hand, the Brownian motion comprise (1/2) kT per degree
of freedom and the ∆GBW of adhered bacteria to a surface
equals 1kT = 0.414 x10-20 J [41, 46].
Subsequent physical-chemical
interaction between the biofilm
in the pipeline
The subsequent influence of the biofilm on linepipe steel is
the development of MIC or biofouling. MIC is not new type
of corrosion process, but it incorporates the role of bacteria
and resulted biofilm in the corrosion processes. There are
diverse types of corrosion resulting from MIC. Generally,
MIC produces localized corrosion that exhibits pitting.
Other types of corrosion include crevice corrosion, underdeposit corrosion, cracking, enhanced erosion corrosion,
and dealloying [2-4].
Fe → 4Fe2+ + 8e
anodic reaction
(16)
8H+ + 8e → 8H
cathodic reaction
(17)
SO42– + 8H → S2– + 4H2O
SRB metabolism
(18)
Fe2+ + S2– → FeS
Fe2+ + 6OH– → 3Fe(OH)2
corrosion products
(19)
Miller and King [3] related the corrosion effects of SRB to
both the hydrogenase and iron/iron sulphide galvanic cell. As
proposed, the iron sulphide will act as a cathode and absorb
the molecular hydrogen, and the area beneath will be the anode
sites. In anaerobic conditions, the oxygen-free environment that
is a prerequisite for SRB growth, the concentration of hydrogen
ions will be extremely low and will not be able to form a layer
of atomic hydrogen. For this reason, an additional cathodic
reaction has been considered, such as H2S reduction, as follows:
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Corrosion is classified as an interfacial process, and the
thermodynamics and kinetics of the process are strongly
influenced by the physico-chemical environment at the
interface including the pH, oxygen concentrations, salt,
conductive, developed oxides, and redox potentials. It is well
established that the metabolic activities and the biofilm have
the ability to alter these factors [2-4, 47], and the type and
extent of damage depends on the bacterial type and associated
environment. The main types of bacteria associated with metals
in pipeline systems are sulphate-reducing bacteria (SRB),
iron-reducing bacteria, and iron- and manganese-oxidizing
bacteria [5]. Among them, SRB has been recognized to be
the major MIC causative microorganisms in pipeline systems.
According to Iverson’s estimation, 77% of the corrosion in
the producing oil wells in the United States is introduced by
SRB [47]. Therefore, the following discussion will be limited
to the influence of the physical-chemical interactions between
the SRB, biofilm and linepipe surface.
There are different ways that SRB and the resulting biofilm
produce MIC damage in the pipeline. According to the classical
theory, SRB consume the cathodic hydrogen by an enzyme
known as hydrogenase to obtain the electron required for
metabolic activities. Therefore, the removal of hydrogen from
the metal surface will catalyze the revisable activation of hydrogen
and in turn will force the iron to dissolve at the anode [2-4, 47].
In 1934, Khur and Vlugt [3] proposed that the reactions that
govern the classical theory as follows:
Sulphate-reducing bacteria (SRB) are related to the Bacterial
domain: SRB are anaerobic and do not need oxygen to
survive; rather, they use sulphate ions as a terminal acceptor
and produce hydrogen sulphide (H2S). Furthermore, this
type of bacterium has the ability to reduce nitrate and
thiosulphate. SRB can manage to stay alive in an aerobic
environment until the environment becomes suitably
anaerobic for them to grow. In this case, the aerobic type
(i.e. IRB) of bacteria consumes the oxygen faster than the
oxygen diffusion towards the biofilm, so the environment
deeper in the biofilm will become anaerobic and, in turn, SRB
will thrive. SRB obtain their energy from organic nutrients,
such as lactate, and they can grow in a pH range from 4 to
9.5 and tolerate pressure up to 500 atmospheres. Most SRB
exist in temperature ranges of 25-60ºC. SRB can be found
everywhere in the oil and gas production facilities, both
deep in the well, and extending to the treatment facilities.
The environment inside the pipeline systems has anaerobic
or low oxygen concentration, considering SRB as the main
contributor to bio-corrosion [2-4, 8, 48, 49].
H2S + e → HS– + ½ H2
(20)
Furthermore, the biofilm forms on the metal surface is
heterogeneous in nature and forms community centres of
bacteria. Those sites may be chosen based on chemical and
metallurgical profiles, such as inclusions and roughness that
induce attachment sites for the bacteria. These colonies produce
EPS that attract more bacteria and organic materials to these
sites. Subsequently, the conditions under these colonies – such
as oxygen level, ion concentrations, and pH – will be different
from those in the bulk stream and, in turn, lead to the formation
of concentration cells, pitting, and crevice corrosion. Other
literature proposed that the area beneath the biofilm will act
as anodic sites while the outside region will be cathodic. The
fixing community centre will form fixing anodic sites that are
affected by the immobile bacteria growth, their activities, and
the biofilm developed under these colonies. This behaviour will
initiate pits under those colonies and will become fixed anodic
sites under an immobile community; as a consequence those
pits will grow with time [3, 47, 50].
Some strains of SRB, such as Desulfovibrio, use the organic
carbon source in the nutrition system such as lactate to produce
the hydrogen necessary as electron donor and yield pyruvate
or acetate, which is excreted to the bulk as these bacteria are
nonacetate oxidizers as follows:
4CH3CHOHCOO– + SO42– → 4CH3COO– + 4HCO3– + H2S + HS– + H+
(21)
70
medium properties include pH, ionic strength, and flow
regime of the system. The tendency of a bacterium to adhere
to the surface can be evaluated using different approaches
via interaction energies, and these include thermodynamics,
DLVO, and extended DLVO. These approaches are based
on the fundamentals of interaction forces between the
bacteria and the surface, and in order to have an adequate
description of this interaction, both long-range and shortrange forces should be considered.
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The main types of bacteria associated with MIC in pipeline
systems are sulphate-reducing bacteria (SRB), iron-reducing
bacteria, and iron- and manganese-oxidizing bacteria. Among
them, SRB has been recognized to be the major MIC causative bacteria in oil and gas operations. The biofilm and the
active metabolisms of SRB alter the electrochemical process
and subsequently change the pH level, produce more H2S,
and introduce multiple cathodic side reactions, all of which
enhances the reduction quality of the system and accelerates the anodic dissolution. Moreover, the accumulation
of iron sulphide on the steel surfaces forms a galvanic cell
with iron, resulting in localized galvanic attack of the iron
surface adjacent to deposits of iron sulphide. Mostly, the
nature of SRB damage is localized extensive pitting attacks.
References
Fig.5. Extensive pitting induced by SRB, Desulfovibrio africanus
sp., on API 5L X65 carbon linepipe steel coupons [19].
2CH3CHOHCOO– + SO42– → 2CH3COO– + 2HCO3–+ H2S + HS– + CO2
(22)
Therefore, the deposit of acetic acid as a result of the above
reaction will form an aggressive environment to the linepipe
steel when concentrated under colony or other corrosion
product and leads to localized metal dissolution beneath
it [3, 48]. Figure 5 shows extensive pitting resulting from
MIC caused by SRB on low alloy carbon steel surfaces [19].
Conclusions
The MIC process starts with the attachment of planktonic
bacteria to linepipe surfaces, which leads to the formation of
the biofilm and subsequently results in metal deterioration.
Bacterial, surface, and medium characteristics play significant
roles in the extent of bacterial transfer rate, adhesion, and
resulting biofilm size. The bacteria characteristics include
surface charge, cell size, and hydrophobicity; the surface
properties include chemical compositions, roughness, inclusions, crevices, oxides, and zeta potential; and the aqueous
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conditions. Corrosion Science, 50, 1169-1183.
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42.J.R.Dann, 1970. Forces involved in the adhesive process, I: critical surface tensions of polymeric solids as
determined with polar liquids. J. Colloid Interface Sci.,
32, 302-320.
43.Id.,1970. Forces involved in the adhesive process. II:
Non-dispersion forces at solid-liquid interfaces. Ibid.,
32, 321-331.
44.D.K.Owens and R.C.Wendt1969. Estimation of the
surface free energy of polymers. J. Appl. Polymer Sci.,
13, 1741-1747.
45.L.Power, S.Itier, M.Hawton, and H.Schraft, 2007. Time
lapse confocal microscopy studies of bacterial adhesion
to self-assembled monolayers and confirmation of a novel
approach to the thermodynamic model. Langmuir, 23,
5622-5629.
46.S.Bayoudh, A.Othmane, L.Mora, and H.Ben Ouada,
Are you up to speed?
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Training courses – mid 2012
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May 2012
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Pipeline Integrity Courses, Houston - 2012 (Houston)
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Pipeline Integrity Management (Houston)
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Journal of Pipeline Engineering

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