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

December, 2008
Vol.7, No.4
Journal of
Pipeline Engineering
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incorporating
The Journal of Pipeline Integrity
Scientific
Surveys Ltd, UK
Clarion
Technical Publishers, USA
Journal of Pipeline Engineering
Editorial Board - 2008
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Obiechina Akpachiogu, Cost Engineering Coordinator, Addax Petroleum
Development Nigeria, Lagos, Nigeria
Mohd Nazmi Ali Napiah, Pipeline Engineer, Petronas Gas, Segamat, Malaysia
Dr Michael Beller, NDT Systems & Services AG, Stutensee, Germany
Jorge Bonnetto, Operations Vice President, TGS, Buenos Aires, Argentina
Mauricio Chequer, Tuboscope Pipeline Services, Mexico City, Mexico
Dr Andrew Cosham, Atkins Boreas, Newcastle upon Tyne, UK
Prof. Rudi Denys, Universiteit Gent – Laboratory Soete, Gent, Belgium
Leigh Fletcher, MIAB Technology Pty Ltd, 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, Mannesmann Forschungsinstitut GmbH, Duisburg, Germany
Lino Moreira, General Manager – Development and Technology Innovation,
Petrobras Transporte SA, Rio de Janeiro, Brazil
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, NV Nederlandse Gasunie, 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 Vice President – Integrity & Materials,
CC Technologies, Dublin, OH, 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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4th Quarter, 2008
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The Journal of
Pipeline Engineering
incorporating
The Journal of Pipeline Integrity
Volume 7, No 4 • Fourth Quarter, 2008
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Contents
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Dr Mo Mohitpour, Andy Jenkins, and Gabe Nahas ........................................................................................... 237
A generalized overview of requirements for the design, construction, and operation of new pipelines for CO2 sequestration
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Professor José Luiz de Medeiros, Betina M Versiani, and Ofélia Q F Araújo .................................................... 253
A model for pipeline transportation of supercritical CO2 for geological storage
Dr Andrew Cosham and Robert J Eiber ............................................................................................................... 281
Fracture propagation in CO2 pipelines
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H S Costa-Mattos, J M L Reis, R F Sampaio, and V A Perrut ............................................................................. 295
Rehabilitation of corroded steel pipelines with epoxy repair systems
Sidney Taylor .......................................................................................................................................................... 307
In-service recoating of a 40-in crude oil pipeline in Kazakhstan
Advertisement feature: 2009 Pipeline Pigging and Integrity Management conference and exhibition ............................. 319
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THE COVER PICTURE shows pipe recoating under way on a project to rehabilitate and recoat 60km of the CPC
pipeline in Kazakhstan. The project is discussed in Sidney Taylor’s paper on pages 307-318.
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The Journal of Pipeline Engineering
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HE Journal of Pipeline Engineering (incorporating the Journal of Pipeline Integrity) is an independent, international,
quarterly journal, devoted to the subject of promoting the science of pipeline engineering – and maintaining and
improving pipeline integrity – for oil, gas, and products pipelines. The editorial content is original papers on all aspects
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Instructions for authors are available on request: please contact the Editor at the address given below. All contributions
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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
(and recent issues of the Journal of Pipeline Integrity) are
available for US$87.50 per copy.
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3. Information for subscribers: The Journal of Pipeline
Engineering (incorporating the Journal of Pipeline Integrity)
is published four times each year. The subscription price for
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Subscribers receive free on-line access to all issues of the
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5. Publisher: The Journal of Pipeline Engineering is
published by Scientific Surveys Ltd (UK) and Clarion
Technical Publishers (USA):
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Editorial
Where’s the T in CCGS?
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A further aspect is associated with the fact that the gas to be
transported will not be pure naturally-occurring CO2,
which is currently being transported by pipeline without
problem in a number of places. It will be so-called
‘anthropogenic’ CO2 (i.e. man-made), and it will by no
means be pure if its origins are power-station and industrial
sources. The uninitiated might think: “a gas is a gas, CO2
is all around us, so what’s the problem?”. But CO2 is a
difficult gas to move by pipeline, and even minor impurities
make it far more problematic.
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The Journal is privileged in this issue to have been able to
publish three significant papers on aspects of CO2
transportation by pipeline, written by international experts
who have informed views of the issues involved. Dr Mo
Mohitpour of Tempsys Pipeline Solutions in Canada and
co-authors from TransCanada PipeLines introduce the
subject with their wide-ranging overview of the current
status of CO2 transportation, and some of the design
aspects that it will be necessary to accommodate if largescale CO2 pipelines are to become a reality. Following this,
Professor Jose Luiz de Medeiros of Rio de Janeiro’s Federal
University and colleagues discuss two models that have
been developed to design CO2 pipelines; taking as a
starting point the McCoy model, the authors examine in
detail the advantages and disadvantages of this ‘base-case’,
and go on to introduce their newly-developed approach
which they consider is more attuned to the actual situation
that will be faced by pipeline designers in this context. They
acknowledge that this is only a step towards a fully-flexible
solution, postulating that further work will be required
properly to incorporate all of the varying parameters that
are necessary.
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HE RECENT international seminar in Salvador, Brazil1,
on the subject of carbon dioxide capture and geologic
storage (CCGS) gave rise to a number of interesting
discussions as participants were updated on the latest views
and research in this important area. CCGS -– or, perhaps
more usually, CCS – is a subject of widespread importance
and frequent discussion, although there seem as yet to be
few solutions to either the ‘capture’ or the ‘geologic storage’
problems. Some of the figures for quantities of CO2 that
will need to be both captured and stored are breathtaking
in their size, and thy are followed by unanswered questions
about how long-term storage (is this a hundred years, a
thousand years, an aeon?, and who will have the
responsibility for managing the process?) is to be effected.
Another interesting aspect of the event, which seems to be
echoed at similar discussions around the world, was that of
the 150 or so papers and presentations, only eight referred
to the elephant-in-the-corner issue of transportation of the
CO2 from the capture site to the storage site: hence the title
of this editorial.
Arguably, CCGS – or CCTGS – is not the right route to be
followed to reduce the effects of global warming, and there
are many other fora in which this is being debated. But if
it is accepted that CCTGS plays a part, than the
transportation aspect is huge. The sheer quantities of CO2
that will need to be transported will probably considerably
exceed the amount of natural gas and crude oil that is
currently being transported by pipeline world-wide,
requiring a vast new international pipeline network to be
constructed from scratch. The deadlines being quoted for
carbon emissions’ reduction mean that this network will
need to be implemented in the next ten years or less, and
the pipelines themselves will be long-distance, and through
developed regions where routeing will itself be a major
issue. The long-distance aspect is of particular relevance, as
the regions and strata suitable for geologic storage are all far
from the locations where the carbon dioxide is being
emitted.
*2nd International Seminar on Carbon Capture and Geological Storage,
Salvador, Brazil, 9-12 September, 2008. Organized by Petrobras
University, Rio de Janeiro.
The third paper on the general subject is from Dr Andrew
Cosham of Atkins Boreas in the UK and Robert Eiber of
his eponymously-named consulting firm in Columbus,
USA. This paper delves further into the technicalities of
pipeline design for CO2 transportation, and examines the
issue of fracture propagation. The authors point out that
fracture propagation control will require careful
consideration in the design of a CO2 pipeline, which may
be considerably more susceptible to long-running ductile
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The Journal of Pipeline Engineering
Performance of European
cross-country oil pipelines
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There were 12 spillage incidents reported in 2006,
corresponding to 0.34 spillages per 1000km of line. This is
slightly above the five-year average but well below the longterm running average of 0.56, which has been steadily
decreasing over the years from a peak of 1.2 in the mid
1970s. There were no reported fires or fatalities – but one
injury – connected with these spills. The gross spillage
volume was 726cum, equivalent to 0.9 parts per million
(ppm) of the total volume transported: this corresponds to
21cum per 1000km of pipeline, and compares favourably
with the long-term average of 57. Nearly 99% of the spilled
volume was recovered or disposed of safely.
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Most of the reported pipeline spillages were small, and just
over 5% of the spillages since 1971 have been responsible
for 50% of the gross volume spilled. Pipelines carrying hot
oils (such as fuel oil) have, in the past, suffered very severely
from external corrosion due to design and construction
problems. Many have been shut down or switched to cold
service, and the great majority of the pipelines included in
this review now carry unheated petroleum products or
crude oil.
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The two further papers in this issue relate to pipeline
rehabilitation. Professor Jorge Reis ad colleagues from the
Universidade Federal Fluminense at Niteroi in Brazil, in
association with Petrobras’ research institution CENPES,
describe their work on scientifically analysing epoxy repair
systems for carbon-steel pipelines. They conclude that
while composite repair systems may not be totally effective
for certain circumstances (in particular, through-thickness
corrosion defects), they have identified a simple and
systematic methodology for repairing leaking corrosion
defects in metallic pipelines with epoxy resins. Finally,
Sidney Taylor of Incal Pipeline Rehabilitation (based in
France, Russia, and the USA) discusses in detail a
rehabilitation project on the CPC pipeline in Kazakhstan,
were 60km of the line has been recoated and refurbished
using a somewhat unusual technology.
which, at the end of 2006, had a combined length of
35,390km, slightly more than the 2005 inventory; the
difference is mainly due to corrections in the reported data.
The volume transported in 2006 was 805m cum of crude
oil and refined products, a figure which has been stable in
recent years; total traffic volume in 2006 was estimated at
130 x 109 cum km.
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fractures than natural gas pipelines. The need to prevent
such propagating fractures imposes either a minimum
required toughness or a requirement for mechanical crack
arrestors and in some situations the requirement for fracture
propagation control will dictate the design of a CO2
pipeline. The issues are illustrated in examples involving
the design of an 18-in and a 24-in pipeline, and the authors
conclude that if fracture control is considered early in the
design, any constraints on the design can be identified and,
in principle, resolved without too much difficulty.
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RUSSELS-based CONCAWE – the oil companies’
European association for the environment, health,
and safety in refining and distribution – has for the last 36
years been collecting spillage data on European crosscountry oil pipelines, paying particular attention to spillage
volumes, clean-up and recovery, environmental
consequences, and incident causes. As many readers will be
aware, the results of these surveys have been published in
annual reports since 1971, and form a most important
statistical record. CONCAWE’s latest report, published in
August2, covers the performance of these pipelines in 2006,
and includes a full historical perspective going back to
1971. The performance over the complete 36-year period
is analysed in various ways, including gross and net spillage
volumes and spillage causes, which are grouped into five
main categories: mechanical failure, operational, corrosion,
natural hazard, and third party. The rate of inspections by
intelligent pigs is also reported.
Approximately 70 companies and agencies operating oil
pipelines in Europe currently provide data for this annual
survey. These organizations operate 159 pipeline systems
2 Performance of European cross-country oil pipelines: a statistical
summary of reported spillages in 2006 and since 1971. Published by
CONCAWE, Brussels, www.concawe.org.
Half the 2006 incidents were related to mechanical failures,
four to third-party activities, and two to corrosion. Over the
long term, third-party activities remain the main cause of
spillage incidents, although it has been progressively reduced
over the years. Mechanical failure is the second largest
cause of spillage; after great progress in reducing this during
the first 20 years of the reviews, the frequency of mechanical
failure has been following an upward trend since the mid
1990s. Most of the European pipeline systems involved
were constructed in the 1960s and 1970s. CONCAWE
points out that in 1971, 70% of the inventory was 10 years
old or less; by 2006, only 7% was 10 years old or less, and
37% was over 40 years old. However, this ageing does not
appear to have led to any increase in spillages.
Over the complete survey period (from 1971) the two most
important causes of spillages are third-party incidents and
mechanical failure, with corrosion well back in third place
and operational and natural hazards making minor
contributions. Significantly, third-party incident frequency
has been reduced progressively over the years although,
having made good progress prior to 1991, it appears that
this trend might subsequently be reversing.
In 2006, 78 runs by all types of intelligent pig covered
7020km of pipeline. Most inspection programmes involved
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4th Quarter, 2008
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A generalized overview of
requirements for the design,
construction, and operation of
new pipelines for CO2
sequestration
by Dr Mo Mohitpour*1, Andy Jenkins2, and Gabe Nahas3
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1 Tempsys Pipeline Solutions Inc, White Rock, BC, Canada
2 Vice President, TransCanada PipeLines Ltd, Calgary, AB, Canada
3 Project Manger, TransCanada PipeLines Ltd, Calgary, AB, Canada
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VER RECENT decades, carbon dioxide has been transported through pipelines with no demonstrated
examples of substantial leakage, ruptures, or incidents, and more CO2 pipelines are expected to
be built within the next ten years due to economic and environmental drivers (high oil prices, climatechange-related policies), for carbon capture and geological sequestration (CCS), for re-injection, and to
support enhanced oil recovery (EOR) projects. While there are some differences between CO2
transportation for EOR and CCS (such as impurities and routeing through more populated areas), if industry
experience and best practice are followed, there seems to be little reason to be concerned about the design,
construction, operation, and safety of CO2 pipelines for CCS; an added advantage is that CCS for EOR using
captured CO2 brings two benefits for same cost.
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ARBON DIOXIDE (CO2) is a colourless, odourless,
non-flammable, non-toxic substance that may exist as
a gas, liquid, solid, or in all three phases at its triple point.
The critical pressure and temperature of CO2 is 1070psi
(7377kPa) and 88oF (31oC), respectively. It is present in
earth’s atmosphere at a current concentration level of
approximately 370ppm (0.037%), although somewhat
higher concentrations may occur in occupied buildings.
Air in the lungs contains approximately 5.5% (55,000ppm)
of CO2. Although it is non-toxic, air containing 10-20%
CO2 concentrations by volume are immediately hazardous
to life by causing unconsciousness, failure of respiratory
muscles, and a change in the pH of the bloodstream.
*Author’s contact information:
tel: +1 604 618 6784
email: [email protected]
CO2 may be shipped as either a gas or a liquid. Pipeline
transportation of CO2 is usually at high pressures in liquid
state or as a gas in dense phase.
International concerns over global warming continue to
grow: man-made emissions of carbon dioxide have become
the main focus of government policies, as carbon dioxide
is the largest contributor to anthropogenic greenhouse gas
emissions. With increasing global energy use and
consequential CO2 emissions (see Fig.1 [1]) and expectation
of continuing high oil prices, CO2 capture and storage
(CCS) is becoming a viable option for managing man-made
greenhouse gases.
Figure 2 indicates the percentage breakdown of sources of
CO2 emissions in the USA [1]. The inset in the figure
provides global breakdowns indicating that the level of
CO2 emission that can possibly lead to capture and use is
The Journal of Pipeline Engineering
Fig.1. Trend in global energy use and CO2 emissions [1].
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Carbon dioxide (CO2 ) is a combustion by-product of
fossil fuels (oil, natural gas, coal) that are used for electricity
production, transportation, heating, and industrial
applications. It is also released when solid waste, wood, and
wood particles are burned.
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CO2 and greenhouse
gas emissions
methane (CH4)
nitrous oxide (N2O)
hydrofluorocarbons (HFCs)
perfluorocarbons (PFCs), and
sulphur hexafluoride (SF6)
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largest from electrical power generation and industrial
usage (cement, chemical, and pharmaceutical manufacture,
etc.).
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CO2 is one of six anthropogenic greenhouse gases (GHGs)
that have been targeted by the international community as
causing global warming. The other five man-made GHGs
of concern are:
Fig.2. Breakdown of the causes of CO2 emission.
Carbon dioxide capture and storage is a process for reducing
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Fig.3. CO2 and greenhouse-gas emission chronology.
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4th Quarter, 2008
Table 1. CO2 safety profile [3].
* National Institute for Occupational Safety and Health.
The Journal of Pipeline Engineering
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Fig.4. Phase diagram for pure CO2 (after refs 4 and 5).
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GHG emissions into the atmosphere by first extracting
CO2 from the gas streams typically emitted during electricity
production, fuel processing, and other industrial processes.
The CCS process involves three stages: gathering of the
CO2 from emitting sources or CO2-rich reservoirs,
transmission of the CO2 to the storage site, usually by
pipeline, and injection of the CO2 into the geological
reservoir.
Awareness of greenhouse-gas emission goes as far back as
1896 when Svante Arrhenius (1859–1927), a Swedish
scientist, postulated that fossil fuel combustion may
eventually result in enhanced global warming [2]. He
proposed a relation between atmospheric carbon dioxide
concentrations and temperature that is the forefather of
present-day CO2 emission calculations. The chronology of
CO2 and GHGs is indicated in Fig.3.
At low concentrations (1% by volume), CO2 causes no ill
effects on humans, fauna, or flora. At concentrations of
about 6% by volume, CO2 can cause nausea, vomiting,
diarrhoea, and irritation to mucous membranes, skin
lesions, and sweating. At about 10% by volume, it cause
asphyxiation, Table 1 [3].
CO2 is a fluid with unusual properties. Its phase diagram
is illustrated in Fig.4 [6]; CO2’s triple point and critical
points respectively exist at 0.52MPa (5.2bar), -56.6oC, and
7.38MPa (73.8bar), +31oC. The line connecting the two
points is the vapour-liquid line separating the gaseous and
liquid phases. The triple-point CO2 exists as one of the
three phases: solid, liquid, or gas.
Safety data and
phase characteristics
The properties of CO2 are unusual compared to other
fluids transported through pipelines. For example pipeline
temperatures for methane are generally above the critical
point of methane, and therefore no phase change would be
expected to occur during the transportation. Oil pipelines
also operate at pressures lower than the critical point, and
therefore produce no phase change.
CO2 is essential for life, being a critical component in
photosynthesis. As an example of this, greenhouses
purposely elevate CO2 levels in order to “fertilize” the
plants they contain.
It is important to avoid phase changes during pipeline
operation. However, as the critical point for CO2 is closer
to the pressures/temperatures that may be encountered
during pipeline operation, the design and operation of
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• 1972:
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CO2 pipelines are more complicated than that for other
fluid-transportation pipelines. To avoid phase changes,
therefore, CO2 is generally transported in the temperature
range 4-24oC [7].
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Fig.5. Typical thermodynamic path for
compression, cooling, and pipeline
operation for CO2.
• 1972:
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CO2 pipeline
milestones and experience
World experience of CO2 pipelines is about 7500km, of
which 6000km (3700miles) are mostly large-diameter and
operational in the USA. The oil industry uses CO2
(currently, mostly in pure form) for enhancing oil
production. CO2-enhanced oil recovery (CO2-EOR) is
currently employed in the USA and Canada, Turkey, and
Trinidad and Tobago as well as Brazil. Of the 74 globallyactive facilities, 70 are in the USA (administered by 27
operators).
The following highlight achievments in EOR and CCS, as
well in the use of pipelines as a mode of transportation:
• early 1960s: injection of CO2 (by the oil industry)
for secondary and tertiary EOR
• 1970s:
low-volume geologic storage of CO2
(onshore) for EOR
• 1970s:
removal of CO2 from flue gas from
power plants
construction of the first onshore CO2
transmission pipeline (Canyon Reef
Carriers)
first major CO2 flood (in Scurry
County, Texas)
• 1979-1989: major naturally-occurring CO2
discovered (N-CO2)
• 1989:
acid gas injection
• 1996:
first offshore saline aquifer injection
(Statoil)
• 2008:
highest-ever oil prices ($145/brl)
Long-distance CO2 pipelines serve these CO2-EOR projects
and, as indicated, many of these pipelines have been
operating since the early 1970s.
From the offshore perspective, Snohvit (in the Norwegian
sector of the North Sea) is the field with the (first) offshore
CO2 transmission pipeline. Since 1996, Statoil (Norway’s
state-owned oil company) has been injecting carbon dioxide
from a by-product of natural gas recovery into a 32,000sqkm aquifer 800m below the floor of the North Sea in this
field (also known as the Sleipner field [5]). This innovative
approach to greenhouse gas reduction was spurred in 1991
by a government-imposed carbon tax on all carbon emissions
from extraction activities on Norway’s continental shelf. In
The Journal of Pipeline Engineering
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standards, and no specialty fluid-transmission code is
applicable or available. CO2 pipelines were unregulated
until 1986; however, ASME/ANSI B31.4 and B31.8 are
generally applicable, as appropriate.
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order to avoid a NOK 1-million/day penalty, Statoil
developed a carbon capture, transportation, and injection
scheme that stores the carbon dioxide in the underground
aquifer once it has been removed from the natural gas.
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Table 2. Major North American CO2 pipelines.
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From an onshore perspective, transportation, injection,
and storage of CO2 in the last 36 years has mostly been
from underground natural deposits/reservoirs such as
those located in Colorado, USA. A typical system includes
CO2 gathering, CO2 dome fields, and processing (water
removal/dehydration, compression, as CO2 from natural
sources is water saturated). Therefore CO2, after being
gathered from wells, is conditioned (through three-phase
separators) and then compressed. A considerable amount
of water is condensed during the first and second
compression cycles, followed by removal of water by amine
absorbers and subsequently further compressions to assure
water-free and dry CO2 prior to pipeline transportation in
liquid form, Fig.5 [8].
Table 2 and Figs 6 and 7 summarize the major CO2
pipelines operating in North America, many of which have
been operating since the early 1980s, with the CO2 being
transported at over 2500psi as a supercritical or densephase fluid in the economically-preferable state [8].
North American
regulatory oversight
Existing CO2 pipeline facilities have been designed to
meet current gas and/or oil pipeline system codes and
In the US, CO2 pipelines are regulated by the US
Department of Transportation’s (DOT) Code of Federal
Regulation (CFR ) Section 195 Liquids Pipelines (for the
transportation of CO2 in Liquid Form). Under US DOT CFR
195, CO2 is regulated as a “hazardous material and carbon
dioxide”.
In Canada, the Natural Resources Code, Chapter 117,
Hazardous liquids or carbon dioxide pipeline transportation
industry, 2005, as well CSA Z662, 2007, apply.
CO2 pipelines are considered ‘high volatile/low hazard
and low risk’ facilities. However, the US DOT consistently
has adopted the language of “hazardous materials and
carbon dioxide.” This means that a higher level of inspection
is required for CO2 pipelines than for crude oil pipelines.
Regulations specifically call for 26 inspections (generally
monitoring of pipeline rights of way) per year. CO2 is
classified as a Class L material, in other words highly
volatile, non-flammable, and non-toxic. No judgment is
made on CO2 as a safety risk.
There is a specific call to mitigate fracture propagation with
a fracture arrestor. Generally, fracture arrestors are specified
where materials do not have sufficient toughness to arrest
running fracture. Valve material compatibility in CO2
service is also a requirement.
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4th Quarter, 2008
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• All CO2 pipeline applications are subject to a
mandatory review by regulatory bodies to ensure
technical completeness and operational safety.
• Since CO2 is non-toxic, no specific requirements
for setbacks, emergency response planning (ERP),
or leak detection are required.
• Because CO2 is heavier than air and tends to
accumulate in low areas (ventilation is poor), pipeline
Fig.7. US pipeline laterals, and the
Canadian distribution system [9].
operators are required to be trained in safe working
procedures in oxygen-deficient atmospheres as well
in the handing of fluids that undergo phase changes
under pressure (asphyxiation occurs at
concentrations greater than 5%).
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Because CO2 is being treated as hazardous, but not declared
hazardous, all the review requirements for high-risk
hazardous pipelines apply in the US if the pipeline is
greater than 457mm (NPS18), or passes through a populated
area; the term “populated area” means a population density
greater than 1,000/square mile (400/sqkm). However from
a Canadian regulatory perspective, the following are
applicable:
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Fig.6. Major CO2 sources and pipeline locations in North America.
• Inspection requirements (every five years) include
smart pigging (which is difficult in CO2 pipelines)
and direct assessment.
From a governmental policy point of view, specific legislative
proposals are being reviewed that reflect the current
perception that CO2 capture probably represents the largest
technological hurdle to implementing widespread CCS,
and that CO2 transportation by pipeline does not present
as significant a barrier. While these perceptions may be
accurate, industry and regulatory bodies are identifying
important policy issues related specifically to CO2 pipelines
which may require government attention [10].
244
The Journal of Pipeline Engineering
Overall design and
installation considerations
SA
M
From a hydraulics point of view, CO2 composition/purity
and characteristics (see Fig.4) impact system design and
hence pipeline operation. These components affect the
following, which in turn affect pipeline capacity and
operational requirements:
• density/specific volume
• viscosity
• specific heat (at constant pressure and constant
volume)
• compressibility
• enthalpy/entropy
• conductivity
O
leak tests
pigging
‘slinky’ and water-hammer effects
safety considerations
C
CO2 composition drives pipeline design, and the following
compositions are typical of the CO2 that is generally
transported through pipelines from CO2-rich fields:
PL
E
The pipeline industry requires that CO2 transmission
systems be designed and constructed at optimal cost, bearing
in mind that they must be safe, reliable, and have minimal
impact on the environment and the general public. This is
achieved by consideration of a number of factors, including
those of design and installation as indicated in Fig.8.
•
•
•
•
PY
Fig.8. Overall design and installation
considerations for CO2 pipelines.
•
•
•
•
CO2:
N2:
CH4:
H2S:
98.372% – 98.350%
1.521% – 0.136%
0.107% – 1.514%
0.000 (approx.)
A typical CO2 pipeline quality specification for enhanced
oil recovery (EOR) is indicated in Table 3.
Excessive water content in CO2 can cause formation of
highly-corrosive carbonic acid, levels of between 18 and
30lb/MMscf (288–480 mg/m3) of which are accepted by
industry for CO2 transmission in carbon steel pipelines.
Effect of impurities
Impact on pipeline capacity
An example of variation of density with temperature for
pure CO2 is given in Fig.9; it is significant to note the nonlinearity of these properties at normal pipeline operating
temperatures and pressures [8].
Other factors affecting the design or operation of CO2
pipelines are:
•
•
•
•
•
impurities/sensitive properties
water content
CO2 concentration
thermodynamic characteristics
dense-phase handling
CO2 impurities significantly affect pipeline design, and in
particular the system capacity. Impurities influence the
vapour pressure of CO2, and thus affect the pipeline’s
capacity and its facilities’ capabilities and design. The affect
of composition of CO2 on the phase diagram is shown in
Fig.10, and the influence on a typical pipeline capacity is
shown in Fig.11. Impurities generally open-up the CO2
gas/liquid bubble (i.e. increase the area of two-phase region,
Fig.10), and move the critical point, thus affecting the
vapour pressure and temperature. Generally, the critical
pressure increases, but the critical temperature decreases as
the level of impurities is increased or changed. This, in
245
PY
4th Quarter, 2008
C
the minimum pump suction pressure must be set higher
than the fluid vapour pressure. A high pump suction
pressure requires a correspondingly-higher maximum
operating pressure so that optimum station spacing and
flow rate can be attained. Alternatively, pump stations have
to be spaced closer than required to meet the required net
positive suction head (NPSH).
PL
E
turn, affects the operating range of a pipeline and the way
CO2 is transported (in liquid rather than supercritical
dense phase, for instance).
O
Fig.9. Density variation of CO2 with temperature (a property significant in pipeline flow computations).
M
For a given pressure drop, the presence of impurities
markedly reduces the pipeline capacity (Fig.11) as they
affect the operating region; it has been shown that the
reduction in capacity is more significant at larger diameters
[7].
SA
Centrifugal pumps are used to transport CO2 at liquid
dense-phase or supercritical conditions. The advantages of
such pumps are their lower cost, better efficiency, higher
reliability, and good operating flexibility. CO2 impurities
affect pump design, however. In order to prevent cavitation,
A propagating ductile fracture is driven by fluid pressure
which acts on the unrestrained walls of a fractured pipe. A
ductile fracture will not propagate if there is insufficient
energy in the system to overcome resistance to the
propagation of the fracture. Decompression characteristics
% P re se n t
Level
R e a so n f o r le v e l
c o n c e rn
95
M in
M in im um m iscibility
pr e ssur e (M M P)*
N itr o g e n
4
M ax
M in im um m iscibility
pr e ssur e (M M P)*
Hydr ocar bon
5
M ax
M in im um m iscibility
pr e ssur e (M M P)*
480 m g / m 3(30 lb/ M M SCF)
M ax
Cor r osion
0.001 (10 ppm )
M ax
Cor r osion
0.01-0.02 (10-200 ppm )
M ax
S a f e ty
0.04 m l/ m 3 (0.3 US g al/ M M SCF)
M ax
O p e r a tio n s
6 5 oC
M ax
M ate r ial ( in cludin g
coatin g )
C o m p o n e n ts
CO 2
Wate r
O xyg e n
H2S
Table 3. Pipeline quality CO2 (*due
to minimum miscibility pressure)
requirement for EOR use only.
Impact on fracture control properties
Glycol
Te m pe r atur e
The Journal of Pipeline Engineering
PY
246
C
t
σd
σf
σy
= pipe wall thickness (m)
= decompressed pipe hoop stress (Pa)
= pipe steel flow stress
= yield stress (MPa)
PL
E
of liquid or dense-phase CO2 lead to a high vapour
pressure during decompression, and this results in a high
driving force at the crack tip concentrating large stresses in
the hoop direction at the fracture tip, similar to natural gas
pipelines (Fig.12).
O
Fig.10. Phase diagram showing the influence of impurities on CO2.
SA
M
CO2 pipelines, as natural gas pipelines, are susceptible to
running ductile fractures [11]. The pipeline has to fail first
for fracture propagation to be an issue: when a CO2
pipeline is burst (mostly due to external forces or corrosion),
high vapour pressure can prevent rapid depressurization
which, in turn, can cause a propagating ductile fracture.
The arrest of propagating ductile fractures is an important
criterion that needs to be considered when designing CO2
pipelines. The fracture-arrest criterion stipulated by Battelle
states that ductile fractures will not propagate if the pipeline
is designed such that:
σd 2
⎛ −π EN ⎞
> cos −1 exp ⎜
⎟
σf π
⎝ 24 ⎠
3.33
where:
σd =
and
EN =
A
Cv
D
E
EN
Pd
Pd D
2t
EC v
1
⎛ Dt ⎞ 2
Aσ f2 ⎜ ⎟
⎝ 2 ⎠
= area beneath Charpy notch (m2)
= material Charpy notch toughness (J)
= pipe outside diameter (m)
= Young’s modulus of elasticity (Pa)
= normalized toughness parameter
= decompressed pressure (Pa)
Examination of the fracture-control equation indicates
that the pipe flow stress σf has to be equal to or greater than
the decompressed hoop stress σd by a factor of 3.33 to
ensure avoidance of ductile fracture propagation in CO2
pipelines [11]. Alternatively, the pipe toughness, strength,
or wall thickness has to be increased to satisfy the condition
for no ductile fracture.
As indicated above, impurities drag the phase envelope to
the left, Fig.10, and impurities cause a lowering of the
critical pressure and, generally, temperature. The phase
boundary determines the vapour pressure; this sets the
decompression pressure at a pipeline break or rupture
which, in turn, decides if a ductile fracture will occur or
not. Cosham and Eiber [12] indicate that the increase in
impurities in CO2 will require pipes having a higher wall
thickness or toughness to arrest a ductile fracture.
Salient design and
operational considerations
Some of the special features of CO2 that need to be taken
into account in any pipeline design include [8, 13]:
• The need to dehydrate the CO2 stream to reduce
corrosion.
• Some petroleum-based and synthetic lubricants can
4th Quarter, 2008
247
Fig.11. The effect of impurities on
pipeline capacity (based on 82.7kPa/
km pressure drop at 10341kPa in an
NPS 16 pipeline at 16oC).
potential for flow transients, known as “water
hammer” by including some surge capacity.
O
Other factors include:
C
• a provision to reduce the possibility of brittle fracture
and ductile fracture propagation. Lower-grade steel,
higher wall thickness and/or toughness;
alternatively, installation of fracture arrestors can
be implemented.
• assessments of high-consequence areas under
pipeline-integrity management programmes.
PL
E
• Supercritical CO2 can damage some elastomer
sealing materials. Elastomers are permeable to CO2,
and a pressure release may cause explosive
decompression and blistering. The solution is
generally to control the rate of decompression, or at
least the number of decompression cycles, and to
choose a high Durometer elastomer (> 90) elastomer
that has a solubility rating farthest from CO2.
PY
harden and become ineffective in the presence of
CO2.
• Viton valve seats and Flexitallic gaskets are typically
specified in the USA for CO2 pipelines.
SA
M
• CO2 cools dramatically during decompression, so
pressure and temperature must be controlled for
routine maintenance.
• Dry CO2 has poor lubricating properties which
require special design features for compressors,
pumps, and traps, etc.
• The pipeline needs to be designed to minimize the
Fig.12. Ductile and brittle
fracture outcomes.
The thermodynamic characteristics of CO2 make pressure
and temperature ranges critical in pipeline operation.
Blow-downs (Fig.13 [14]) and pipeline loading must be
controlled over significantly-longer times than in normal
natural gas pipeline procedures, to prevent excessively-low
temperature gradients.
CO2 has significant mass, and therefore its release at high
pressures is noisy, cold, and powerful. Depressuring CO2
from pipeline-injection pressures to atmospheric pressure
can result in auto-refrigeration temperatures of -90°C, and
The Journal of Pipeline Engineering
CO2 pipelines are equipped with scraper traps, Fig.14.
However, the industry has significant problems with pigging
CO2 pipelines when using rubberized material for the pig’s
components. Pipeline pigging in CO2 service is also difficult
SA
M
PL
E
this will require the use of flare pre-heaters as well as lowtemperature materials. Blow-downs are sized for blowing
down a 32-km section of pipeline in 6-8 hours to avoid dry
ice formation.
C
Fig.13. Blow-down of a pure CO2 pipeline [14].
O
PY
248
Fig.14. Scraper traps in a typical CO2 pipeline application.
4th Quarter, 2008
249
Fig.15. Typical CO2 orifice meter run (for custody transfer).
PY
PL
E
• Meter runs require insulation as a 1ºF (0.5ºC)
temperature differential can swing pressures by up
to 20psi.
Incidents related to CO2 pipe operation are rare. The US
DOT’s Office of Pipeline Safety’s statistics for the period
1994 to 2000 on pipeline incidents in the USA show no
significant statistics on CO2 pipeline incidents. Considering
the number of CO2 pipelines, it can be concluded that the
number of incidents is lower than for hazardous liquid
pipelines in general. There were no injuries or fatalities
associated with incidents on CO2 pipelines that have been
reported, and the cost of the resultant property damage was
significantly less than for hazardous liquid pipelines.
O
Piping design, Figs 15 and 16, for CO2 operation generally
considers the following:
CO2 pipeline operational
safety considerations
C
without the aid of a precursor lubricant such as diesel,
because dry CO2 has very poor lubricating characteristics.
Industry experience indicates that, after pipeline
commissioning, the use of scrapers is redundant as very
little moisture drops out.
• Orifice plates (with a 0.400-in pressure transmitter
connected to a flow computer) are used for CO2
flow measurement.
SA
M
• Meter runs are typically equipped with differential
pressure and temperature recorders as well as a
densitometer. A pressure-relief system is also added.
The only incident of significant importance relates to CO2
release from a non-pipeline source. In August, 1986, at
Lake Nyos in Cameroon, West Africa, a volcanic crater lake
released a large volume of CO2 (Fig.17 [15]). This was not
a volcanic eruption, but a gas burst. A natural release of
Fig.16. Typical station block-valve arrangement.
250
The Journal of Pipeline Engineering
ventilation to prevent accumulation. An additional measure
to reduce risk could include adding chemical odorants, like
those added to natural gas, which help in detecting leaks
especially around more populous areas. This technique has
had a positive impact on leak detection at the Weyburn
facility and its supplying pipeline [17].
Fig.17. CO2 release from volcanic eruption, Lake Nyos,
Cameroon [15].
Public safety is the top priority in any pipeline emergencies.
“Emergency “ is defined as any unforeseen combination of
circumstances or disruption of normal operating conditions
that poses a potential threat to human life, health,
environment, or property if not contained, controlled, or
eliminated. The two primary operational safety
considerations for CO2 facilities are therefore:
• to avoid suffocation in areas where CO2 may be
blowing-down, leaking, and displacing oxygen
(especially in enclosed or low-lying areas); and
• to exercise extreme caution when operating or
maintaining high-pressure CO2 facilities due to the
compressibility and potentially-violent expansion
(150 to 1) of CO2 as it changes phase.
C
O
A typical dispersion of a CO2 vapour cloud after release
from a pipeline is shown in Fig.18 [3]. With reference to
Table 1, staging areas for responding to emergencies during
a rupture can be identified. This allows for an organized
response to the release, including proper siting of emergencyresponse personnel and equipment, and safe and effective
performance of necessary work. Typical modelling for CO2
source characterization and dispersion can be made using
commercially-available software such as BP’s CIRRUS.
PL
E
In comparison 10km of NPS 12 pipeline contains about
380 million cum of CO2 (at standard pressure and
temperature, operating at 15.3MPa and 20oC) which is
about 210 – 2600 times less than the Lake Nyos incident
[16]. For a 32-km section of NPS 36 pipeline, this is equal
to about 9 million cum. The best practice for CO2 pipeline
design thus includes, but is not limited to, selecting sites
and methods that reduce the probability of accumulation
resulting from leakage or injection well failure.
PY
between 80 million and 1 billion cum of CO2 was recorded.
Being denser than air, the CO2 failed to disperse, and
flowed down into nearby populated valleys, resulting in the
deaths of about 1700 people.
SA
M
Best site selection practices would involve selecting a site
away from populated areas and, if indoors, having sufficient
Fig.18. A typical CO2 cloud after release from a pipeline (after Ref. 3).
4th Quarter, 2008
251
• There is a significant knowledge base, developed
from the experience gained from 36 years of
operation and regulation of the existing CO2
pipelines by operators and regulatory bodies. This
knowledge and expertise is available when
considering the development of new CO2 pipelines
and networks.
• Over this 36-year period, CO2 has been transported
through pipelines with no demonstrated examples
of substantial leakage, rupture, or incident.
• More CO2 pipelines are expected to be built within
the next decade due to the economic and
environmental drivers (high oil prices, climatechange-related policies) for carbon capture/
geological sequestration, for re-injection, and to
support enhanced oil recovery projects.
M
PL
E
• While there are some differences between CO2
transportation for EOR and CCS (such as impurities
and routeing through more-populated areas), if
industry experience and best practice are followed,
there would seem to be little reason to be concerned
about the design, construction, operation, or safety
of CO2 pipelines for CCS.
PY
• Most existing pipelines are mainly sited in areas of
low to medium population densities.
O
• There are already in existence long-distance CO2
pipelines and also networks of CO2-distribution
pipelines.
2. H.A.M.Sneiders, 1970. Arrhenius, savante august. Dictionary
of Scientific Biography.
3. A.Turner, J.Hardy, and B.Hooper, 2006. Risks associated
with a CO2 pipeline: methodology and case study. GHGT
8,Trondheim, 19 -22 June, https://extra.co2crc.com.au/
modules/pts2/download.php?file_id=951&rec_id=369.
4. S.T.McCoy, 2008. The economics of CO2 transport by
pipeline and storage in saline aquifers and oil reservoirs. PhD
Thesis, Carnegie Mellon University Pittsburgh, PA.
5. O.Kaarstad, 2005. Carbon capture and storage: the visions.
New and innovative approaches for CO2 capture and storage.
International Seminars on Planetary Emergencies 34th
Session, Erice, Sicily, August 24.
6. O.Kaarstad, 2004. Creating a North Sea CO2 value chain.
Statoil ASA, http://ec.europa.eu/research/energy/pdf/
14_1610_kaarstad_en.pdf.
7. P.N.Seevam, J.M.Race, J.M.Downie, and P.Hopkins, 2008.
Transporting the next generation of CO2 for carbon capture
and storage: the impact of impurities on supercritical CO2
pipelines. Proc..ASME 7th International Pipeline Conference,
Calgary Alberta, Canada, Sept 29-Oct 3, IPC2008-64063.
8. M.Mohitpour, H.Golshan, and A.Murray, 2007. Pipeline
design and construction – a practical approach. 3rd edn,
ASME Press, New York.
9. K.Havens, 2008. CO2 transportation. Indiana Center for
Coal Technology Research, June 5, http://www.purdue.edu/
dp/energy/pdfs/CCTR/presentations/Havens-CCTRJune08.pdf.
10. P.W.Parfomak and P.Foldger, 2007. Carbon dioxide (CO2)
pipelines for carbon sequestration: emerging policy issues.
CRS Report for the US Congress, RL33971http://
www.iepa.com/ETAAC/ETAAC%20Handouts%208-8-07/
CRS%20-%20Report%20CO2%20Pipelines%20for
%20CCS%20k%20davis.pdf.
11. G.G.King, 1981. Design of carbon dioxide pipelines.
Presented at ASME Energy-Sources Technology Conference
and Exhibition ( ETCE), Houston, Texas, Jan 18-22.
12. A.Cosham and R.J.Eiber, 2008. Fracture control in carbon
dioxide pipelines – the effect of impurities. Proc..ASME 7th
International Pipeline Conference, Calgary, Alberta, Canada,
Sept 29-Oct 3, IPC 2008-64346.
13. A.Jenkins and M.Mohitpour, 2008. Design, construction
and operation of new pipelines for CO2 sequestration: an
overview of technical requirements. 2nd Petrobras
International Seminar on CO2 Capture and Geological
Storage, 9-12 Sept, Salvador, Brazil.
14. Kinder Morgan, 2006. CO2 transportation. Presented at
World Resources Institute, February 28.
15. K.Krajick, 2003. Defusing Africa’s killer lakes. Smithsonian,
34, 6. 46-55.
16. J.Dillon, 2008. Status of CO2 capture and sequestration in
Canada. Hatch Energy Presentation, May 19.
17. J.Gale and J.Davison, 2002. Transmission of CO2 – safety
and economic considerations. IEA Greenhouse Gas R&D
Programme, presented at the GHGT-6 Conference, Kyoto,
Japan, October. http://www.usea.org/CFFS/CFFSErice/
Presentations-Remarks/Kaarstad%201430.pdf.
C
Conclusions
SA
• CCS for EOR using captured CO2 brings two
benefits for the same cost.
• Incentives should be designed to be revenue-positive
to government.
Acknowledgments
This paper is based on a continuing programme by
TransCanada Ventures for the transmission of CO2 by
pipeline.
Thanks are due to TransCanada PipeLines Ltd’s
management for permission to publish this paper. Reviews
conducted by Dr H.Golshan (TransCanada) and Dr
A.Cosham (Atkins Boreas) are gratefully acknowledged.
References
1. M.Mohitpour, 2008. Energy supply and pipeline
transportation – challenges and ppportunities. ASME Press.
252
The Journal of Pipeline Engineering
Rio
Pipeline
2009
Call for Papers
September 22-24
Presentation of Papers
Instructions for sending Abstracts/Final Papers
The Rio Pipeline Conference will take place from September
nd
th
22 to September 24 , 2009, in SulAmerica Conventions
Center, in Rio de Janeiro. This main forum for the pipeline
industry is organized every odd year and bring together
professionals and executives of the sector in search for
knowledge of the state-of-art technologies and management
practices in the area. The Conference program includes
panels, talks, technical sessions (oral/posters) and minicourses on relevant topics.
The proposals forwarded must be brand-new, without
intention to publish prior to the Conference and must not
contain any commercial material and/or publicity.
Abstracts forwarded by any other means will not be accepted.
Those who are interested in submitting technical papers
should follow the schedule, the proposed subjects and the
instructions available at the event site. Access:
www.riopipeline.com.br
Official language of the event:
English
PY
Format of the abstracts/final papers:
• Abstracts written in English (100 - 500 words)
• Final paper written in English (maximum - 8 pages)
• Oral Session: Powerpoint Presentation written in English
Schedule to Submit Papers
SA
M
• Automation, Supervisory Systems and Measurement
• Distribution Bases, Terminals, Compression and Pumping
Stations
• Corrosion
• Subsea Pipelines
• GIS and Mapping
• Structural Integrity, Reliability and Risk Analysis
• Logistics and Operation
• Maintenance and Rehabilitation
• Environment and Operational Safety
• Slurry Pipelines
• Design, Construction, Assembly and Materials
• Social Responsibility
• Inspection Techniques
Technical Sessions (Oral)
15/02/2009
Notification of abstracts assessment
15/04/2009
Deadline to receive final papers
(maximum - 8 pages)
28/05/2009
Notification of acceptance/review of
final papers
15/06/2009
Deadline to receive reviewed papers
15/07/2009
Notification of date, time and form of
paper presentation (oral/poster)
O
Deadline to receive abstracts
(100 - 500 words)
C
PL
E
Themes
20/01/2009
(new date)
Further information:
Lídia Bairros
Phone.: (55 21) 2112-9077
E-mail: [email protected]
The abstracts must be submitted until
January 20th, 2009 (new date), according
to instructions available at Rio Pipeline
2009 website.
www.riopipeline.com.br
Formal presentation of technical or economic nature of general
interest to a great audience.
Technical Sessions (Poster)
These sessions will provide an informal forum for direct contact
between authors and delegates on technical topics of specific
focus. They can be scientific topics or cutting-edge topics of
great interest, but aimed at a distinct public.
Participation
Organization
4th Quarter, 2008
253
A model for pipeline
transportation of supercritical
CO2 for geological storage
by Professor José Luiz de Medeiros*, Betina M Versiani,
and Ofélia Q F Araújo
Escola de Química, Federal University of Rio de Janeiro, Ilha do Fundão,
Rio de Janeiro, RJ, Brazil
I
PL
E
C
O
PY
T IS recognized in many broad circles – as well as in restricted ones – that cumulative emissions of
greenhouse gases (basically CO2) are gradually and dangerously contributing to a measurable and
concrete anthropogenic interference of the global climate system. From the viewpoint of the current
century, CCGS – carbon capture and geological storage – is being considered as the most serious response
by industry for mitigating the effects of emissions of fossil carbon into the atmosphere. CCGS demands the
co-operative intervention of three technologies: (a) capture and compression of CO2 from large industrial
sources; (b) transportation of CO2 from sources to feasible geological sinks; and (c) geological injection,
storage, and retention of CO2. It is currently recognized, both technically and economically, that only the
second of these three ‘legs’ – transport of CO2 via high-pressure and high-capacity pipelines – is proven
to be a reliable and feasible technology in the CCGS ‘tripod’.
SA
M
On the other hand, the thermodynamic characteristics of CO2 transportation by pipeline are very specific,
and the supercriticality, high density, and high compressibility of the fluid play important roles. In this area,
the literature seems not to be particularly forthcoming in terms of decisive studies. The work of McCoy
[1] is a recent exception due to its analytical nature, full engagement in searching for valid economic
estimates, and ample scope of the investigation. Nevertheless, the pipeline model proposed in this study
has made certain simplifications which may compromise some of its results in view of the characteristics
of the flow.
In this context, the present work addresses a modelling and simulating resource capable of generating
quantitative responses concerning CO2 transportation issues in the CCGS scenario. The authors present
here a rigorous pipeline model for transportation of CO2 in the supercritical state, and demonstrate its use
for simulating CO2 transportation to an appropriate geological formation for storage. This model takes into
account the physical parameters of supercritical CO2 within a rigorous stationary high-density compressible
flow framework. The features of this model include: (a) high-density supercritical thermodynamic and
transport properties; (b) correct topographic effects (i.e. gravitational compression and expansion of the
fluid and respective thermal consequences); (c) heat transfer effects according to temperature distributions
in the soil and in the injection column; and (d) the ability to incorporate multiple machine stations such as
booster compressors, exchangers, and recovery turbines. The model was designed for engineering
applications involving pipelines which transport dense supercritical CO2 either in its pure form, or in
mixtures with other gases and fluids.
E
NVIRONMENTAL CONCERNS NOWADAYS focus
on atmospheric CO2 levels which have steadily
increased from a pre-industrial level of 278ppm to the
current 379ppm. It is estimated [1] that the current level of
*Author’s contact information:
tel: +55 21 2562 7535
e-mail: [email protected]
global greenhouse gas emissions has reached 50 Gt/yr (50
x 109 metric tons per year), of which 60% corresponds to
CO2 from fossil fuel combustion by industry. For instance,
it has been postulated that the thermoelectric power sector,
with its 10 Gt/yr of CO2 around the world (2.4 Gt/yr of
which is generated in the USA), is the main contributor to
industrial fossil carbon emissions, particularly by coal-fired
plants in the northern hemisphere [1].
254
The Journal of Pipeline Engineering
(a) post-combustion capture, where fuel is burned with
air, by the usual means, followed by the separation
of CO2 from the flue gases;
(b) pre-combustion, where CO2 is separated after the
conversion of the fuel into a carbonless fuel (i.e.
H2);
(c) oxyfuel combustion, which occurs with pure O2 in
stoichiometric proportion, leading to a flue gas
having only H2O and CO2, the last being easily
separated as a pure stream.
PY
In terms of the probable contaminants, CO2 from oxyfuel
combustion (such as with natural gas), post-combustion,
and pre-combustion systems, could be carrying small
contents of, respectively, CH4/N2, N2, and H2.
The (total) cost of capturing and compressing CO2 ranges
from $10 to $60 per ton of CO2, according to the plant
type and other operation factors [3]. To estimate this cost,
it must be noted that, in general, all alternatives in Fig.1 are
technically well understood; it is probable that most of the
component activities can be found successfully operating
for many years as parts of other chemical- and energyproduction processes. Nevertheless, the three abovementioned alternatives have not yet been proved at the
scale required.
PL
E
In this context, CCGS – carbon capture and geological
storage – is being considered as the most viable (projected)
response by industry to the mitigation of CO2 emissions
carrying fossil carbon. CCGS demands the co-operative
intervention of three technologies: (a) the capture and
compression of CO2 from large industrial sources; (b) the
transportation of the CO2 from the sources to feasible
geological sinks; and (c) geological injection and geological
retention of the CO2.
Capture and compression of CO2 is accomplished according
to one of the three main processes shown in Fig.1:
O
As shown in Ref.1, and according to the IPCC summary,
achieving the European Union’s target of long-term
stabilization of no more than 2oC of GMTR would require
a constant deceleration of emissions such that a reduction
between 50% and 85% of the carbon emissions in 2000
could be obtained by 2050. If, instead, long-term stabilization
is projected at 3.3oC of GMTR, a milder deceleration of
emissions will be required, leading to a level of emissions
equivalent to 2000 by 2050.
affecting the transportation costs. Composition is also
important if the geological destination of the fluid
corresponds to applications in enhanced oil recovery (EOR)
since, in this case, the purity of the CO2 is a relevant factor.
C
As a result, if human energy supply remains fossil-carbonbased, and with the expected growth of population as well
the understandable expectations of rising living standards
and energy usage, cumulative greenhouse CO2 emissions
may contribute what is being called a “dangerous
anthropogenic interference” to the climate system. The key
factor behind for this is the global mean temperature rise
(GMTR) above pre-industrial levels; measurements of the
GMTR and its forecasts according to several scenarios of
fossil carbon emissions can be found in specialized sources,
such as the IPCC AR4 [2].
SA
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As explained in Ref.1, CCGS was devised as a “bridge”
technology that will be superimposed on current
technologies for energy production until new, non-fossil,
energy sources eventually become more widely established.
From a strictly short-term point of view, CCGS will add a
layer of costs to any current technology for energy
production, thus decreasing the economic efficiencies of
all plants and increasing the cost of electricity (COE) in
US$/MWhr. It is expected that the capture step alone will
add about $10-30/MWhr to a current COE of about $4060$/MWhr [1].
As can be seen, if CCGS is to become a reality, a simple
approximation shows that a target of 10 Gt of CO2 will
have to enter into the CCGS conveyor chain every year.
Capture and compression of CO2
The capture and compression of CO2 is briefly described
here as it will be probably responsible for the major
contributing slice of the total CCGS cost per unit of CO2.
Capture and compression also impacts all subsequent steps
in the CCGS chain because it affects the composition of
the fluid to be transported to the site of geo-injection. The
fluid composition, by its turn, defines properties like
compressibility, viscosity, vapour-liquid equilibrium (VLE),
and the potential for corrosion, all of which are factors
Geological injection and retention of CO2
The existence of enormous geological formations – geosinks – appropriate for CO2 storage is the decisive factor
which supports (and formerly suggested) CCGS initiatives.
But, on the other hand, as commented in Ref.1, the
theoretical capacity of geological formations as sinks for
CCGS is uncertain. In spite of this, it is easy to see that
there is, at least, a capacity of the same order of size of all
known (depleted or not) reserves of fossil carbon. Estimated
world capacities (EWC) of geo-sinks are presented in Ref.1.
EOR and ECBM (enhanced coal bed methane recovery)
are other acronyms frequently used in this context,
respectively referring to injection processes of CO2 into oil
reservoirs (to improve flow and recover more oil), and into
coal veins (to displace and recover methane).
Geo-sinks appropriate for CO2 storage are basically
associated with sedimentary basins, including:
• deep saline aquifers (EWC: 103-104Gt)
• depleted natural gas and oil reservoirs and EOR
operations (EWC: 103Gt)
• ECBM operations (EWC: 10-100Gt), and
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4th Quarter, 2008
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Fig.1. CO2 capture and compression process routes (adapted from Ref.1).
• caverns in deep saline veins.
SA
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There is thus an obvious correlation between the discovery
of geo-sinks and the exploration of oil, gas, and coal. If a
geo-sink is not a coal bed or a depleted oil-gas reservoir
itself, there is little surprise that its discovery has occurred
during drilling in oil-, gas-, and coal fields.
Although EOR (and ECBM) operations provide an apparent
CCGS paradox of using fossil carbon to get more fossil
carbon, they are considered valid CCGS destinations
because the coefficient expressing barrels of oil recovered
per ton of CO2 injected is both economical and CCGS
favourable. A little exercise with numbers can show this: in
general, EOR operations can be considered very attractive
if one ton of injected CO2 (priced, say, at the capture cost
of $10-60 per compressed ton or less) leads to, at least, one
barrel of recovered oil (priced, at the present time, at $80
per barrel or more). In this context, Ref.1 presents EOR
results for four field cases (Purdy-Northeast, SACROC,
Ford-Geraldine, and Joffre-Viking), showing that, at the
end of injection campaigns (respectively 9, 22, 5, and 15
years), approximate recovery coefficients of 0.8, 1.3, 1.6,
and 1.4 (in barrels recovered per ton of injected CO2) were
respectively obtained. Thus, it is not far from reality if we
assume a conservatively typical EOR coefficient of 1 barrel
of recovered oil per ton of injected CO2 (a rule of thumb
in West-Texas stipulates 1.7 barrel recovered per ton of
CO2 injected). Assuming, also, that the oil contains 85%
carbon by weight, we arrive at the conclusion that a ton of
injected CO2 will generate less than 0.3 tons of new CO2
after the complete oxidation of the recovered oil. So, EOR
may be also profitable on the carbon scale of CCGS if at
least 30% of the injected CO2 remains geologically stored.
The capacity and location of geo-sinks affects CCGS
feasibility as a whole, due to their direct impact on
transportation planning, investment, and cost. It is
conceivable, for instance, that CO2 would have to be
transported over large distances because more distant sinks
could be more adequate destinations than nearby formations
[1]. The adequacy of a particular candidate geological
formation as a geo-sink depends on:
• its geological nature
• its size and probable capacity of storage, if exhibiting
a favourable geology
• its potential long-term interaction with the injected
CO2
• its necessary well depths, well-head pressures,
reservoir pressure, maximum allowable flow rate of
injection per well, and
• safety and infrastructure concerns.
For instance, based on existing information on EOR
processes, a typical injection well in a EOR field has a depth
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The Journal of Pipeline Engineering
This procedure for estimating transportation cost of CO2
is, probably, the current best estimate which can be found
in the literature. The figure is impressive, and should be
carefully compared with the above-mentioned expected
cost of capture and compression of CO2 ($10-60/t).
Nevertheless, despite the very comprehensive nature of this
work, the model for CO2 pipeline uses some unnecessary
simplifications during the integration of the differential
flow model. Though understandable – because the work
was basically interested in a engineering estimate of the
pipeline diameter – the truth is that the kind of
simplifications that were made can affect the final result,
and do not necessarily guarantee that a conservative design
has been achieved. These simplifications are, by the way,
very common in pipeline engineering, but they can generate
small differences that may be relevant, particularly for long
pipelines with high flow rates operating with the special
peculiarities of CO2 in the CCGS context, namely: high
pressure, high density, high isothermal compressibility,
non-uniformity, slight supercritical condition, and sensitive
to the influence of the topography along the pipeline route.
Considering the importance of this issue, these
simplifications should be removed in order to attain a more
rigorous conclusion.
PL
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In comparison to the aspects of CCGS already discussed,
there is some industrial experience with pipeline
transportation of CO2. Nowadays, about 50Mt/yr of CO2
(equivalent to the output from 16 coal-fired power plants)
are transported by 3100km of CO2 pipeline, mainly for
EOR processes in the USA and Canada [1]. A legendary
example (perhaps the largest and longest CO2 pipeline in
the world) is the 808-km long, 30-in diameter, Cortez
Pipeline transporting 13Mt/yr of CO2 from Colorado to
oilfields in Texas, USA.
The base-case in McCoy’s study considers a 100-km pipeline
with no booster compressor, no elevation change, ground
temperature of 12oC, minimum outlet pressure of 103bar,
and inlet pressure of 138bar. This proposed pipeline extends
across the Midwest of the USA with a transportation target
of 5Mt/yr of CO2. The model designed the line with a
diameter of 16in (390mm). This analysis also reports a
capital cost of $36 x 106 and O&M of $0.325 x 106 per year.
Considering a annualized fixed cost of 15% of capital, the
unitary total cost of this transport reaches only $1.16 per
ton of CO2 per 100km. Applying a Monte Carlo sensitivity
analysis, McCoy [1] determined a range of $0.75 to $3.56
per ton of CO2 for this cost, recommending the median
value of $1.65 per ton of CO2 (per 100km) as a suitable
representative estimate for investment decisions.
PY
An efficient CO2 transportation system will be required to
address the mega-assignments of transport in the CCGS
scenario. In spite of the existence of many options for
transporting compressed (gas or liquid) CO2 from sources
to geo-sinks – including highway tankers, railway tankers,
ships, and pipelines – it is evident that the impressive
tonnages that must be transported to make CCGS feasible
will dictate that only pipelines working at high pressure and
high capacities are suitable for the job. For instance, 23Mt/yr of CO2 have to be transported to dispose of the
entire production of a single 500-MW coal-fired power
plant; this corresponds to transporting 230-350t/hr of
CO2, just to service a single, medium-sized, client. Looking
at the big picture this means, undoubtedly, that only a
network of large-scale pipelines could provide viable
overland transport of massive flow rates of CO2.
O
Transportation of CO2
year and per kilometre of pipeline) in 2004 dollars. Similar
estimates were proposed for other O&M contributions for
each item, such as booster compressors.
C
between 1000-3000m, reservoir pressure between 100-200
bar, and is usually fed with 10-50 ton CO2 per day.
SA
M
From these real cases, and from the considerable experience
of the pipeline industry with high-pressure, long-distance,
transport systems for products such as natural gas, a cost
estimation procedure for the pipeline transportation of
CO2 is possible. Nevertheless, the literature presents only
few studies addressing engineering, cost, and maintenance
of CO2 pipelines in detail, basically concentrating on rulesof-thumb for sizing CO2 pipelines, and correlations for
cost estimates, corrosion monitoring, and corrosion countermeasures [1].
Reference 1 presents an extensive engineering and cost
model for CO2 pipelines. From the projected flow rate and
related information, this model can design the basic
geometric parameters of rectilinear pipelines and estimate
capital costs and operation and maintenance costs (O&M).
Since the classes of operating pressures for CO2 pipelines
are the same as for natural gas, the capital costs were based
on a regression analysis over published project costs of
natural gas pipelines in the USA between 1995 and 2005.
The data was treated in order to convert all values to 2004
dollars using the Marshall and Swift equipment cost index.
Based on historical O&M data for a 480-km long CO2
pipeline with no booster compressor, McCoy’s model
projects a fixed O&M coefficient of $3,250/yr/km (per
The flow model in Ref.1 assumes known values of fluid
composition, weight flow rate, ground temperature, inlet
and outlet pressures, line length, and elevation change
between the initial and final points of the pipeline. This last
parameter results in a simplified topography with constant
inclination. The goal of the algorithm is the determination
of the line diameter as a floating-point number, which is
subsequently rounded-up to the nearest existing commercial
diameter.
The procedure starts with a correct differential formula in
terms of the mechanical energy balance (i.e. a differential
form of the Bernoulli equation for compressible flow),
4th Quarter, 2008
257
which was subsequently integrated assuming averaged values
of some properties and flow coordinates, namely:
temperature (θ), compressibility factor (Z), density (ρ),
viscosity (μ), friction factor (f) and Reynolds Number (Re).
We comment briefly below on some consequences of these
simplifications:
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PL
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1. The temperature (θ) is assumed constant at an
average value (θAVE) given by the ground temperature
(θ E). This simplification rules out a correct
description of the common situation where the
fluid enters the line at a different temperature.
Besides, this simplification also ignores eventual
temperature changes due to the combined action of
velocity changes of the fluid (via kinetic energy enthalpy conversion), adiabatic gravity compression/
expansion (i.e. when the heavy fluid flows along a
descending/ascending terrain), and heat transfer
(heating or cooling) from the outside. As is well
known, temperature strongly and inversely
influences the fluid density; the consequences of
taking temperature as a constant may result in an
underestimated line diameter, because ignoring
positive changes of flow temperature at intermediate
locations in the pipeline leads to overestimated
values of density and, consequently, results in
underestimation of velocity and of the coefficient of
head loss per km.
5. Changes of elevation were considered linearly
distributed along the pipeline, because the model
only demands the knowledge of the initial and final
elevation values. This simplification may have serious
impacts on the model response in the supercritical
CO2 context if the pipeline extends across a hilly
terrain (see, for example, the case of the Cortez
pipeline cited above). Essentially, CO2 flows as a
heavy compressible fluid. So ignoring the correct
topographic, point-to-point, effects, may lead to an
optimistic description of the flow behaviour.
Basically, intermediate segments in the pipeline
with sharp positive changes of elevation (very
inclined uphill segments), cause adiabatic expansion
of the fluid due to momentum loss by gravity action.
This loss of momentum is, at first, reversible and
can be recovered during subsequent downhill
segments, but the rapid expansion decreases the
fluid density, accelerating the stream, irreversibly
increasing the rate of loss of momentum via friction,
which varies nearly with the square of velocity. This
irreversible loss is not recovered when the fluid
flows through a subsequent downhill segment. The
final effect is that the pressure value at the end of the
pipeline is lower than the value predicted by the
model. Thus, this imprecision may lead to an
unfeasible design due to an incorrect diameter
selection.
PY
• the flow has only pressure as a dependent variable
• the full energy conservation principle is not observed,
and
• the mechanical energy balance is solved with several
averaged terms as constants.
4. Viscosity (μ) is calculated at θAVE and PAVE. This is a
simplification similar to (but less severe than) the
above case, causing propagation errors in the
estimation of the Reynolds Number and the friction
factor.
O
The main point lacking in this approach is that the flow
must be modelled with one independent variable – normally
the axial position (x) in the line – and two differential
equations – a momentum balance (or a mechanical energy
balance), and a full energy balance – which have to be
solved simultaneously for two flow-dependent variables:
temperature (θ) and pressure (P). The simplifications
introduced mean that:
3. The compressibility factor (Z) is assumed as a constant
calculated at θAVE and PAVE. This simplification may
be problematic because Z has a low value (0.2-0.3);
assuming a constant Z may therefore lead to large
relative errors in this property, resulting in further
errors which influence density estimation.
C
These assumptions are, in general, not significant in ordinary
flow problems but, as mentioned above, due to the
supercriticality and high density present in the CO2
transportation problem, they may acquire more importance.
reverberate strongly in velocity and head loss
calculations, affecting the profile of pressure (and,
again, the profile of the density).
2. Pressure is assumed constant at an average value
(PAVE) with the purpose of calculating averaged
properties like density, viscosity, and the
compressibility factor. This simplification introduces
errors in the above properties and in other averaged
variables (such as Reynolds Number, friction factor,
and density) calculated using them. The impact in
the model response is difficult to evaluate, but it is
not negligible because, for instance, density errors
Objective and scope of this work
According to the information stated above, and
independently of the acknowledgement of many previous
efforts by the many specialists involved with the development
of CCGS technology, it is easily recognizable, both
technically and economically, that only ‘leg’ – the transport
of CO2 by high-pressure and high-capacity pipelines – has
proved to be a reliable, feasible, and ‘ready-to-go’ technology
in the CCGS tripod.
The state-of-the-art of pipeline transportation of CO2 has
been extensively and completely studied [1]. Nevertheless,
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The Journal of Pipeline Engineering
0.04401
kg/mol
Acentric Factor (ω)
304.15 K
(30.98 oC)
Critical Volume (VC)
93.9*10-6
m3/mol
73.8 bar
Critical Density (ρC )
469 kg/m3
0.239
Triple Point Temperature (TTP)
216.6 K
(-56.6oC)
Critical Dynamic Viscosity (μC )
3.1 10-5 Pa.s
Triple Point Pressure (PTP)
as we show above, the flow model that was developed
adopted some simplifications of a practical nature which
may generate imprecision when dealing with the very
special type of flow that is presented by CO2 transportation
in the CCGS scenario.
Consonant with this, the present work addresses a more
complete modelling resource capable of generating
quantitative responses and profiles for all the flow variables
in the context of CO2 transportation by pipeline. This
approach provides a pipeline model for transportation of
CO2 (and its mixtures) in the supercritical state to an
appropriate geological formation for storage. This model
numerically solves three ordinary differential equations
corresponding to one-dimensional forms of:
Table 1. Summary of the physical
and critical constants of CO2.
pipeline model for supercritical transportation of CO2 is
introduced. The fourth section formulates and solves an
example involving a 1000-km long, 14-in diameter, pipeline
designed to transport 2.6Mt/yr (300t/hr) of a fluid with
95% CO2 for EOR finalities. This pipeline starts at an
elevation of 150m, having a destination elevation of 0m,
but it has to cross a highland section rising to 850m and a
length of 150km. The final 2500-m long section of this line
is a vertical 8-in column (or a set of several smaller columns
with the same total flow area) for geological injection of the
fluid.
The pipeline also includes three ancillary items: a booster
compressor and cooler exchanger are located just before
the pipeline section which has to climb the highland
section; a heater is installed near the injection wellheads for
pre-heating the fluid prior to expansion; and a recovery
turbine, preceded by the heater, is installed near the
wellheads to remove the excess of head from the stream,
since the descent flow in the injection column will recompress the fluid, attaining the appropriate reservoir
pressure at down-hole conditions. The investment in the
recovery turbine and heater is justified because the
conversion of heat into power thus obtained met the
requirements for power consumption of the booster
compressor.
PL
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• momentum balance
• full energy balance, and
• inventory distribution, for three dependent
variables: pressure, temperature, and fluid inventory.
5.2 bar
PY
Critical Pressure (PC)
0.274
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Critical Temperature (TC)
Critical Compressibility Factor (ZC)
C
Molar Mass (M)
SA
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The model also takes into account the properties of CO2
within a rigorous stationary high-density compressible flow
framework, in conjunction with:
(a) high-density supercritical thermodynamics by the
Peng-Robinson equation of state;
(b) topographic effects (i.e. adiabatic gravitational
compression and expansion, including the respective
thermal consequences);
(c) heat transfer effects according to the temperature
distribution in the soil and in the injection column;
(d) multiple machine stations, such as booster
compressors, exchangers, and recovery turbines;
(e) rigorous calculation of the parameters from point
to point along the pipeline.
The model was designed for engineering applications
involving long-distance pipelines transporting dense
supercritical CO2, either in its pure form or in mixtures
with other gases and fluids.
The remainder of this paper is organized in the following
manner. The next section describes the physical
characteristics of CO2 and corresponding implications in
flow problems at high density, high isothermal
compressibility, and high pressure. Following this, the
In order to make some comparison with the flow model in
Ref.1, in this fourth section we also solve another pipeline
example which was designed and analysed extensively in
the earlier study. This consists of a 100-km long, 16-in,
pipeline for transporting 5Mt/yr of pure CO2 across a
plain terrain in the Midwest of the USA, with inlet pressure
of 138bar and minimum outlet pressure of 103bar.
Although Ref.1 claims a 380-mm internal diameter pipeline
is feasible, the present model shows that the final pressure
was 102.8bar, less than the intended value. Although small
in size, this difference is critical because it shows that the
required lower limit for the head, at the end of the pipeline,
was not met by the design.
CO2: the fluid
As shown in the CO2 phase diagram in Fig.2, CO2 exhibits
large state regions where it can exist as solid, liquid, and
vapour phases. The boundary lines where two of these
4th Quarter, 2008
259
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Table 1 presents a summary of physical and critical constants
of CO2. At temperatures and pressures greater than the
critical values, the fluid is in a supercritical condition: this
state region, shown in Fig.2, is located beyond the end of
the VLE line and below the SLE line. The region of
supercritical fluid is very large in terms of pressure values,
extending from 73.8bar to almost 104bar, where the
formation of solid can occur above the critical point. In this
region the fluid can pass – isothermally, via a not necessarily
large decrease in pressure – from a typical liquid condition
(high density, low isothermal compressibility) to a typical
dense-gas condition (high density, high isothermal
compressibility) without any abrupt phase transition as
occurs across the VLE line.
Historically, long-distance pipelines were constructed for
transportation of liquids (crude oil, liquid petrochemical
commodities, fuels, and water) and certain gases (natural
gas and light petrochemical commodities). Long liquid
pipelines rarely operate above 90-10 bar pressure, whereas
in long gas systems the flow can leave the compressor
stations at 190-200bar. These differences (and others shown
below) are consequences of the following characteristics of
these two operations:
• Compressibility effects 1 (severe for gas pipelines,
O
mild for liquid pipelines): for stable liquids the fall
of pressure due to friction does not appreciably
affect the flow velocity (i.e. the fluid is assumed to be
nearly incompressible). For gas pipelines, on the
contrary, the decrease of pressure reduces density,
increasing velocity and enhancing, by friction, the
subsequent fall of pressure/density and the rise of
the velocity:
C
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regions intersect constitute the two-phase coexistence lines,
and are shown in Fig.2 as SVE (the solid-vapour equilibrium
line), SLE (the solid-liquid equilibrium line), and VLE (the
vapour-liquid equilibrium line). The intersection of all
three phase regions (and the coexistence lines) is located at
the Triple Point at -56.56oC and 5.2bar, where the three
phases coexist. The Critical Point is another special point
in the phase diagram, corresponding to the end of the VLE
line at 30.98oC and 73.8bar. The SLE line does not,
apparently, have a similar critical point.
PY
Fig.2. Phase diagram of pure CO2,
showing Triple and Critical Points,
two-phase lines (SVE: solid-vapour,
SLE: solid-liquid, VLE: vapour-liquid
equilibria), and the supercritical fluid
region.
P ↓ ⇒ ρ ↓ ⇒ v ↑ ⇒ P ↓↓ ⇒ ρ ↓↓ ⇒ v ↑↑ ...
This sequence ends, obviously, with the limit of the
speed of sound, which is a complete operational
impossibility. For this reason, gas pipelines have to
operate at the maximum possible pressure
(maximum density) so that the velocity and the head
loss per km coefficient can be kept at minimum and
almost-constant values. Recompression by booster
compressors is necessary whenever the head loss per
km exhibits a trend to increase beyond a certain
tolerance. More than merely increasing the pressure,
the role of a booster compressor is to restore the
original inclination of the descending pressure
profile along the pipeline, because the negative
inclination of this profile increases rapidly in
magnitude with the fall of pressure.
• Compressibility effects 2 (severe for gas pipelines,
mild for liquid pipelines): for stable liquids, the
consequences of a pipe rupture can be modest if
actions are immediately taken for pump shut-down.
On the contrary, for long gas pipelines, a shutdown, even followed by isolating actions along the
line, will still be insufficient to prevent a sonic
discharge of fluid through the rupture orifice until
almost all the fluid inventory of the isolated section
of the pipeline has escaped to the atmosphere. This
260
The Journal of Pipeline Engineering
For downhill sections of the pipeline, the opposed situation
occurs; the fluid is now compressed nearly adiabatically,
increasing both temperature and density, which reduces its
velocity:
z ↑⇒ P ↓ ⇒ θ ↓, ρ ↓ ⇒ v ↑ ⇒ P ↓↓ ⇒ ρ ↓↓ ...
This last effect is particularly important in the injection
column, which may be several kilometres in vertical length.
As can be seen, adiabatic heating and cooling are common
effects that must be taken into account in high-density
compressible-flow modelling. To do this, as said before, it
is necessary for the model to incorporate the temperature
(θ) as a second dependent variable.
SA
(C )
1 ⎛ ∂ρ ⎞
⎜
⎟ =∞
ρ ⎝ ∂P ⎠θ
M
PL
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Moreover, as can be seen in Table 1, the critical temperature
of CO2 is high (compared to natural gas), and close to the
ambient temperature. Thus, it is conceivable that the flow
temperature and pressure may approach the corresponding
critical values, while the fluid is maintained slightly
supercritical ( θ ≅ TC , P ≅ PC ). In this situation, the fluid
accesses a state region, just above the Critical Point, where
its isothermal compressibility is still very large, since the
critical isothermal compressibility is infinity:
Though necessary, high densities mean, as said above, that
the topography will strongly affect the flow as the fluid gains
(or loses) height (z), due to gravity. When the flow passes
through a uphill section, it expands nearly adiabatically,
experiencing reductions both of density (ρ) and temperature
(θ), and increasing its velocity and the coefficient of head
loss by friction, which leads to a subsequent fall in pressure
(see Eqn 1c, below).
PY
The specific physical properties of CO2 confer to CO2
pipelines some important differences from the above two
systems. Going directly to the point, it is enough to say that
all three above phenomena have a severe effect on longdistance CO2 pipelines, which exhibit the properties of
both high-pressure liquid pipelines and of high-pressure
compressible-flow pipelines. The reason for this is that
CO2 behaves in the line as a very dense compressible fluid,
with a density that can even approach the density of water:
compared to natural gas at same pressure and temperature,
CO2 has a density almost three times higher, which can
reach 900-1000kg/m3.
O
• High-density effects (severe for liquid pipelines,
mild for gas pipelines): contrary to the case for gas
pipelines, the high liquid density makes the
distribution of pressure in a pipeline to be strongly
affected by gravity through topographic changes of
elevation. This characteristic may even change the
pressure class at the end of a downhill section.
densities as high as possible, and at low velocities (commonly
below 2-3m/s) so as to keep friction head losses as low as
possible, thus maintaining the power consumption costs as
low as possible. In the CO2 case, the situation is no
different. CO2 has to be previously compressed and cooled
to a supercritical dense or liquid state at pressures as high
as possible, meaning supercritical pressures between 90bar
and 200bar, depending on the distance to be crossed. High
densities are mandatory; low densities mean high velocities
and extra friction, entailing huge head losses.
C
discharge will expose, despite the shut-down and
isolating actions, the environment at the rupture
location to severe risk and damage.
(1)
In other words, in the upper vicinity of the Critical Point,
the density can vary rapidly with pressure (the same kind of
phenomenon that may occur with other CO2 properties),
implying that small decreases of pressure cause rapid
increases of velocity and head loss per km, as shown in Eqn
1b below.
Another fact distinguishing CO2 and natural gas pipelines
is that, depending on the neighbourhood temperature, the
flow occurs in the liquid state in cold countries like Canada
(θ < TC) or as a supercritical dense fluid (θ > TC, in hot
countries such as Brazil).
This characteristic severely impacts the flow economy,
enhancing even more the compressibility difficulties
described above. To avoid this, the CO2 flow must be
operated at pressures above 86-90bar, where compressibility
effects are not so intense.
Finally, there is one more important difference from natural
gas pipelines: CO2 flow must be kept at a supercritical
pressure in order to prevent phase change by vaporization,
which could transform the flow into a two-phase flow,
characterized by difficulties in connection with several
possible flow regimes and associated instabilities. There is
also another reason to avoid vaporization: since the
formation of a low-density phase would accelerate the
stream, high head losses would occur, leading to further
falls of density, higher velocities, and so on.
As stated above, a basic rule in the design of compressible
flow pipelines (such as natural gas pipelines) stipulates that,
to be efficient, the long-distance transport must be done at
In summary, some characteristics expected for CO2
transportation pipelines, in the context of CCGS, are the
following:
P ↓ ⇒ ρ ↓↓ ⇒ v ↑↑ ⇒ P ↓↓↓ ⇒ ρ ↓↓↓↓ ... (θ ≅ TC , P ≅ PC )
(1b)
z ↑⇒ P ↓ ⇒ θ ↓, ρ ↓ ⇒ v ↑ ⇒ P ↓↓ ⇒ ρ ↓↓ ...
(1c)
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261
Independent Variable :
x
: axial position ( m )
Dependent Variables :
P( x )
: Pr essure ( Pa , abs )
θ( x )
: Temperature ( K )
I( x )
: Fluid Inventory ( kg )
Fluid Composition and Molar Mass :
Y
: Vector of molar fractions
MM
: Molar Mass ( kg / mol )
Ther mod ynamic Pr operties and their Dependences
U ( P ,θ ,Y ), H ( P ,θ ,Y ) : Internal Energy ( kJ / mol ) and Enthalpy ( kJ / mol )
S ( P ,θ ,Y ), V ( P ,θ ,Y ) : Entropy ( kJ / mol .K ) and Molar Volume ( m 3 / mol )
Table 2. Variables and basic
thermodynamic properties for the
pipeline model.
ρ ( P ,θ ,Y ), c( P ,θ ,Y ) : Density ( kg / m 3 ) and Sonic Velocity ( m / s )
Specialized Ther mod ynamic Pr operties
φˆiV ,φˆiL : Fugacity Coefficients of Vapor and Liquid Phases for Species i
• High operation pressures, high flow rates, and
heavy-wall pipes.
PY
the power used can be recovered in larger amounts
prior to injection from to the heating preceding the
expansion. This provides the possibility that
operating the pipeline at extra-high pressures could
be advantageous at very large flow rates because, in
this case, the pipeline has the facet of being able to
convert heat into power. This feature can be even
better exploited if the source of heat is geothermal,
as is the case in several locations in the USA.
M
C
PL
E
• In order to maintain a small value for the head loss
per km coefficient, and also to maintain the pressure
profile as supercritical (and away from the zone of
high values of isothermal compressibility), boostercompressor and intercooler stations may be necessary
at 500-600km intervals, assuming a neutral
topography. More-hilly topographies may need morefrequent booster-compressor stations.
O
• CO2 has to be compressed and cooled to a
supercritical dense or liquid state at pressures as
high as possible.
SA
• The destination of the fluid is normally an injection
column upwards of a thousand meters in length in
which, due to gravity, the fluid will be compressed
(with the help of its own large molecular mass)
during its descent to the reservoir. Thus the stream
does not need excessive pressurization to meet the
well-head conditions. The necessary thermodynamic
condition should be just a slight supercritical
temperature and a slight sub-critical pressure which,
after the natural geo-compression, can reach the
necessary EOR head. This will allow power to be
produced by the flow just prior to injection, by
means of recovery turbines preceded by heaters to
raise the fluid temperature to 100oC; this will both
enhance the power production, and avoid formation
of dry ice or excessive freezing during expansion.
The capital cost of using recovery turbines and
heaters is more than met in this process, and such
units are even capable of producing all the power
required by the intermediate compressor stations,
as we will see in the following sections of this paper.
The use of recovery turbines endorses the provision
of extra compression units along the pipeline, since
• Due to the fluid compressibility, the rate of
dissipation of mechanical energy by friction decreases
with pressure. The use of recovery turbines and
heaters, in conjunction with higher levels of
operating pressure, can therefore dramatically
increase the mechanical efficiency of the pipeline
(η) expressed by Eqn 2:
η =1−
Power dissipated by friction
Power consumption-Power recovereed
(2)
• Obviously, the optimum levels of power
consumption and power recovery through the
pipeline should be decided by taking into
consideration the pipe costs as a function of the
pressure.
Model for CO2
transportation by pipeline
The authors have developed a pipeline model appropriate
for CO2 transportation within the context of CCGS.
Tables 2, 3, and 4 present the basic nomenclature for the
variables, properties, and parameters in this model; all
units are expressed in the SI units, and the basic features of
the model are the following:
262
The Journal of Pipeline Engineering
⎛ ∂U
CV ≡ ⎜⎜
⎝ ∂θ
⎞
⎟⎟
⎠V ,Y
: Isocoric Heat Capacity ( kJ / mol .K )
⎛ ∂ρ ⎞
ΞP ≡⎜ ⎟
⎝ ∂P ⎠θ ,Y
: Isothermal Compressibility ( kg / Pa .m 3 )
⎛ ∂ρ ⎞
Ξθ ≡ ⎜ ⎟
⎝ ∂θ ⎠ P ,Y
: Isobaric Expansivity ( kg / K .m 3 )
μ
f (Re,ε / d )
v
: Dynamic Vis cos ity ( Pa.s )
: Darcy Friction Factor
: Fluid Velocity ( m / s )
q( x )
Ψ
: Fluid Flow Rate ( kg / s ) at Position x
: Tube Wall Shear Stress ( Pa )
v
: Mach Number
c
d .v.ρ
4q
=
: Re ynolds Number
Re ≡
μ
π .d .μ
M ≡
Table 3. Thermodynamic and flow properties for the
pipeline model.
The vertices are spatially-located points on the physical
domain of the pipeline. It is convenient that all special sites
along the pipeline route – including pumping and metering
stations, booster compressors, exchangers and recovery
turbines, as well client and supplier sites, etc. – are assigned
as vertices. The fluid can only enter or leave the pipeline
through the external flow rates of the vertices ({Wn}). Each
vertex n relates to a single flow specification, which is
normally its external flow rate (Wn) or its pressure (Pn). For
example, a simple junction vertex can be specified with
Wn = 0, while a client vertex should be specified by associating
to its external flow rate the (negative) value of the desired
flow rate of fluid that leaves the pipeline.
The tubes physically correspond to inclined rectilinear
segments of the pipeline, each one asymmetrically
interconnecting two vertices. The orientation of tubes is
arbitrary and is fixed a priori. The mass flow rate (q) is a
property of the tubes and is algebraically positive if the flow
obeys the tube orientation, otherwise it is negative. It is
recommended that a given tube could reproduce, as far as
possible, the topography of the pipeline section
corresponding to it: in other words, when the pipeline has
to overcome a classic highland formation, the corresponding
extension of the pipeline should be described by at least
four vertices and three tubes in order to account for the
uphill, plateau, and downhill terrain sections.
SA
M
PL
E
• Steady-state rigorous compressible flow with
specified distribution of mass flow rate (q(x)), fixed
along the line.
• One independent variable: the axial position through
the pipeline (x).
• Three dependent variables: pressure (P), temperature
(θ), and fluid inventory (I).
• Heat transfer taken into account from the
distribution of external temperature, θE(x), and the
distribution of the heat transfer coefficient Ω(x).
• Friction term via the Churchill equation for universal
Darcy friction factor (f) [4].
• Ideal gas properties from Poling, Prausnitz, and
O’Connel [5].
• Viscosity of dense compressible fluid from the Chung
et al. model [6].
• Rigorous thermodynamics from the Peng-Robinson
equation of state.
• Complete topography of the pipeline taken into
account through the distribution of elevations (z(x))
and pipeline inclinations (a(x)).
• Pipe roughness modelled as a function of position
(ε(x)).
• Pipeline description as a digraph: vertices and
oriented edges (tubes).
• Pipeline specifications: pressure at vertex 1, and
external flow rates for other vertices.
• Data of feed streams: temperature (θ), pressure (P),
and species molar fractions (Y).
vertices and E oriented edges (oriented tubes). The chemicals
present in the fluid define another important set, with C
chemical components. Components, tubes and vertices are
numbered independently: indexes i and j are used for
components, and k and n are assigned to tubes and vertices
(i, j = 1 … C, k = 1 … E, n = 1 … N) respectively. From this
point on, sets of vertex and tube properties will be
represented by the symbol { } enclosing further symbols
respectively, indexed by k and n.
PY
: Isobaric Heat Capacity ( kJ / mol .K )
O
⎞
⎟⎟
⎠ P ,Y
C
⎛ ∂H
C P ≡ ⎜⎜
⎝ ∂θ
Discrete sets associated
to vertices and tubes
In order to describe the pipeline model, and following a
strategy in network problems [7], the pipeline is first
represented in digraph form. This form is a highly-concise
representation of the system, and is composed by sets of N
The properties of the pipeline, which are known parameters
depending on position (x), should be put as discrete sets
assigned to vertices or to tubes. The degree of accuracy of
the digraph format of the pipeline will therefore increase
with the number of vertices and tubes in the representation.
In this context, some properties are assigned to vertices
while others belong to tubes: for example, the distribution
of pipeline elevations and external temperatures are
implemented as sets {zn}, {θEn} of the vertex properties, while
pipeline diameters, areas of flow section, inclinations,
segment lengths, equivalent lengths of fittings, heat transfer
coefficients, and wall roughnesses are implemented as sets
{dk}, {Ak}, {ak}, {Lk}, {LEk}, {Ωk}, {εk}of the tube properties.
Along tube k all the pipeline parameters which are known
functions of position, and can not have a fixed value as in
the sets above, are considered linearly dependent on the
axial position on the tube by using linear interpolations
made with the adjacent vertex properties. This is done, for
example, to generate the linear profiles of external
temperatures and elevations along tube k from the
4th Quarter, 2008
263
d( x )
A( x )
: Internal Diameter ( m ) at Position x
: Flow Area at Position x
LE ( x )
: Cummulative Equivalent Length ( m ) of Fittings at Position x
ε( x )
: Pipe Wall Roughness ( m ) at Position x
α( x )
⎞
⎛ dz
: Elevation ( m ) at Position x ⎜
= sin( α )⎟
⎠
⎝ dx
: Pipeline Inclination ( rd ) at Position x ( positive for uphill )
θE( x )
: Distribution of External Temperature ( K )
Ω( x )
: Distribution of Heat Transfer Coefficient ( kW / m 2 .K )
g
: Gravity Acceleration ( 9.81m / s 2 )
R
: Ideal Gas Cons tan t ( 8.314 Pa .m 3 / mol .K )
z( x )
N , E ,C
: Numbers of Vertices , Tubes and Chemical Components
Wn , q k
: External Flow Rate of Vertex n and Flow Rate of Tube k ( kg / s )
(3a)
z ( k ) ( x ) = z n1 + ( z n 2 − z n1 )( x / L k )
(3b)
As an example, consider in the above context a single
pipeline, with one supply point (at Vertex 1), several (or no)
compressor and heat-exchanger stations, and several client
vertices, all located sequentially in the line. The
nomenclature in Tables 2, 3, and 4, is used, and the focus
is on the flow through tube k, described by its independent
axial position variable x ∈ [0, L k ] .
PL
E
where x represents the axial coordinate along tube k. It must
be noted that this indexing procedure is carried out only for
the pipeline parameters; thermodynamic and flow
properties, and the flow-dependent variables, are all treated
as continuous functions of axial position in the flow.
PY
θE( k ) ( x ) = θE n1 + (θE n 2 − θE n1 )( x / L k )
Flow model equations
O
corresponding property values at the initial and final
vertices (say, vertices n1 and n2), as shown below:
C
Table 4. Pipeline parameters,
constants, and sizes of sets for the
pipeline model.
SA
M
The proposed pipeline model assumes that all positiondependent pipeline parameters in Table 4 are previously
known. Additionally, from the pipeline specifications, the
distribution of flow rate (q(x)) along the line is also known
a priori; the flow rates of all tubes are known, configuring a
set {qk} of tube flow rates.
When the flow system corresponds to a single pipeline,
extending from a single supply site, carrying fluid to a set of
client vertices, disposed sequentially with or without
intermediate booster stations, the development of the
model equations can be segmented in terms of the set of
tubes representing the pipeline. To do this, the single
spatial coordinate x is used as independent variable along
a specific tube k. In the case of a system with the topology
of a pipeline network, the situation can be very different
and will be addressed in a future work.
It can be shown that the stationary balances of momentum,
energy, and mass (i.e. the fluid inventory), applied to an
infinitesimal length of compressible, single-phase, nonisothermal flow, can be put into ordinary differential
forms, respectively shown in Eqns 4a and 4b (below), and
4c:
dI
= A k .ρ
dx
Equation 4c is the simplest, and is used to estimate the
distribution of fluid inventory (I(x)) of tube k, since the
required factor, the fluid density, is already being calculated
for use in Eqns 4a and 4b.
Eqn 4a reflects the momentum balance of the flow in tube
k, with its terms in units of rate of momentum (force) per
unit of volume. It shows that gravity creates momentum
into the flow when αk is negative (downhill flow), and steals
it from the fluid when αk is positive (uphill flow). The
intensity of this transfer is regulated by the local value of the
⎛ ⎛ q ⎞2 ⎞ dP ⎛ q ⎞2
Ψ.π .dk
dθ
⎜1 − ⎜ k ⎟ Ξ P ⎟ − ⎜ k ⎟ Ξθ
= − ρ .g .sen(α k ) −
⎜ ⎝ ρ .Ak ⎠
⎟ dx ⎝ ρ . A k ⎠
dx
Ak
⎝
⎠
⎛ ⎛ q ⎞2
θ .Ξθ ⎞ dP
⎜1 − ⎜ k ⎟ ΞP +
⎟
⎜ ⎝ ρ .Ak ⎠
ρ ⎟⎠ dx
⎝
⎛⎛ q ⎞
ρ .CP
− ⎜ ⎜ k ⎟ Ξθ −
⎜ ⎝ ρ .Ak ⎠
MM
⎝
2
(4c)
⎞ dθ
ρ .Ωk .π .dk .(θE( k ) ( x ) − θ )
⎟
= − ρ .g .sen(α k ) +
⎟ dx
qk
⎠
(4a)
(4b)
264
The Journal of Pipeline Engineering
fluid density, as shown in the equation. On the other hand,
momentum always leaves the flow by the action of friction.
The term for momentum transfer by friction is shown in
Eqn 5 using the Darcy friction factor; in this work, the
friction factor is predicted, for all single-phase flow regimes,
by the Churchill formula [4] in terms of Reynolds Number
and relative roughness (Eqn 6):
Ψ.π .dk =
f (Re, ε k / dk ) ⎛ L Ek
. ⎜1 +
2
Lk
⎝
⎞ qk . qk
⎟
⎠ ρ .dk . A k
f = f (Re, ε / d )
Thermodynamic model:
the Peng-Robinson EOS
Popular cubic EOSs following the form of Eqn 9, such as
the van der Waals EOS, the Soave-Redlich-Kwong EOS,
and the Peng-Robinson EOS (this last employed in this
model) can be presented in a generalized cubic form in
terms of the fluid density, as shown in Eqn 11:
(5)
P=
(11)
(6)
The Reynolds Number is calculated by Eqn 7:
4qk
Re =
π .dk .μ
In this equation, terms a, b, and the mixture molar mass,
MM, are dependent on the fluid composition (Y) according
to the following definitions:
(7)
C
b = ∑ Yib i
C
C
M M = ∑ Yi M M i
The EOS is also used to estimate the values of the residual
properties that must be added to the corresponding ideal
gas property values in order to estimate the properties of
the fluid. For instance, in Eqn 4b, the isobaric heat capacity
of the fluid is estimated from the respective ideal gas
( C P# (θ , Y ) ) value by Eqn 10:
C P (T , P , Y ) = C PR (T , P, Y ) + C P# (T , Y )
O
(12c)
i =1
C
b i = Ωb
PL
E
M
SA
(9)
(12b)
i =1 j =1
(8)
Equation 4b reflects the energy balance of the flow, with its
terms being the units of energy per unit of length and per
unit of volume (the same units as in Eqn 4a). This equation
shows that energy can only enter or leave the flow by gravity
and heat transfer. The left-hand sides of Eqns 4a and 4b
express the changes of energy and momentum of the flow,
and the impact of the dependent variables temperature and
pressure. These affects are dependent on an appropriate
equation of state (EOS) in order to describe the fluid’s
thermodynamics. Equations of state are normally put in
the form shown in Eqn 9, expressing pressure as a function
of density, temperature, and composition. From this, the
fluid density and the two differential coefficients ( Ξ P , Ξθ )
can be numerically determined as functions of (θ, P, Y).
C
a = ∑ ∑ Yi Yj ai (θ ) aj (θ )(1 − k ij )
PY
μ = μ (θ , P , Y )
(12a)
i =1
Equation 7 requires the estimation of the dynamic viscosity
for high-pressure, dense, compressible fluids. In order to
do this, the Chung Model [6] expressed in Eqn 8:
P = P ( ρ ,θ , Y )
Rθ .ρ
a.ρ 2
−
M M − b ρ ( M M + α .b ρ ) ( M M − β .b ρ )
RTC i
PC i
ai (θ ) = Ω a
(12d)
( RTC i )
2
PC i
Φ i (θ )
(12e)
⎡
⎛
θ ⎞⎤
Φ i (θ ) = ⎢1 + (ξ 0 + ξ1 .ω + ξ2 .ω 2 ) ⎜⎜1 −
⎟⎥
TC i ⎟⎠ ⎥⎦
⎢⎣
⎝
2
(12f)
where α , β , Ω a , Ωb , ξ 0 , ξ1 , ξ2 are positive constants
characteristic of the EOS in use. TCi, PCi, ωi, and MMi denote
the critical temperature, critical pressure, acentric factor,
and molecular mass (kg/mol) of component i. Equations
12a and 12b are known as the ‘classical EOS mixing rules’;
as shown in Table 5, at least three well-known different
cubic EOSs may result from the values chosen for these
constants. The binary interaction coefficient, kij, in Eqn
12b, is used as zero in the absence of more-detailed
information on the system of interest, and can be treated as
an additional degree of freedom to force the EOS to adhere
to a set of vapour-liquid equilibrium (VLE) data for the
system of interest.
(10)
The residual heat capacity ( C PR (T , P , Y ) ) is numerically
obtained from the EOS as a function of (θ, P, Y). All the
necessary ideal gas properties for pure components that are
used in this work come from polynomial forms presented
in Poling et al. [5].
The generalized EOS (Eqn 11) can be rewritten in a cubic
polynomial dimensionless form shown in Eqn 13 (below),
in terms of the compressibility factor Z, where:
Z=
P .M M
ρ .Rθ
Z 3 − (1 + (1 + β − α )B ) .Z 2 + ( A + ( β − α )(B + B2 ) − αβ B2 ) Z − ( AB − αβ (B2 + B3 ) ) = 0
(14a)
(13)
4th Quarter, 2008
265
Parameter
α
Soave-Redlich-Kwong EOS
1
0
0
1+ 2
−1+ 2
27/64
1/8
0
0
0
0.42748
0.08664
0.48508
1.55171
-0.1561
0.45724
0.07780
0.37464
1.54226
-0.26992
Process unit or
device
Bi =
Discharge
temperature
after cooler
Finds
isentropic
temperature
and work
Heater and
recovery
turbine
(one stage)
Discharge
pressure
Efficiency
Temperature
at turbine
entrance
Expansion
valve and
exchanger
Discharge
pressure
Efficiency
(=0)
Exchanger
Discharge
pressure
Discharge
temperature
after
exchanger
Discharge
temperature
Finds heat
duty of preheater;
finds
isentropic
temperature
and work;
Finds
isentalpic
temperature
Pb
Rθ
(14b)
Pa
( Rθ )
2
Pb i
Rθ
A i (θ ) =
Pai (θ )
( Rθ )2
(14c)
(14d)
(14e)
A typical use of the cubic EOS for property evaluation in
flow calculations follows the sequence:
. (12 ),(14 )
. (13 )
. (14 a )
θ , P , Y ⎯Eqs
⎯⎯⎯
⎯
→ A, B ⎯Eq
⎯⎯
→ Z ⎯Eq
⎯⎯⎯
→ ρ , etc
More-specialized thermodynamic properties, eventually
necessary for specific types of calculation (such as the VLE
calculations), are the fugacity coefficients ( ϕˆi ) of species in
each phase. It can be shown that such functions are written
for the generalized EOS, with Eqns 14 a-e, according to
Eqns 15(below) and 16:
ln ϕ i = − ln(Z − B) +
O
PY
Efficiency
M
A=
Discharge
ressure
SA
B=
Resolution method
Booster
compressor
(one stage) and
cooler
PL
E
Table 6. Optional process
units (devices) available in
the model.
Specifications
Peng-Robinson EOS
C
Table 5. Parameters for some
popular EOSs from the
generalized EOS (Eqn 11).
β
Ωa
Ωb
ξ0
ξ1
ξ2
van der Waals EOS
0
Applies the
efficiency.
Finds actual
work, power and
machine
temperature.
Finds heat duty.
Applies the
efficiency.
Finds actual
work, power and
discharge
temperature.
Applies discharge
temperature.
Finds heat duty.
Applies discharge
temperature.
Finds heat duty.
C
D i = 2∑ Yj A i (θ ) A j (θ )(1 − k ij )
(16)
j
VLE calculations are necessary for determining the locus of
the vapour-liquid equilibrium data for the fluid being
transported. The state path of the fluid along the pipeline
can be plotted onto the VLE locus to ascertain the formation
of two-phase flow, or to evaluate the risk of it occurring.
The VLE locus is generated by scanning pairs of temperature
and pressure with a feasible VLE solution involving the
fluid composition in question. The solution must have the
fluid composition as a liquid at its bubble point, or as a
vapour at its dewpoint. The VLE locus ends at the critical
state of the fluid composition. The VLE equations
correspond to C equalities of the product of molecular
fractions and fugacity coefficients of all components, for
the liquid and vapour phases.
Specification and resolution of thermomechanical devices in the vertices
The pipeline model allows vertices to have optional process
units (or devices) such as booster compressors, recovery
turbines, valves, and exchangers (cooler or heater) capable
of applying changes of state to the fluid before it resumes
Bi
⎛ ABi ⎞ ⎛ α
β ⎞ ⎛ ABi ⎞ ⎛ D i 1 ⎞ ⎛ Z − β B ⎞
−⎜
+
− ⎟ ln ⎜
⎟
⎟⎜
⎟+⎜
⎟⎜
Z − B ⎝ (α + β )B ⎠ ⎝ Z + α B Z − β B ⎠ ⎝ (α + β )B ⎠ ⎝ ABi B ⎠ ⎝ Z + α B ⎠
(15)
266
The Journal of Pipeline Engineering
Fig.3. Algorithm for
numerical resolution
of the pipeline model.
M
The temperature and pressure from the device specifications
overwrite the final values from the previous upstream flow
as initial conditions for the next downstream tube.
Numerical resolution of
the pipeline flow model
C
O
PY
final values from the previous stage as new IVP conditions.
Before the new stage starts, the thermo-mechanical device
allocated to the vertex (if present) is calculated by the
appropriate procedure described in Table 6. The new tube
is then selected, appropriate IVP conditions are set, and the
integration sequence is started; the procedure is repeated
until the last vertex in the pipeline is reached, and the
algorithm in Fig.3 describes the procedure.
PL
E
the flow downstream. Prior to the downstream flow
calculation, the thermo-mechanical device allocated in the
vertex (if present) is solved by the appropriate
thermodynamic procedure. Table 6 presents typical
specifications and resolution procedures for acceptable
devices in vertices as proposed by the pipeline model; in all
cases, the initial condition of the flow at the device entrance
corresponds to the thermodynamic state of the upstream
fluid.
SA
All the tubes in the pipeline model are solved sequentially
from tube 1 to E, following the flow path. The resolution
for tube k is conducted by means of numerical integration
of Eqns 4a, 4b, and 4c for the distributions of temperature,
pressure, and fluid inventory, using the known distribution
of tube flow rates. Several terms and properties, required in
Eqns 4 a-c, are directly obtained through Eqns 5-14. The
numerical integration proceeds via an ‘adaptive gear method’
modified for highly-stiff problems [8].
Each tube k is integrated from its initial vertex n1 to its
ending vertex n2. The dependent variables should be known
at n1 as in the standard initial value problem (IVP). The
initial condition of tube k is written as θ 0( k ) , P0( k ) , I 0( k ) . For
tube k = 1, the initial temperature and pressure correspond
to the fluid conditions at the pipeline entrance; the initial
inventory is obviously set to zero.
When the integration for tube k reaches its end vertex, the
final values of dependent variables (θ, P, I) can be prepared
as initial values for the integration for the next stage. But,
if this vertex is equipped with a process device, the device
specifications of temperature and pressure overwrite the
Two examples of CO2 pipelines
The pipeline model is illustrated using two examples,
described as follows. Both use same the thermodynamic
and transportation property models as well as the pipeline
model described in the previous section.
Example 1: 14-in, 300ton, 200bar, V6
This is a 1000-km long pipeline, 14-in (350mm) internal
diameter, pipeline carrying 300t/hr (2.6Mt/yr) of fluid
containing CO2, CH4, and N2. The pumping pressure at
Vertex 1 is 200 bar. There is a booster compressor at vertex
6, and the pipeline has two client vertices, the last of which
is the bottom of a 2500-m deep injection column the
diameter of which is 200mm. 16 vertices and 15 tubes were
proposed. Tables 7, 8, and 9 present, respectively, feed
data, tube data, and vertex data for this example. Figures 4
and 5 present the VLE locus of the fluid on planes P vs θ,
and P versus ρ.
Figures 4 and 5 are useful concerning the thermodynamics
of the fluid in this example, because they clearly show the
state region where the mixture is two-phase. This two-phase
domain is defined by the union of the bubble and dew lines
with the region between them; the critical point of this
fluid (according to Peng-Robinson EOS with zero binary
parameters of interaction) is near 78bar and 27oC, 3-4oC
below the critical temperature of pure CO2 and a few bars
above its critical pressure.
4th Quarter, 2008
267
O
vertical injection column, with external temperature
changing gradually from 20oC to 67oC.
C
The pipeline is fed with fluid at 200bar, but to overcome
the highland formation, starting at position 450km, a
booster compressor was installed prior to the uphill segment
to recompress the fluid to 200bar. This compressor has a
cooler to recondition the fluid to 37oC, if necessary. As a
result of the head recovery in the downhill segment, the
excess pressure of the fluid should be reduced prior to its
delivery, and for this reason the fluid is pre-heated in vertex
12 to 105oC and flows to the turbine in vertex 13 to be
expanded to 70bar, releasing power. The turbine has an
after-cooler to accommodate the decrease in temperature
of the stream, if necessary. Finally, at vertex 15, the fluid
PL
E
The pipeline in Example 1 is depicted spatially in Fig.6,
where each axis uses a different scale. The little orange
circles and the coloured diamonds are ‘flagging’ the system
tubes and vertices; the vertices are coloured according to
the specification in Table 8. The pipeline discharges fluid
at vertices 14 and 16, and vertex 15 is the well-head of the
injection column that ends at vertex 16. The pipeline
exhibits changes of elevation in the following segments:
PY
Fig.4. VLE locus P vs θ
for the fluid in Table 7.
SA
M
• vertex 6 to vertex 7 (tube 6) is an uphill slope,
50.005km long, ascending to a plateau at an altitude
of 850m from a level of 150m;
• vertex 8 to vertex 9 (tube 8) is a downhill slope,
50.007km long, descending to an altitude of 0m;
• vertex 15 to vertex 16 (tube 15) is a 2500-m long
Fig.5. VLE locus P vs ρ for the
fluid in Table 7.
268
The Journal of Pipeline Engineering
Composition
CO2 95%mol
CH4 2%mol
3%mol
N2
Flow rate
Temperature
Pressure (abs)
Molar mass
ρ (density)
952.74 kg/m3
300 t/h
200 bar
10oC
(283.15 K)
(2.6 Mt/y)
Calculated thermodynamic and transport properties
c (sonic velocity)
Z
CP
545.35 m/s
0.3834
0.0917 kJ/mol.K
Fluid state
Liquid
9.5E-5 Pa.s
μ
γ = C P / CV
U
S
-388.638 kJ/mol
-0.07306 kJ/mol.K
Table 8. Tube data for Example 1.
y(m)
z(m)
Elevation
150
150
150
150
150
150
Fittings
M
SA
LE
(m)
3.2725
3.2725
3.2725
3.2725
3.2725
3.2725
3.2725
3.2725
3.2725
3.2725
3.2725
3.2725
36.38
3.2725
---
1 GateVlv
1 GateVlv
1 GateVlv
1 GateVlv
1 GateVlv
1 GateVlv
1 GateVlv
1 GateVlv
1 GateVlv
1 GateVlv
1 GateVlv
1 GateVlv
1GateVlv+1T
1 GateVlv
---
O
Ground
temp. θE
20oC
20oC
20oC
20oC
20oC
20oC
Extra
device
1
0
0
--2
100E3
0
--3
150E3
0
--4
250E3
0
--5
350E3
0
--6
450E3
0
Comprs
+
Cooler
7
500E3
0
850
20oC
--W=0kg/s
o
8
650E3
0
850
20 C
--W=0kg/s
9
700E3
0
0
20oC
--W=0kg/s
10
800E3
0
0
20oC
--W=0kg/s
11
900E3
0
0
20oC
--W=0kg/s
12
970E3
0
0
20oC
Heater
W=0kg/s
13
970010
0
0
20oC
Turbine
W=0kg/s
+
Cooler
14
971E3
0
0
20oC
--W=-41.7kg/s
15
1000E3
0
0
20oC
--W=0kg/s
16
1000E3
0
-2500
67oC
--W=-41.7kg/s
Comprs: 1 Stage Adiabatic Compressor; Turbine: 1 Stage Adiabatic Turbine; Effic: Efficiency
Table 9. Vertex data for Example 1.
Table 7. Feed data for
Example 1.
PY
Ω
(kW/m2K)
5E-3
5E-3
5E-3
5E-3
5E-3
5E-3
5E-3
5E-3
5E-3
5E-3
5E-3
5E-3
5E-3
5E-3
5E-3
C
PL
E
Length
Diameter (ID)
Roughness
(m)
(m)
(m)
1
100E3
0.35
4.572E-5
2
50E3
0.35
4.572E-5
3
100E3
0.35
4.572E-5
4
100E3
0.35
4.572E-5
5
100E3
0.35
4.572E-5
6
50005
0.35
4.572E-5
7
150E3
0.35
4.572E-5
8
50007
0.35
4.572E-5
9
100E3
0.35
4.572E-5
10
100E3
0.35
4.572E-5
11
70E3
0.35
4.572E-5
12
10
0.35
4.572E-5
13
990
0.35
4.572E-5
14
29E3
0.35
4.572E-5
15
2500
0.20
4.572E-5
GateVlv : Gate Valve 100% Open, T :Standard Tee
x(m)
H
-387.736 kJ/mol
2.29404
Tube
Vertex
0.042971 kg/mol
Vertex
specification
P=200bar
W=0kg/s
W=0kg/s
W=0kg/s
W=0kg/s
W=0kg/s
Device
specification
----------POUT 200bar
TOUT 37oC
Effic 60%
----------TOUT 105 oC
POUT 70bar
TOUT 37oC
Effic 60%
------P
P
269
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4th Quarter, 2008
Fig.6. Spatial representation of the pipeline for Example 1.
descends into the injection column, where it gradually
recovers pressure by gravitational compression. During
this sector, the fluid also gradually increases its temperature
due to compression and due to the rising temperature of
the column walls.
Figures 7 and 8 show the simulated spatial profiles of
pressure and temperature for the pipeline in Example 1. In
Fig.8, in the domain of tube 1, it can be seen that the flow
takes about 70km to bring the fluid temperature from the
feed value of 10oC to the ground value of 20oC. In Figs 7
and 8, each important physical transformation undergone
by the fluid during the transfer is identified; for example,
At vertex 12, the heater raises the fluid temperature to
105oC, at approximately 120bar of pressure., for which
approximately of 20,000kW is required. The flow then
arrives at vertex 13 where the recovery turbine reduces its
pressure to 70bar producing 1350kW of power. An extra
cooling of 3000kW is necessary to attain the required
pipeline temperature of 37oC at the outlet of vertex 13. The
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The numerical resolution of this example starts from the
initial condition of the pipeline where fluid conditions
correspond to the feed data in Table 7, i.e. θ = 10oC, P =
200bar, and I = 0kg. Using the numerical solution, profiles
of the dependent variables, thermodynamic properties,
and flow properties can be draw. In order to facilitate the
analysis of the results, which come in the form of spatial
profiles against position, the graphic’s background is colourcoded corresponding to the set of tubes in the pipeline, so
that the spatial domain of each tube becomes more clearly
visible. For instance, the domain of tube 1 is red, tube 2
domain is orange, and so on. The width of one domain is
proportional to the length of the tube in question.
the pressure can be seen to fall steadily until vertex 6 is
reached, near 125bar. The pressure then rises back to
200bar due to the booster compressor, consuming 1250kW
of power. During the next, 50-km long, uphill segment
(vertex 6 to vertex 7), the pressures again falls to near
130bar along a highly-negative gradient. In Fig.8, slight
cooling can be identified during this expansion along the
uphill section. At vertex 7 the plateau has been reached,
and there follows a 150-km long horizontal section (vertex
7 to vertex 8) where the pressure gradient is similar to the
gradient upstream of vertex 6. At the end of the plateau, the
downhill section (vertex 8 to vertex 9) exhibits a highlypositive pressure gradient, showing that compression takes
place, and the pressure increases to approximately 170bar.
The temperature also rises, but it is attenuated by the
cooling effect of the ground. At the downhill end, the flow
crosses a 270-km long horizontal section (vertex 9 to vertex
12) where the pressure gradient is again similar to the
gradient upstream of vertex 6.
270
The Journal of Pipeline Engineering
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Fig.7. Profile of pressure for the
pipeline in Example 1.
Fig.8. Profile of temperature for the
pipeline in Example 1.
Fig.9. Summary of results for the
thermo-mechanical devices at vertices:
SP = specified, in = inlet, out = outlet,
Q = heat duty
[booster compressor + cooler at v6,
heater at v12, turbine + cooler at v13]
4th Quarter, 2008
271
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Fig.10. Profile of fluid velocity for the
pipeline in Example 1.
Fig.11. Profile of fluid density for the
pipeline in Example 1.
power produced by the recovery turbine is sufficient to
drive the booster compressor at vertex 6, obviously at the
expense of reducing the density of the fluid to be injected.
rises from near 20oC to more than 70oC. The fluid reaches
the reservoir at a pressure almost of 130bar, which is
adequate for this application.
At the outlet condition of vertex 13, the fluid is supercritical
at 70bar and 37oC. This condition allows the flow to arrive
at vertex 14, situated 1km downstream of vertex 13, where
the first client receives 150t/hr of fluid. The flow rate
inside the pipeline, which continues the flow toward vertex
15, is now only 150t/hr. Vertex 15 is reached 27km
downstream from vertex 14, with a pressure of 67bar and
temperature near the ground temperature of 20oC, and
geo-injection through tube 15 then takes place. As the
gravitational compression takes place, a rise of pressure
occurs from 67bar to almost 130bar. Temperature also
Figure 9 reports a summary of results for the thermomechanical devices at vertices 6, 12, and 13, corresponding
respectively to booster compressor and cooler at vertex 6,
pre-heater at vertex 12, and turbine and cooler at vertex 13.
The values reported in the text above for power and heat
duties of thermo-mechanical devices are depicted as bars in
Fig.9. The profile of flow velocity is depicted in Fig.10,
showing that it was successfully maintained below 3m/s as
prescribed. Higher velocities were only observed at the
heater outlet and through the injection column. The
profile of density is shown in Fig.11, while the profile of the
272
The Journal of Pipeline Engineering
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Fig.12. Profile of compressibility factor
for the pipeline in Example 1.
compressibility factor is shown in Fig.12. The profile of
fluid inventory is depicted in Fig.13, showing that there are
almost 80,000 tonnes of fluid in this pipeline.
Figure 14 depicts the complex flow path of the fluid onto
its VLE locus on the plane P (bar) vs θ (oC). Figure 15
depicts a magnification of the same flow path to allow the
details of the state trajectory to be more visible: the path
starts at the feed condition with θ =10oC and P = 200bar,
well above the bubble point curve (i.e. as a compressed subcooled liquid). Gradually, the fluid state migrates directly
toward the two-phase region at a temperature near the
ground temperature of 20oC. The booster compressor
stops this trend and restores the fluid to a high-pressure
state. The final moves of the fluid state show that it almost
touches the dew-point curve when the fluid arrives at vertex
15 with a pressure of 67bar and temperature near the
Fig.13. Profile of fluid inventory
(tonnes) for the pipeline in Example 1.
ground temperature of 20oC. The pressure rises again as
the flow enters the 2500-m long injection column, achieving
almost 130bar in the downhole conditions; the final density
of the fluid downhole is above 300kg/m3. If a higher
density is required, the injection pressure should be
increased by reducing the loss of pressure in the recovery
turbine, although this results in losing a fraction of the
power recovery.
Example 2: 16-in, 571ton, 134bar
This example concerns the base-case of the CO2 pipeline in
Ref.1. This is a 100-km long pipeline carrying 571t/hr
(5Mt/yr) of pure CO2; the pumping pressure (Vertex 1) is
134bar, and the pipeline does not have changes of elevation.
There is only one client vertex at the end of the line; a basic
4th Quarter, 2008
273
Fig.15. Magnification of
the flow path in Fig.14.
Fig.16. VLE locus P vs θ
for the fluid in Table 11.
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Fig.14. The VLE locus for the
pipeline in Example 1.
274
The Journal of Pipeline Engineering
ρ (density)
944.28 kg/m3
Pressure (abs)
Flow rate
Temperature
571 t/h
12oC
134 bar
(5 Mt/y)
(285.15 K)
Calculated thermodynamic and transport properties
c (sonic velocity)
Z
CP
507.38 m/s
0.27127
0.1029 kJ/mol.K
Fluid State
Liquid
8.4E-5 Pa.s
Composition
CO2 100%mol
μ
Molar mass
0.044 kg/mol
H
Table 10. Feed
data for the
pipeline in
Example 2.
-406.206 kJ/mol
γ = C P / CV
U
S
2.5363
-406.85 kJ/mol
-0.07259 kJ/mol.K
Length
(m)
Diameter (ID)
(m)
Roughness
(m)
Ω
(kW/m2K)
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
10E3
5E3
10E3
10E3
10E3
5000
15E3
5000
10E3
10E3
7E3
1
99
400
2500
0.38
0.38
0.38
0.38
0.38
0.38
0.38
0.38
0.38
0.38
0.38
0.38
0.38
0.38
0.38
4.572E-5
4.572E-5
4.572E-5
4.572E-5
4.572E-5
4.572E-5
4.572E-5
4.572E-5
4.572E-5
4.572E-5
4.572E-5
4.572E-5
4.572E-5
4.572E-5
4.572E-5
5E-3
5E-3
5E-3
5E-3
5E-3
5E-3
5E-3
5E-3
5E-3
5E-3
5E-3
5E-3
5E-3
5E-3
5E-3
Fittings
C
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Tube
-------------------------------
LE
(m)
-------------------------------
0
10E3
15E3
25E3
35E3
45E3
50E3
65E3
70E3
80E3
90E3
97E3
97001
97100
97500
100E3
y(m)
z(m)
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
0
Elevation
150
150
150
150
150
150
150
150
150
150
150
150
150
150
150
150
M
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
x(m)
SA
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Table 11. Tube data for the pipeline in Example 2.
Ground
temp. θE
12oC
12oC
12oC
12oC
12oC
12oC
12oC
12oC
12oC
12oC
12oC
12oC
12oC
12oC
12oC
67oC
Vertex
specification
P=134bar
W=0kg/s
W=0kg/s
W=0kg/s
W=0kg/s
W=0kg/s
W=0kg/s
W=0kg/s
W=0kg/s
W=0kg/s
W=0kg/s
W=0kg/s
W=0kg/s
W=0kg/s
W=0kg/s
W=-158.6kg/s
Extra
device
---------------------------------
Device
specification
---------------------------------
Table 12. Vertex data for the pipeline in Example 2.
premise of this study was that the fluid pressure at this
client vertex should be equal to or greater than 103bar.
There are no extra thermo-mechanical devices. The design
method in Ref.1 calculates an internal diameter of 380mm
(14.9in), which was subsequently rounded to a larger
commercial diameter of 390mm (15.3in). However, since
380mm was established as a feasible diameter for the
design, it is this value that we consider in the present
comparison.
The same mesh of 16 vertices and 15 tubes was proposed to
represent the system, and Tables 10, 11, and 12 present,
respectively, feed data, tube data, and vertex data for this
example. Figures 16 and 17 present the VLE locus of this
4th Quarter, 2008
275
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Fig.17. VLE locus P vs ρ
for the fluid in Table 11.
Fig.18. Profile of pressure for the
pipeline in Example 2.
fluid on planes P versus θ, and P versus ρ. Since the fluid
is a pure substance, the VLE locus in Fig.16 is the single
VLE line of Fig.2 (the bubble and dew curves are the same),
as seen by the Peng-Robinson EOS. Figure 17 shows the
state region where the mixture is two-phase.
The numerical resolution of this example starts with the
initial condition of the pipeline where the fluid conditions
correspond to the feed data in Table 10. With the numerical
solution for this example, profiles of dependent variables,
thermodynamic properties and flow properties can be
drawn, and Figs 18-21 show the simulated spatial profiles
of pressure, temperature, velocity, and density. In Fig.18
the profile of pressure can be seen to have a practicallyconstant coefficient of head loss per km, and the velocity
and fluid density are almost constant, which can be
confirmed through Figs 20 and 21. Figure 19 shows a very
small temperature drop along the pipeline route: the fluid
loses 1oC (below the ground temperature) between vertices
1 and 16 as can be seen in the figure. This is probably due
to a mild Joule-Kelvin effect created by the fall of pressure
from 138bar to almost 103bar, but attenuated by the heat
transfer from the ground, which prevents the sharper
cooling associated with the isenthalpic expansion.
Figure 20 shows the velocity profile for this example,
showing that there was only a 3% of increase in this
variable. This is reflects the almost-constant density, which
decreased by only 3% after 100km of flow. This behaviour
is also shown in the density profile Fig.21.
Figure 22 depicts the flow path of the fluid and its VLE
276
The Journal of Pipeline Engineering
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Fig.19. Profile of temperature for the
pipeline in Example 2.
locus on the plane P versus ρ. The path starts at the feed
conditions of θ = 12oC and P = 134bar, well above the
bubble point curve (i.e. as a compressed sub-cooled liquid).
Gradually it migrates directly toward the bubble curve at a
temperature slightly below the ground temperature of
12oC. The flow is properly monophasic (i.e. as a compressible
liquid) along the entire pipeline.
The purpose of this example is to analyse the feasibility of
the pipeline design proposed in Ref.1. To do this, we have
to take a good look at the pressure at the end of the pipeline
and compare it with the desired lower bound of 103bar.
Figure 23 magnifies the end section (i.e. the end of the
domain of tube 15) of the pressure profile in Fig.18; it can
be seen that the final fluid pressure corresponds to 102.8bar.
This implies a small, but nevertheless perceptible, loss of
feasibility for the pipeline design as proposed in Ref.1. The
Fig.20. Profile of flow velocity for
the pipeline in Example 2.
target lower bound of 103bar of pressure at the pipeline
end point is unattainable with an internal diameter of
380mm.
The point is, as mentioned at the end of the first section of
this paper, that there are some unnecessary simplifications
in this model which may compromise the final design.
Although this methodology applies simplifications based
on taking averaged values of thermodynamic and flow
properties, it can be seen that none of them are conservative
or design protective, and they affect the design erratically
and in an unpredictable way.
This small imprecision (which can be considered to be
fairly common in pipeline engineering) may become
invisible (or practically disappear) in short pipelines or
those that are operating at low flow rates. But similarly it
4th Quarter, 2008
277
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Fig.21. Profile of density for the
pipeline in Example 2.
Fig.22. Flow path on the VLE locus for
the pipeline in Example 2.
Fig.23. Magnification of the end
section (tube 15) of the pressure
profile for the pipeline in Example 2.
278
The Journal of Pipeline Engineering
can become more influential in longer systems at higher
flow rates, or with those that have sharp positive changes of
elevation and/or positive changes of temperature. Although
this imprecision, as verified here, can generate unfeasible
designs by only the smallest of margins in the majority of
cases, it can have a considerable impact on others.
• rigorous dense compressible fluid flow modelled
with 1-D momentum and total energy balance
equations;
• three dependent flow variables: pressure, fluid
temperature, and fluid inventory
• heat transfer taken into account;
• rigorous description of pipeline topography and
gravitational effects on the flow;
• multiple thermo-mechanical devices allowed, such
as booster compressors, exchangers, and recovery
turbines;
• properties rigorously calculated from point to point
along the route, and no averaged properties are
used.
Concluding remarks
PY
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E
Although there is no ‘T’ in the above acronym, it is
acknowledged that only the transportation step, through
high-pressure, high-capacity, CO2 pipelines, is the currentlyproven reliable and (very) economic technology in the
CCGS ‘tripod’. The estimated cost of CO2 transportation
ranges between $1 to $2 per ton per 100km for highcapacity pipelines [1].
This CO2 pipeline model was able to simulate the transport
performance of a 16-in, 1000-km long pipeline, working at
2.6Mt/yr of a gas with 95% CO2. The pipeline is fed with
a fluid at 200bar pressure; starting from the pump station
at 150m altitude, the pipeline had to cross a 250-km long
highland area with an altitude of 850m. A booster
compressor was installed at the beginning of the uphill
section to repressure the fluid to 200bar. Due to the
recovery of the hydraulic head during the downhill section,
a heater and a recovery turbine were installed near the two
client sites at the end of the pipeline. The production of
power by the recovery turbine was sufficient to drive the
booster compressor. The last segment of the pipeline is a
vertical, 8-in diameter, 2500-m long, injection column to
carry the fluid to the geological sink. Following
depressurisation through the recovery turbine, the pipeline
delivers fluid to the wellhead at the minimum possible
head, taking advantage of the gravitational compression
occurring during the descent to repressurize the fluid to the
level of pressure required by the sink. In this example,
specific issues characteristic of CO2 transport, such as the
expected effects of dense supercritical compressible flow
and rapid variation of hydraulic head across height changes
(including the associated thermal effects), were reproduced
by the model
C
This paper presents a brief review of some aspects of CO2
transportation in connection with carbon capture and
geological storage (CCGS) strategies. Basically, CCGS is
the projected main response by industry towards mitigating
CO2 emissions carrying fossil carbon. As explained in
Ref.1, CCGS was devised as a “bridge” technology to be
superimposed on current fossil energy technologies until
new, no-fossil, energy sources eventually become more
widely established. CCGS involves the co-operation of
three technologies: CO2 capture at industrial sources and
compression; CO2 transportation from sources to geological
sinks; and geological storage.
SA
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The capture and compression step, though well-known on
technical grounds, is not yet proven to be operational
under long-term conditions. The corresponding cost of
capture is also impressive, ranging between $10 to $60/ton
of CO2, depending on the process of CO2 production and
on the technology adopted for its capture.
The geological storage step, which was originally behind
the CCGS initiatives, ironically still demands more
quantitative methods and reliable estimation procedures
in order to establish the critical parameters for geological
sinks, including: the practical long-term capacity of storage;
the long-term behaviour of the maximum admissible flow
rate of injection per well; the dynamics of the interaction of
CO2 with the sinks; the security and stability of the
reservoirs of stored CO2; and the necessary procedures for
long-term monitoring the integrity of the CO2 reservoirs.
In connection with the initiatives on CO2 transportation,
this work presents a one-dimensional model for CO2
transport by high-pressure pipeline. This model was designed
for engineering applications involving long-distance
pipelines transporting dense supercritical CO2 either in its
pure form or in mixtures with other gases and fluids. The
model has the following features:
• rigorous thermodynamics of dense supercritical
fluids through the Peng-Robinson EOS;
The proposed pipeline model was also used to simulate the
base-case pipeline for CO2 transport analysed in Ref.1.
This comparison shows that despite the modest
simplifications present in the design for the base-case
pipeline, the special characteristics of supercritical CO2
made the proposed design unfeasible, albeit by a small
margin of pressure at the destination of the pipeline.
References
1. S.T.McCoy, 2008. The economics of CO2 transport by
pipeline and storage in saline aquifers and oil reservoirs. PhD
Thesis, Carnegie-Mellon University, Pittsburgh, USA.
2. B.S.Fisher, et al., 2007. Issues related to mitigation in the
long term, context, In: Climate Change 2007: Mitigation.
Contribution of Working Group III to the 4th Assessment
Report of the Inter-governmental Panel on Climate Change
4th Quarter, 2008
279
6. T.H.Chung, et al., 1988. Generalized multi-parameter
correlation for nonpolar and polar fluid transport properties.
Industrial & Engineering Chemistry Research, 27, pp671-679.
7. R.S.H.Mah, 1990. Chemical process structures and
information flows. Butterworth Publishers, New York.
8. J.L.de Medeiros, A.L.H.Costa, J.P.P.Neto, and O.Q.F.Araújo,
2002. Dynamic modeling of pipeline networks for dense
compressible fluids tuned with time series of plant data. Proc.
IPC-2002, International Pipeline Conference, Calgary,
Canada.
PL
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PY
(IPCC), B.Metz et al. Eds, Cambridge University Press,
Cambridge, UK.
3. K.Thambimuthu et al., 2005. Capture of CO2 in IPCC
Special Report on Carbon Dioxide Capture and Storage,
B.Metz et al. Eds, Cambridge University Press, Cambridge,
UK.
4. S.Churchill, 1977. Friction-factor equation spans all fluidflow regimes. Chemical Engineering, 11, pp91-92.
5. B.E.Poling, J.M.Prausnitz, and J.P.O’Connell, 2001. The
properties of gases and liquids, 5th Edn, McGraw-Hill Book
Co.
M
Technical Writing A–Z: A Commonsense
Guide to Engineering Reports and Theses,
British English Edition
INTEREST
FROM
ASME PRESS
by Trevor M. Young
by James A. Wingate
Topics include: format and content of reports and theses;
copyright and plagiarism; print and Internet reference citation; abbreviations; units and conversion factors; significant
figures; mathematical notation and equations; writing styles
and conventions; frequently confused words; grammatical
errors and punctuation; commonsense advice on issues
such as getting started and holding the reader’s attention.
Gain practical knowledge from frank, colorful cases and
learn to solve mechanical problems related to hydraulics,
pipe flow, and industrial HVAC and utility systems with
these organized solutions to the problems involving: water
and steam hammer phenomena; gravity flow of liquids in
pipes; siphon seals and water legs; regulating steam pressure drop; industrial risk insurers’ fuel gas burner piping
valve train; controlling differential air pressure of a room
with respect to its surroundings; water chiller decoupled
primary-secondary loops; pressure drop calculations of
incompressible fluid flow in piping and ducts; water chillers
in turndown; hydraulic loops; radiation heat transfer; and
thermal insulation.
SA
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280
The Journal of Pipeline Engineering
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4th Quarter, 2008
281
Fracture propagation in CO2
pipelines
by Dr Andrew Cosham*1 and Robert J Eiber2
1 Atkins Boreas, Newcastle upon Tyne, UK
2 Robert J Eiber Consultant, Inc, Columbus, OH, USA
T
HE FOURTH REPORT from the Intergovernmental Panel on Climate Change states that “Warming of
the climate system is unequivocal…”. It further states that there is a “very high confidence that the
global average net effect of human activities since 1750 has been one of warming.” One of the proposed
technologies that may play a role in the transition to a low-carbon economy is carbon dioxide capture and
storage (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.
C
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The transportation of CO2 by long-distance transmission pipeline is an established technology; there are
examples of CO2 pipelines in USA, Europe, and Africa. The design and operation of a CO2 pipeline is more
complicated than a typical hydrocarbon pipeline, because of the highly non-linear thermodynamic properties
of CO2 and because it is normally transported in a pipeline as a dense-phase fluid. There are number of issues
to be considered. Furthermore, CO2 captured from fossil-fuel power stations may contain different
proportions and/or types of impurities from those found in the sources of natural or anthropogenic CO2
transported in existing CO2 pipelines.
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Fracture propagation control is one such issue that requires careful consideration in the design of a CO2
pipeline. CO2 pipelines may be more susceptible to long running ductile fractures than hydrocarbon gas
pipelines. The need to prevent such propagating fractures imposes either a minimum required toughness
(in terms of the Charpy V-notch impact energy) or a requirement for mechanical crack arrestors. Indeed,
fracture propagation control has implications for the diameter, wall thickness, and grade of the pipeline, in
addition to the Charpy V-notch impact energy of the linepipe steel, because in some situations the
requirement for fracture propagation control will dictate the design of a CO2 pipeline.
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The issues surrounding fracture propagation control in a CO2 pipeline are illustrated through the means
of two simple design examples: a 24-in (609.6-mm) diameter pipeline with a design pressure of 100bar
(1450psi), and a 18-in (457.2-mm) diameter pipeline with a design pressure of 180bar (2610psi). It is been
shown that fracture propagation control in a CO2 pipeline can be addressed relatively simply. Some care
is required because the trends observed in CO2 pipelines are not the same as those in natural gas pipelines,
and the required toughness to arrest a ductile fracture may be very sensitive to small changes in the design
parameters. Nevertheless, provided that fracture control is considered early in the design, any constraints
on the design can be identified and, in principle, resolved without too much difficulty. It is important not
to forget that transportation is an implicit, and essential, part of CCS.
T
HE FOURTH report from the Intergovernmental
Panel on Climate Change (IPCC) [1] states that
“Warming of the climate system is unequivocal, as is now
evident from observations of increases in global average air
and ocean temperatures, widespread melting of snow and
ice, and rising global average sea level.” It further states that
there is a “very high confidence that the global average net
effect of human activities since 1750 has been one of
warming.” Provided that action is taken soon to reduce
emissions of ‘greenhouse gases’, the potentially severe
effects of climate change can be avoided, without excessive
cost [2, 3].
* Author’s contact information:
tel: +44 (0)191 230 6501
email: [email protected]
Carbon dioxide capture and storage (CCS) is one of the
technologies that has been proposed to reduce emissions of
carbon dioxide (CO2) to the atmosphere from fossil-fuel
282
The Journal of Pipeline Engineering
FAILURE
fracture
initiation
control
LEAK
RUPTURE
PROPAGATION
ARREST
fracture
propagation
control
Fig.1. Fracture control.
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Fracture control is concerned with designing a pipeline
with a high tolerance to defects introduced during
manufacturing, construction, and service; and preventing,
or minimizing, the length of long running fractures. CO2
pipelines are potentially more susceptible to long running
fractures than conventional natural gas pipelines.
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A second factor that has raised the profile of CCS amongst
governments is the need to ensure security of energy
supply. Clean-coal technology is seen as having the potential
to make a significant proportion of a diverse low-carbon
energy mix. Coal is one of the most available sources of
energy in the USA, and similarly in the UK and other parts
of Europe, not to mention the rest of the world. A cleancoal power station would incorporate CCS. The UK
government, through the Department for Business,
Enterprise, & Regulatory Reform (BERR) has organized a
competition to develop a commercial-scale coal-fired plant
capable of demonstrating the full range of CCS
technologies1. The project envisages the construction of a
300-400MW plant, capable of capturing up to 90% of its
CO2 emissions. A number of countries around the world,
including Australia, the USA, and Norway, also have
government supported projects to develop commercialscale CCS power stations. A 30-MW pilot plant at the
Schwarze Pumpe power station in Germany, demonstrating
carbon capture and storage, opened in September, 2008 [5,
6]. However, initially the CO2 is being transported from
the plant to the storage site by road tanker, not pipeline.
The transportation of CO2 by long-distance transmission
pipeline is an established technology. However, the design
and operation of a CO2 pipeline is more complicated than
a typical hydrocarbon pipeline [7, 8]. One of the issues that
needs to be considered is fracture control, and specifically
fracture propagation control.
C
power stations. An IEA (International Energy Agency)
study estimated that the widespread adoption of CCS
technologies could contribute approximately 20% of the
reduction in emissions required to reduce projected
emissions in 2050 to their 2003 levels (although, in
comparison, energy-efficiency measures could contribute
approximately 45%) [4].
In simple terms, there are two types of carbon-capture
technology: pre-combustion and post-combustion, with
various methods of implementing either technology. The
composition of the ‘captured’ CO2 will depend on the
process used to capture it. Once the CO2 is captured, it
needs to be transported to where it is to be stored. Pipelines
can be expected to play a significant role in the required
transportation infrastructure [7]. Transportation is an
essential part of carbon capture and storage, but sometimes
appears to be something of a ‘Cinderella’ subject.
1 The CCS demonstration competition now falls under the remit of the
Department for Energy and Climate Change (DECC).
Existing CO2 pipelines transport CO2 from CO2-dome
fields and plants processing gas from reservoirs with a high
proportion of CO2. ‘Captured’ CO2 may have a different
composition, and the type and proportion of the impurities
in the CO2 may have a significant effect on the susceptibility
of the pipeline to a running fracture, in addition to their
effect on hydraulic design [9].
In this paper, the issues surrounding fracture propagation
control in a CO2 pipeline are illustrated by two simple
design examples.
Fracture control
Fracture control is an important consideration in the
design of a pipeline. A fracture control plan for a pipeline
will consider two issues (see Fig.1):
• fracture initiation control; and
• fracture propagation control.
A propagating (or running) fracture will result in the loss of
many lengths of linepipe, and hence is undesirable. Fracture
propagation control is achieved by ensuring that the
toughness of the linepipe steel is sufficiently high to arrest
propagating fractures, and needs to be considered in
pipelines conveying gaseous fluids, two-phase fluids, densephase fluids, or liquids with high vapour pressures.
Propagating fractures are described as either brittle or
4th Quarter, 2008
283
2500
108°F
2000
pressure (psi )
measured
80°F
predicted
1500
94°F
1000
70°F
500
PY
0
0
Fig.2. Experimental and theoretical
decompression curves for CO2 (after
Maxey (1986)).
500
1000
1500
-1
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velocity (ft.s )
‘arrest pressure’ is greater than the ‘saturation pressure’
[14-18]. The ‘arrest pressure’ can be determined using part
of the TCM; the ‘saturation pressure’ can be determined
from a phase diagram (or a gas-decompression program),
given the initial pressure and temperature.
Linepipe specifications and pipeline design codes specify
toughness requirements in terms of the minimum shear
area as measured in a drop-weight tear test (DWTT) to
address the ‘upper shelf’ requirement [10-13]. Brittle fracture
propagation is not an issue in modern linepipe steel.
The transportation of
carbon dioxide by pipeline
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ductile: brittle propagating fractures are prevented by
ensuring that the linepipe steel is operating on the ‘upper
shelf’; ductile propagating fractures are prevented by
specifying a minimum toughness to ensure that a ductile
fracture will arrest or, if the required toughness is too high,
by using mechanical crack arrestors.
A ductile fracture will not propagate if there is insufficient
energy in the system to overcome the resistance to
propagation. The resistance to a running fracture can be
characterized by the Charpy-V notch (CVN) impact energy
of the linepipe steel, although the relationship between
CVN and fracture resistance becomes non-linear at high
impact energies (when the full-size impact energy exceeds
approximately 100J). The driving force for a running
fracture is the internal pressure: if the fluid in the pipeline
decompresses slowly, for example high pressures at low
decompression wave velocities (as is the case for CO2, see
Fig.2), then a higher toughness is required to arrest the
running fracture.
The Battelle two-curve model, widely used in fracturecontrol studies, expresses the resistance and driving force
in terms of the fracture and gas decompression wave
velocities [11, 12]. For CO2 it can be shown that fracture
propagation control can be conservatively simplified to
determining the toughness required to ensure that the
CO2 is transported in pipelines over long distances as a
dense-phase fluid, for operational and economic reasons.
The typical range of operating pressures and temperatures
of CO2 pipelines are 1,250psi (86.2bar) to 2,220 psi
(153bar), 40°F (4°C) to 100°F (38°C) [8, 19].
CO2 pipelines are susceptible to propagating ductile
fractures because the CO2 is transported in the dense
phase. It is a high vapour pressure liquid: at high pressures,
supercritical CO2 behaves as a liquid, and has a liquid-like
density, but it yields a very large volume of gas when its
pressure is lowered [20].
Fracture propagation control requires careful consideration
in the design of a CO2 pipeline, as do a number of other
issues such as hydraulics and corrosion control [8].
The transportation of CO2 by long-distance transmission
pipeline is an established technology, and one of the first –
the Canyon Reef Carriers pipeline system in West Texas –
was commissioned in 1972 [7]. There are now over 2,500km
of CO2 pipelines in the USA and Canada for enhanced oil
The Journal of Pipeline Engineering
97.5
99
284
100
CO2 & N2
100
pressure (bar)
95
90
125
75
10°C
25
0
100
200
300
400
500
600
-1
C
Fig.3. Theoretical decompression curves
for mixtures of CO2 and N2.
Decompression characteristics
of CO2 and fracture control
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recovery (EOR) projects [7], with other pipelines in the
Netherlands, Turkey, North Africa, and Norway (the latter,
the Snøhvit pipeline, being the world’s first offshore CO2
pipeline [21]). The source of the CO2 transported in these
pipeline is either natural or ‘anthropogenic’ (i.e. manmade), although none of the anthropogenic sources are
(yet) ‘captured’ CO2 from fossil-fuel power stations.
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velocity (m.s )
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The fact that long-distance, high-pressure CO2 pipelines
have been designed, constructed, and operated successfully
for many years indicates that the issues associated with the
design and operation of CO2 pipelines can be addressed.
Several CO2 pipelines in USA have mechanical crack
arrestors installed at regular intervals along their length,
because linepipe with a sufficiently high toughness was not
available when the pipelines were constructed [7, 8, 22, 23].
Fitting crack arrestors is expensive; retro-fitting them to
existing pipelines is even more so.
CO2 is normally transported as a dense-phase fluid.
Consider a rupture in a CO2 pipeline: the CO2 initially
decompresses rapidly as a liquid; the decompression path
then crosses the phase boundary, and the resulting twophase fluid decompresses much more slowly. Experimentally
determined decompression curves for CO2 are illustrated
in Fig.2. The discontinuities in the decompression curves
occur when the decompression path crosses the phase
boundary; the pressure at which it crosses the phase
boundary is the saturation pressure.
The renewed interest in CO2 pipelines, both new and the
change-of-use of existing pipelines from their current service
to CO2 service, means that it is informative to look again
at the issue of fracture propagation control in CO2 pipelines.
The decompression in a pipeline following a rupture can be
approximated as an isentropic process . GASDECOM is a
program for calculating the decompression curve for
mixtures of hydrocarbons [11, 12], based on the Benedict-
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In a wider context, it is also worth noting that there are
differences between the existing CO2 pipelines, which
were (with the odd exception) constructed for the purposes
of EOR, and the new CO2 pipelines that will be constructed
as part of the required transportation infrastructure for
CCS. Some of these differences are summarized in Table 1,
and the implications arising from these differences will
need to be addressed.
Carbon dioxide exhibits highly non-linear thermodynamic
properties, and it departs significantly from ideal gas
behaviour as the pressure increases. The critical point of
CO2 is at a pressure of 73.77bar (1,070psi) and a
temperature of 31°C (88°F). The presence of impurities,
such as methane or hydrogen, can have a significant effect
on the behaviour of the fluid [9, 18]. The decompression
characteristics of a fluid have a significant effect on the
toughness required to arrest a running ductile fracture, and
it is the decompression characteristics of CO2 that mean
that fracture propagation control requires careful
consideration.
4th Quarter, 2008
285
160
initial pressure (bar)
140
typical operating
conditions of
CO2 pipelines
120
100
high i.p.
80
60
low i.p.
40
low i.p.
high i.p
20
PY
99% CO2, 1% N2
0
0
Fig.4. The effect of initial conditions
on the saturation pressure of a
mixture of CO2 and N2.
10
20
. 30
40
50
60
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initial temperature (°C)
typical operating pressure and temperature range of CO2
pipelines, increasing the initial temperature and/or
decreasing the initial pressure will increase the saturation
pressure.
The saturation pressure is key to determining the toughness
required to arrest a propagating ductile fracture in a CO2
pipeline. Factors that increase the saturation pressure will
increase the arrest toughness.
Two examples
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Webb-Rubin-Starling (BWRS) equation of state, with
modified constants known to give accurate estimates of
isentropic decompression behaviour. Figure 2 compares
the measured decompression curves with theoretical
predictions using a modified version of GASDECOM. The
agreement between the experimental and theoretical
decompression curves is relatively good, and a reasonable
estimate of the saturation pressure, for given initial
conditions, can consequently be obtained assuming an
isentropic decompression and a phase boundary described
by the BWRS equation of state.
The presence of impurities has a significant effect on the
saturation pressure. Impurities such as hydrogen, nitrogen,
and methane will increase the saturation pressure [18].
Theoretical decompression curves for mixtures of CO2
and N2, from 0% N2 to 10% N2, are shown in Fig.3 [18],
illustrating a significant increase in the saturation pressure
as the proportion of N2 increases. This increase in the
saturation pressure will significantly increase the arrest
toughness (as discussed further below).
The initial pressure and temperature of the fluid also have
a significant effect on the saturation pressure. Theoretical
predictions of the saturation pressure for 100% CO2, and
99% CO2 and N2, for a range of initial pressures and
temperatures, are shown in Fig.4 [18]. Considering the
Considering the above, it is clear that the composition of
‘captured’ CO2 and the pipeline operating conditions
need to be well defined at the early stages of the design, so
that the implications for achieving fracture propagation
control can be addressed.
The issues associated with achieving fracture propagation
control in a CO2 pipeline are illustrated through two
examples:
• 24-in (609.6-mm) diameter pipeline with a design
pressure of 100bar; and
• 18-in (457.2-mm) diameter pipeline with a design
pressure of 180bar.
The above pipeline diameters and design pressures are
representative of what might be required to transport the
CO2 produced by a 1,600-MW coal-fired power station
over a distance of approximately 200km. A power station of
this size would produce something of the order of 8 million
ton/yr of CO2.
In both cases, the linepipe grade is taken to be API 5L X65
and the design factor is 0.72. The wall thicknesses are
286
The Journal of Pipeline Engineering
200
CH4
fracture velocity curves
150
decompression curves
18 in., 40 J
100
50
24 in., 50 J
X65, f = 0.72
10°C
0
0
100
200
300
400
500
600
-1
C
Fig.5. Theoretical decompression
curves for pure CO2 and pure CH4,
and fracture velocity curves for the
18- and 24-in pipelines.
All references to Charpy V-notch (CVN) impact energy in
the following refer to upper-shelf values (100% shear)
measured using full-size specimens tested at the minimum
pipeline operating temperature. In a linepipe specification,
the required impact energy may be expressed as either the
minimum of three test results, or the average of three. The
implications of this issue are not considered here.
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calculated accordingly and are, for the 24-in and 18-in
diameter pipelines respectively, 9.45mm and 12.76mm,
giving diameter to wall thickness ratios of 64.5 and 35.8.
700
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velocity (m.s )
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pressure (barg)
CO2
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In practice, a standard API 5L wall thickness would be
adopted and, depending upon the pipeline design code (for
example, PD 8010-1,2 : 2004 or ASME B31.4 [24, 25, 26]),
wall-thickness manufacturing tolerances may also need to
be considered. In addition, the design factor may not
dictate the minimum required wall thickness (which may
be governed by resistance to external interference in onshore
pipelines, or collapse and stability in offshore pipelines).
While, for simplicity, none of these issues are considered
here, their implication is that the wall thickness will tend to
be slightly (or significantly) greater than the minimum
required to satisfy the limit on the design factor. An
increase in the wall thickness is beneficial from a fracturecontrol perspective because it reduces the arrest toughness
(see below).
It is assumed that the linepipe steel is operating on the
upper shelf: 85% shear area in a DWTT at the minimum
pipeline operating temperature2. It is also assumed that the
pipelines are onshore, although this has little significance
for the purposes of these examples.
2 In some design codes and standards the requirements is expressed in
terms of the minimum design temperature, and in others in terms of the
minimum operating temperature. In most cases the difference is not
significant. It is more conservative to use the minimum design
temperature.
A methane (natural gas) pipeline
It is instructive to consider the requirements for fracture
propagation control if the above two pipelines were
transporting methane (CH4).
There are a number of different method that could be used
to estimated the required CVN impact energy to arrest a
running ductile fracture (the arrest toughness). The EPRG
recommendation for crack-arrest toughness for highstrength linepipe steels [13] would be the simplest approach,
while the Battelle short formula (SF) [11, 12], as
recommended in ASME B31.8 [27], is slightly more
complicated. The most-accurate, but also the mostcomplicated, approach, is the Battelle two-curve model
(TCM) [11, 12]. It is important to emphasize that the TCM
would not normally be used for a CH4 pipeline (and, in any
case, the SF is an approximation to the TCM). It is considered
here because its use illustrates the implications of the
different decompression curves for CH4 and CO2.
Table 2 gives the required toughness for the two pipelines
calculated using the EPRG recommendations, the SF and
the TCM. The SF is conservative with respect to the TCM,
4th Quarter, 2008
287
E xistin g C O 2 p ip e lin e s
N e w C O 2 p ip e lin e s
CCS
EO R
Table 1.
Differences
between existing
and new CO2
pipelines.
im pur itie s, de pe n din g on th e captur e m e th od
r e m ote , un populate d ar e as
populate d ar e as
' static' de m an d
f luctuation de m an d (due to load f actor s)
h ig h e r th r oug h put ?
18 in ., 18 0 b a r
EPRG
40 J
40 J
SF
53 J
T CM
50 J
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2 4 in ., 10 0 b a r
53 J
40 J
the initial pressure increases the arrest toughness. The
decompression curve is only part of the picture; it depends
only on the initial pressure and temperature and the fluid
composition. The fracture-velocity curves illustrate the
effect of pipeline geometry and grade. The 18-in diameter
pipeline has a higher resistance to a ductile fracture than
the 24-in pipeline because the diameter to wall thickness
ratio is smaller (for the same toughness, at any given
fracture velocity, the required driving pressure is higher)3.
The higher fracture resistance of the 18-in pipeline more
than offsets the higher driving force implied by the
decompression curve. Consequently, a lower arrest
toughness is predicted for the 18-in, 180-bar, pipeline than
for the 24-in, 100-bar, pipeline.
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as would be expected. The EPRG recommendations give
the lowest required toughness. The EPRG
recommendations for X70 and below are based on 0.75
times the AISI formula, and take into account the statistical
distribution of the CVN impact energy in an actual linepipe
supply (mid-1990s data). The minimum toughness specified
by the EPRG recommendations ensures that 50% of the
linepipe will meet the required toughness. The SF and
TCM are simply formulae for calculating the arrest
toughness. The results of the three different criteria are
broadly comparable. Modern linepipe would easily exceed
the required toughness.
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Table 2.
Required full-size
CVN impact
energy for a
CH4 pipeline.
n e ar ly pur e CO 2 f r om dom e f ie lds
Further insight into the underlying behaviour is given in
the results of the TCM. Figure 5 shows the theoretical
decompression curves for pure methane, based on an
initial temperature of 10°C and initial pressures of 100 and
180bar, and the fracture velocity curves for the 18 and 24in diameter pipelines, based on the minimum arrest
toughness (and hence the respective decompression and
fracture velocity curves intersect at a tangent). The
decompression curves are characteristic of the
decompression of a gaseous fluid in the gaseous phase. The
decompression curve for an initial pressure of 180bar is
more severe than that for an initial pressure of 100bar (at
any given decompression wave velocity, the decompression
pressure is higher). All other factors being equal, increasing
3 The smaller diameter to wall thickness ratio has a second effect. At any
given decompression wave velocity, the hoop stress in the 18-in pipeline
is lower than that in the 24-in pipeline, even though the pressure is
higher.
The following general trends for a CH4 pipeline can be
identified:
• the higher the initial pressure, the more severe is the
decompression curve;
• the lower the initial temperature, the more severe is
the decompression curve;
• the smaller the diameter to wall thickness ratio, the
lower is the arrest toughness; and
• the lower the design factor, the lower is the arrest
toughness.
A carbon dioxide pipeline
Consider now the same 18-in and 24-in diameter pipelines,
but transporting carbon dioxide (CO2) rather than methane.
288
The Journal of Pipeline Engineering
200
180
160
180 bar, 10°C
pressure (bar)
140
120
100
100 bar, 10°C
80
60
40
CO2 phase boundary
0
-20
-10
0
10
20
30
40
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temperature (°C)
PY
20
C
pressure of 100bar (the estimated saturation pressures are
approximately 35 and 39bar, respectively). The
decompression curve for an initial pressure of 180bar is less
severe than that for an initial pressure of 100bar – the
opposite of what was observed above.
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Figure 5 shows the theoretical decompression curves for
pure carbon dioxide, based on an initial temperature of
10°C and initial pressures of 100 and 180bar. The
decompression curves are very different from those of
methane decompressing from the same initial conditions,
and are characteristic of the decompression of a densephase fluid. The discontinuity, or plateau, in the
decompression curve occurs when the decompression path
crosses from the single-phase region (liquid) into the twophase region (liquid-gas). The marked difference between
the decompression curves for methane and carbon dioxide,
illustrated in Fig.5, clearly demonstrates why it is only
necessary to consider the saturation pressure when
determining the required arrest toughness in a CO2
pipeline. The full decompression curve is not required.
Fig.6. Isentropic decompression paths.
The isentropic decompression paths corresponding to the
decompression curves are shown in Fig.6. The saturation
pressure is the pressure at which the decompression path
intersects the phase boundary. The saturation pressure for
an initial pressure of 180bar is lower than that for an initial
car bon dioxide (CO 2)
In the case of a CO2 pipeline, the toughness required to
arrest a running ductile fracture can be estimated through
consideration of the arrest pressure and the saturation
pressure (as previously discussed). The saturation pressure
follows from the isentropic decompression path, as indicated
in Fig.6, and its calculation is simpler than the calculation
of the decompression curve, and similarly the calculation
of the arrest pressure is simpler than the calculation of the
fracture-velocity curve [17].
Table 3 gives the required toughness for the two pipelines
calculated in this manner (the TCM would give identical
results). Comparing the results for a CO2 and a CH4
pipeline, the arrest toughness in the 24-in pipeline is
slightly higher (although not significantly) when the contents
2 4 in ., 10 0 b a r
18 in ., 18 0 b a r
53 J
12 J (9 J)
Table 3.
Required fullsize CVN impact
energy for a
CO2 pipeline
and a CH4
pipeline.
Note: The arrest
toughness for
the 18-in. diameter CO2 pipeline is quoted for an initial pressure of 100bar and, in brackets, an initial pressure of 180 bar.
m e th an e (CH4)
50 J
40 J
4th Quarter, 2008
289
CVN impact energy (J)
200
180
24 in., 100 bar
160
18 in., 180 bar
140
120
100
80
60
40
20
X65, f = 0.72
30
PY
0
Fig.7. Effect of saturation pressure on
the CVN impact energy required to
achieve fracture propagation control
in the 18- and 24-in pipelines.
40
50
60
70
80
90
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hoop stress at the saturation pressure in the case of the 24in pipeline also has implications for the significance of the
effect of impurities on the arrest pressure (see below).
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are CO2, and higher in the 18-in pipeline when the
contents are CH4. The differences in the arrest toughnesses
follow from the decompression characteristics of the two
fluids. The results for the 18-in pipeline are, in fact,
somewhat artificial because it is likely that there would be
insufficient energy in the system to sustain a running
fracture at the saturation pressure, because the hoop stress
is low (the hoop stress at the saturation pressure is less than
20% SMYS). It is important to note that the arrest toughness
for the 18-in pipeline is not determined by the design
pressure; in Table 3 it is assumed that the minimum
operating pressure is 100bar, and it is this minimum
pressure that determines the required toughness (see below).
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saturation pressure (bar)
For CH4, the higher initial pressure results in a moresevere decompression curve; conversely, for CO2 pipeline,
it is the lower initial pressure. From this observation, it
follows that fracture propagation control is easier to achieve
in a CO2 pipeline that has a high design pressure, and this
is illustrated in the decompression paths given in Fig.6. The
difference between the saturation pressures for the two
initial pressures is small: it is less than 10% of the difference
between the initial pressures. The design factor for the 18and 24-in pipelines is 0.72, i.e. the hoop stress is 72%
SMYS. The driving force for a running fracture is directly
related to the hoop stress: for an initial pressure of 180bar,
the saturation pressure is approximately 0.2 times the
initial pressure, and the hoop stress is less than 20% SMYS.
For an initial pressure of 100bar, the saturation pressure is
approximately 0.4 times the initial pressure, and the hoop
stress is approximately 30% SMYS. Consequently, a lower
arrest toughness is predicted for the 18-in, 180-bar pipeline
than the 24-in, 100-bar pipeline (see Table 3). The higher
Having established the arrest toughness for the 18- and 24in diameter pipelines, the sensitivity of this toughness to
changes in the wall thickness and the saturation pressure
can be investigated.
The arrest toughness increases and tends to infinity as the
saturation pressure increases, see Fig.7. The limiting
saturation pressure, above which mechanical crack arrestors
would be required, depends on the diameter, wall thickness,
and grade, and is the flow-stress-dependent arrest pressure
[17]. Increasing the initial temperature and/or decreasing
the initial pressure would increase the saturation pressure.
The addition of impurities would change the saturation
pressure, either increasing or decreasing it [18]. The increase
in the arrest toughness is greater for the 24-in pipeline than
for the 18-in pipeline because the saturation pressure at the
assumed initial conditions is closer to the flow-stressdependent arrest pressure.
The arrest toughness decreases as the wall thickness
increases, as shown in Fig.8. Increasing the wall thickness
is equivalent to reducing the design factor, given that the
diameter, grade, and design pressure remain unchanged.
The arrest toughness increases and tends to infinity as the
wall thickness decreases. The limiting wall thickness, below
which mechanical crack arrestors would be required,
depends on the saturation pressure, diameter, and grade (as
above, it is related to the flow-stress-dependent condition).
It may or may not correspond to a realistic design case,
The Journal of Pipeline Engineering
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given that pipeline design codes place a limit on the design
factor (for example, 0.72).
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The trends in the results in Figs 7 and 8 show that fracture
propagation control is achievable in both the 18- and 24-in
diameter pipelines, but that the 24-in case is more sensitive
to changes in the design conditions. Figure 5 illustrates why
fracture propagation control is an issue in CO2 pipelines,
but also that it does not always follow that it is more of an
issue than in CH4 pipelines – it depends on the initial
conditions and the composition.
Considering the 24-in pipeline, the estimated saturation
pressure for initial conditions of 100 bar and 10°C is
approximately 39bar, and the arrest toughness is
approximately 53J. A 5-bar increase in the saturation
pressure increases the arrest toughness to approximately
89J, while a 10-bar increase means that mechanical crack
arrestors are required (irrespective of the toughness of the
linepipe steel), as can be seen in Fig.8. The design is
constrained by the requirements for fracture propagation
control, not the design factor. Increasing the wall thickness
to 12.4mm (giving a design factor of 0.55) reduces the
arrest toughness to approximately 53J. To illustrate the
effect of impurities on the saturation pressure, for initial
conditions of 100bar and 10°C, the addition of 1% nitrogen
(i.e. a mixture of 99% CO2 and 1% N2) would increase the
saturation pressure by 5bar, and the addition of 2.5%
would increase it by approximately 13bar.
The following general trends for a CO2 pipeline can be
identified:
Fig.8. Effect of wall thickness on the
CVN impact energy required to
achieve fracture propagation control
in the 18- and 24-in pipelines.
• the lower the initial pressure, the higher the arrest
toughness;
• the higher the initial temperature, the higher the
arrest toughness;
• the smaller the diameter to wall thickness ratio, the
lower the arrest toughness; and
• the lower the design factor, the lower the arrest
toughness.
It also follows that there are some combinations of design
parameters (diameter, wall thickness grade, and design
pressure) for which it is not possible to achieve facture
propagation control without the use of mechanical crack
arrestors. Mechanical crack arrestors would be needed if
the required toughness is too high (i.e. linepipe of the
required toughness is not available or too expensive), or if
it is simply impossible to arrest a fracture irrespective of the
toughness. There is a second consideration when the
required toughness is high. The existing models may
overestimate the ductile fracture resistance implied by very
high CVN impact energies; however, simple modifications
to the design (such as increasing the wall thickness) will also
solve the problem. Consequently, it is important to consider
fracture propagation control early in design, before difficultto-reverse decisions have been made.
The effect of the initial pressure and temperature on the
arrest toughness in a carbon dioxide pipeline are the exact
opposite of what is observed in a methane pipeline (and
indeed in most, if not all, natural gas pipelines conveying
lean or rich gas), and this has one very significant implication,
as follows. When developing a facture control plan for a
4th Quarter, 2008
291
• Fracture propagation control in a CO2 pipeline can
be achieved through consideration of the arrest
pressure and the saturation pressure. The required
calculations are therefore much simpler than those
required for the two-curve model.
• Impurities such as methane, nitrogen and hydrogen,
will increase the saturation pressure and hence the
toughness required to arrest a ductile fracture.
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• The limiting case for fracture propagation control
in a CO2 pipeline is the lowest pressure and highest
temperature within the operating envelope.
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• In some situations, the requirement for fracture
propagation control will dictate the design of a CO2
pipeline.
References
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Through the examples of the 18-in, 180-bar, and 24-in,
100-bar, pipelines it has been shown that fracture
propagation control in a CO2 pipeline can be addressed
relatively simply. There are significant differences between
CO2 and CH4 pipelines that mean that fracture propagation
control is more of an issue in a CO2 pipeline, but it does
not always follow that the arrest toughness will be higher in
the CO2 pipeline than for an equivalent CH4 pipeline.
The issue of fracture propagation in CO2 pipelines tends
to favour pipelines with a small diameter to wall thickness
ratio and large wall thickness (the two are related), low
grade, low design factor, and a high design pressure, or
some combination thereof. The availability of modern,
high-toughness linepipe steel reduces the significance of
some of these trends.
to arrest a ductile fracture may be very sensitive to
small changes in the design parameters (such as
pipeline geometry or fluid composition).
Nevertheless, provided that fracture control is
considered early in design, any constraints on the
design can be identified and, in principle, resolved
without too much difficulty.
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natural gas pipeline, the limiting condition corresponds to
the maximum operating pressure and the minimum
operating temperature. The maximum operating pressure
will be less than or equal to the design pressure, and it is
conservative to use the design pressure. In other words, the
limiting condition is well defined. This is not the case for
a carbon dioxide pipeline. When developing a facture
control plan for a carbon dioxide pipeline, the limiting
condition corresponds to the minimum operating pressure
and the maximum operating temperature. The minimum
operating pressure may not be well defined. It is also a
conceptual issue because, in design, it is normally the
maximum pressure that defines the worst case.
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The information required to assess the significance of
fracture propagation control will be available at the
conceptual stage of design (including pipeline diameter,
operating conditions, and composition), and the
calculations are relatively straightforward. Therefore, it will
be simple to define a design envelope in which fracture
propagation control can be achieved without the use of
mechanical crack arrestors or, conversely, identify this as an
issue early in design. This would be useful in defining the
specification for the CO2; for instance, is it necessary to
remove impurities (and if so, to what level) when the CO2
is captured?
There are a number of underlying issues that have not been
considered in detail here, including the range of applicability
of the underlying models, the effect of impurities that
might be found in ‘typical’ captured CO2, and experimental
validation of the methods, but the principles have been
demonstrated.
Conclusions
• Fracture propagation control is an issue for a CO2
pipeline, but it is readily addressed using the methods
that the pipeline industry has developed over the
years. Some care is required because the trends
observed in CO2 pipelines are not the same as those
in natural gas pipelines, and the required toughness
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report summary for policymakers. An assessment of the
Intergovernmental Panel on Climate Change, 4th Assessment
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2. T.Barker et al., 2007. Summary for policy makers, Working
Group III contribution to the Intergovernmental Panel on
Climate Change 4th Assessment Report Climate Change
2007: Mitigation of Climate Change, IPCC WG III 4AR,
Intergovernmental Panel on Climate Change, May.
3. N.Stern, 2007. The economics of climate change: The Stern
review. Cambridge University Press, Cambridge (also HM
Treasury, 2006 www.hm-treasury.gov.uk).
4. C.Philibert, 2007. Technology penetration and capital stock
turnover: lessons from IEA scenario analysis. International
Energy Agency, Organization for Economic Cooperation
and Development, COM/ENV/EPOC/IEA/SLT(2007)4,
May.
5. R.Harrabin, 2008. Germany leads ‘clean coal’ pilot, BBC, 3
September. news.bbc.co.uk/1/hi/sci/tech/7584151.stm
6. www.vattenfall.com/www/co2_en/co2_en/index.jsp
7. R.Doctor, A.Palmer, D.Coleman, J.Davison, C.Hendriks,
O.Kaarstad, M.Ozaki, and M.Austell, 2005. Chapter 4:
Transport of CO2. IPCC Special Report on Carbon Dioxide
Capture and Storage, R.Pichs-Madruga, S.Timashev, Eds.,
Intergovernmental Panel on Climate Change, Cambridge
University Press, Cambridge.
8. M.Mohitpour, H.Golshan, and A.Murray, 2000. Pipeline
design and construction: a practical approach. ASME Press,
New York.
9. P.N.Seevam, J.M.Race, M.J.Downie, and P.Hopkins, 2008.
Transporting the next generation of CO2 for carbon capture
and storage: the impact of impurities on supercritical CO2
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19. C.B.Farris, 1983. Unusual design factors for supercritical
CO2 pipelines. Energy Process, 3, 3, September, pp150-158.
20. M.W.Wadseley and A.B.Rothwell, 1997. Fracture control
for pipelines carrying other gases – HVPL, CO2 and others.
Paper 9, Proc. International Seminar on Fracture Control in
Gas Pipelines, WTIA/APIA/CRC-MWJ Seminar, Sydney,
Australia, 3 June.
21. G.Koeijer, J.H.Borch, J.Jakobsen, and A.Hafner, 2007.
Construction of a CO2 pipeline test rig for R&D and
operator training. Transmission of CO2, H2, and biogas:
exploring new uses for natural gas pipelines conference,
organized by Global Pipeline Monthly and Clarion Technical
Conferences, Amsterdam, Netherlands, May.
22. D.L.Marsili and G.R.Stevik, 1990. Reducing the risk of
ductile fracture on the Canyon Reef Carriers CO2 pipeline.
SPE20646, 65th Annual Technical Conference and
Exhibition of the Society of Petroleum Engineers, New
Orleans, USA, September 23-26.
23. D.W.Barry, 1985. Design of Cortez CO2 system detailed. Oil
and Gas Journal, 1985, pp96-102.
24. Anon., 2004. Code of practice for pipelines - Part 1: Steel
pipelines on land, PD 8010-1: 2004, British Standards
Institution, London, UK.
25. Anon., 2004. Code of practice for pipelines - Part 2: Subsea
pipelines, PD 8010-2: 2004, British Standards Institution,
London, UK.
26. Anon., 2002. Pipeline transportation systems for liquid
hydrocarbons and other liquids. ASME Code for pressure
piping, B31, ASME B31.4 – 2002 Edition (Revision of
ASME B31.4 – 1998), American Society of Mechanical
Engineers, New York, NY, USA.
27. Anon., 2003. Gas transmission and distribution systems,
ASME B31.8-2003, American Society of Mechanical
Engineers, New York, NY, USA, March.
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11.
pipelines. Paper IPC2008-64063, Proc. 7th International
Pipeline Conference, Calgary, Canada, September 30 October 03.
Anon., 2000. Specification for linepipe. Exploration and
Production Department, API Specification 5L, American
Petroleum Institute, 42nd Edition.
R.J.Eiber, T.A.Bubenik, and W.A.Maxey, 1993. Fracture
control technology for natural gas pipelines. Final Report to
Linepipe Research Supervisory Committee of the Pipeline
Research Committee of the American Gas Association,
Project PR-3-9113, NG-18 Report No. 208, Battelle,
December.
R.J.Eiber and T.A.Bubenik, 1993. Fracture control plan
methodology. Paper 8, 8th Symposium on Linepipe Research,
Pipeline Research Committee of the American Gas
Association, Catalogue No. L51680, Houston, Texas, USA,
September.
G.Re, V.Pistone, G.Vogt, G.Demofonti, and D.G.Jones,
1993. EPRG Recommendation for crack arrest toughness for
high strength linepipe steels. Paper 2, Proc. 8th Symposium
on Linepipe Research, American Gas Association, Houston,
Texas, 26-29 September 1993, pp. 2-1-2-13 (also 3R
International, 34 Jahrgang, Heft 10-11/1995, p. 607-611).
G.G.King, 1981. Design of carbon dioxide pipelines. EnergySources Technology Conference and Exhibition, Houston,
Texas, USA, January 18-22.
W.A.Maxey, 1986. Long shear fractures in CO2 lines
controlled by regulating saturation, arrest pressures. Oil and
Gas Journal, pp 44-46.
A.B.Rothwell, 1988. Fracture control in natural gas and
CO2 pipelines. Conference on Microalloyed HSLA Steels,
ASM International, pp95-108.
A.Cosham and R.J.Eiber, 2007. Fracture control in carbon
dioxide pipelines. Transmission of CO2, H2, and biogas:
exploring new uses for natural gas pipelines conference,
organized by Global Pipeline Monthly and Clarion Technical
Conferences, Amsterdam, Netherlands, May.
A.Cosham and R.J.Eiber, 2008. Fracture control in carbon
dioxide pipelines – the effect of impurities. Paper IPC200864346, Proc.7th International Pipeline Conference, Calgary,
Canada, September 30 - October 03.
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10.
The Journal of Pipeline Engineering
Editorial (continued from page 236)
the running of more than one type of pig in the same
section, so that the total actual length inspected was around
4776km (13% of the inventory). Overall, there is no
evidence to show that the ageing of the pipeline system
poses any greater level of risk, and CONCAWE concludes
that the development and introduction of new techniques,
such as internal inspection using intelligent pigs, holds out
the prospect that pipelines can continue operating reliably
for the foreseeable future. Continued monitoring of the
CONCAWE pipeline performance statistics will be
necessary to confirm the position.
Subscriber on-line access
W
E ARE PLEASED to confirm that on-line access for
subscribers to the Journal is now operational at
www.j-pipe-eng.com, and all subscribers should have
received a personal letter giving them the user names and
passwords required. Please contact the publishers (see page
234) in case of difficulty or if the letter has not arrived. The
site contains both this current issue, and all previous issues,
in pdf format; issues can be downloaded in their entirety as
a single pdf, or the individual papers can be downloaded
separately. We hope that this resource proves helpful to
subscribers, and enhances the reputation and influence of
the Journal.
We are shortly also to introduce on the site an automated
process for paper submission, in which authors will be able
to upload abstracts and receive acceptance or rejection
messages rapidly and efficiently. The refereeing of papers
will be managed through this procedure, and we hope that
its introduction will improve the effectiveness and speed
with which such matters are currently implemented.
293
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4th Quarter, 2008
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The Journal of Pipeline Engineering
The Pigging Products
and Services Association
An international trade association
serving the pipeline industry
PY
Our aims are to promote the knowledge of pigging and its related products and
services by providing a channel of communication between the members
themselves, and with users and other interested parties.
Services include:
Free technical information service available to all
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Pigging seminars – next one
19th
November
2008
Aberdeen
18
November,
2009,
Aberdeen
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Sourcing of pigs and pigging services
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Complimentary Buyers Guide and Directory of Members
PPSA newsletter, “Pigging Industry News”
PPSA’s book “An Introduction to Pipeline Pigging”
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Training courses
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PPSA web site – www.ppsa-online.com
Want to join?
Full members - pigging manufacturers and service providers
Associate members - pipeline operators, suppliers and allied industries
Individual members - anyone with an interest in pigging
To find out more visit our web site www.ppsa-online.com
or contact the Secretary at [email protected]
Pigging Products and Services Association
P O Box 2, Stroud, Glos., GL6 8YB, UK
Telephone: +44 (0) 1285 760597
Facsimile: +44 (0) 1285 760470
Email: [email protected]
www.ppsa-online.com
4th Quarter, 2008
295
Rehabilitation of corroded steel
pipelines with epoxy repair
systems
by H S Costa-Mattos1, J M L Reis*1, R F Sampaio1, and V A Perrut2
1Programa de Pós-Graduação em Engenharia Mecânica, Laboratório de Mecânica Teórica e
Aplicada, Universidade Federal Fluminense, Niterói, Brazil
2 Centro de Pesquisas e Desenvolvimento da Petrobrás – CENPES, Ilha do Fundão, Rio de
Janeiro, Brazil
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HE REHABILITATION OF corroded pipelines using epoxy repair systems is becoming a well-accepted
engineering practice and an interesting alternative to the classic repair methods for metallic pipes in
the oil industry, both saving time and allowing safer operation. In these repair systems, a pipe segment is
reinforced by wrapping it with concentric coils of composite material after the application of epoxy filler
at the corrosion defect. The technical specification ISO 24817 [1] gives requirements and recommendations
for the qualification and design, installation, testing, and inspection for the external application of composite
repairs to corroded or damaged pipework. Nevertheless, so far, composite repair systems are not totally
effective for through-thickness corrosion defects because generally they cannot avoid leaking. The present
paper presents a simple and systematic methodology for repairing leaking corrosion defects in metallic
pipelines with epoxy resins. The focus is to ensure an adequate application of the epoxy filler such that the
pipe will not leak after the repair. Such a procedure can be associated with a composite sleeve that will
ensure a satisfactory level of structural integrity. Examples of repair systems in different damage situations
are presented and analysed, showing the practical use of the proposed methodology.
SA
HE REHABILITATION OF corroded pipelines with
epoxy repair systems is becoming a well-accepted
engineering practice and an interesting alternative to the
classic repair methods for metallic pipes, mainly in the oil
industry, saving time and allowing safer operation [2].
Since offshore platforms are hydrocarbon atmospheres,
any repair method that uses equipment that produces heat
and sparkling is forbidden: type B sleeves, leak clamps, and
hot tapping are therefore excluded from the list of allowable
repair methods. According to Ref.2, only Bolt-On Clamps
with seals are allowed for leak repairs on offshore platforms.
Corroded pipelines can be repaired or reinforced with a
composite sleeve system, in which a pipe segment is
reinforced by wrapping it with concentric coils of composite
material after the application of epoxy filler at the corrosion
defect. Generally, the composite sleeve is not only used as
repair system itself (mainly to avoid or to restrain the
*Author’s contact information:
tel: +55 21 2629 5565
email: [email protected]
propagation of internal flaws), but also as a complementary
procedure to enhance the reliability of weldments,
eliminating the necessity of heat treatment (in the welding
operation there is always a possibility of metallurgical
changes in the parent metal in the vicinity of the weld).
Technical specification ISO 24817 [1] gives requirements
and recommendations for the qualification and design,
installation, testing, and inspection of the external
application of composite repairs to corroded or damaged
pipework. Nevertheless, so far, composite repair systems
are not effective for through-thickness corrosion defects
because generally they cannot avoid leaking.
The present paper presents a very simple and systematic
methodology for repairing leaking corrosion defects in
metallic pipelines with epoxy resins. The focus is to ensure
that the pipe will not leak after a repair, and such a
procedure can be associated with a composite sleeve that
will further ensure a satisfactory level of structural integrity.
The study is focused on what ISO 24817/TS defines as a
defect type B – where the substrate requires structural
reinforcement and sealing of through-wall defects (leaks) –
and all three classes of repair, although mainly Class 3
The Journal of Pipeline Engineering
Epoxy resins
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The main motivation for the study presented on this paper
is leaking defects found in the produced water pipelines
used in offshore oil platforms. The damages derived from
corrosion process in produced water pipelines in platforms
cause very important economic losses because the operation
must be stopped while the repair is being performed
(Fig.1). Although the operation pressure of these pipelines
is not very high, the water temperature is between 60oC and
90oC, which can be a major shortcoming if polymeric
materials are used as repair systems.
Examples of repair systems in different damage situations
are presented and analysed, illustrating the possibilities of
practical use of the proposed methodology.
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which is appropriate for systems transporting produced
fluids.
Fig.1. Corrosion damage in
produced-water pipelines.
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The objective is to ensure the pipe will not leak under the
operational pressure and temperature after the repair. The
maximum time allowed between the beginning of the
repair and the return to operation is 75mins. Hydrostatic
tests were carried out with water at room temperature and
at 80oC to validate the epoxy repair systems that are applied
in offshore produced water pipelines, and the experimental
tests were aimed at analysing the performance of different
epoxy resins in real offshore platform repair situations.
Two different commercial fast-curing epoxy resins were
analysed: both are two-component systems consisting of a
base and solidifier. The first one (System A) is designed for
leak repairs on tanks and pipes, as well as for other
emergency applications, and is based on a silicon steel alloy
blended within high molecular weight polymers and
oligomers. It is partly cured (machining and/or light loading)
after 35mins at 25oC and is fully cured after 1hr at this
temperature. Further technical data for System A includes:
•
•
•
•
flexural strength:
tensile shear on steel:
compressive strength:
heat-distortion temperature:
59.3MPa
17.2MPa
55.8MPa
51oC
The second system (System B) is also a polymer-based
Fig.2. Types of failure.
4th Quarter, 2008
297
system specially developed for repairs, and consisting of a
mixture of epoxy resin and aluminium powder. It is partly
cured (machining and/or light loading) after 18mins at
25oC and is fully cured after 40mins at this temperature.
Further technical data for System B includes:
•
•
•
•
flexural strength:
tensile shear on steel:
compressive strength:
heat-distortion temperature:
67MPa
19MPa
104MPa
120oC
Since the heat-distortion temperature for System A is very
low (51oC) it was only tested at room temperature. The
hydrostatic tests with pipes repaired with System 2 were
performed at two different temperatures: room temperature
and 80oC.
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Fig.3. Defect sizing.
Proposed repair procedure
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Since epoxy repair systems do not necessarily avoid leakage,
even if a composite sleeve is used, the following methodology
was created to improve the effectiveness of such repair
systems in the produced-water pipelines used on offshore
oil platforms. The experimental set-up in the laboratory
was designed to approximate a real repair operation, where
the resin has to be applied in field conditions (which affect
the quality of the resulting epoxy repair). To optimize the
process, avoiding stopping production for a long period, a
maximum repair time of 75mins is suggested from the
beginning of the repair procedure to the return to operation.
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Methodology for the
epoxy repair system
Defect sizing
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In a repair of a pipeline with through-thickness defects with
epoxy resins, two mechanisms of brutal failure can occur
when pressure is applied, see Fig.2. The experimental
procedure was designed to minimize the possibility of such
failure modes.
Defect sizing is important in order to define the limits for
an effective use of the repair procedure. The dimensions of
the defect should be determined by the smallest ellipse,
with one axis parallel to the axis of the pipe, which fully
contains the area of the flaw (see Fig.3). The maximum
allowable defect size for the proposed repair procedure is
defined by the semi-major axis of the ellipse, a, which is
given by:
⎧R ⎫
amax ≤ max ⎨ , t⎬
⎩10 ⎭
(1)
where R is the inner radius of the pipe and t is the wall
thickness. This means that the maximum allowable
dimension for the semi-major axis a is the greatest value of
either the wall thickness t or 1/10 of the inner radius R.
The repair methodology can be described as follows:
Surface preparation
Surface treatment often involves chemical reactions which
produce surface modifications on adherends, or mechanical
procedures, which improve adhesion by increasing
mechanical interlocking of the adhesive to the adherend.
In this way, the primary objective of a surface treatment is
to increase the surface energy of the adherend as much as
possible, and/or improve the contact between the adhesive
and the adherend by increasing the contact area. Increasing
roughness, or an increase in surface area, has been shown
to give good results in improving adhesion. Subsequently,
a relationship exists between good adhesion and bond
durability.
In order to obtain these properties, sanding with 120 or
150 sandpaper was used to achieve a white metal appearance
and to remove some of the existing oxide layer in the
substrate. A final rinse with solvent was made to provide a
surface free of oil, grease, and dirt surface. After this, the
adhesive was mixed according to the manufacture’s
procedure, and applied to the pipe. It is important to point
out that, in a real situation, the pipe may be so corroded
that sandpaper should be used with extreme care (see
Fig.4). Also, since offshore platforms are hydrocarbon
atmospheres, any method of mechanically roughening the
surface that may produce heat or sparking (such as
sandblasting, cutting, grinding), is unacceptable.
The Journal of Pipeline Engineering
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An elliptically-shaped rubber cap must be used to avoid
resin spillage inside the pipe. Since the rubber is very
deformable, it is easy to introduce the cap into the pipe, and
it is maintained in position using a simple system of nylon
strings.
wall, and with average dimension twice the size of the defect
(see Fig.5). For through-thickness defects with the semimajor axis less than or equal to 5mm, it may be difficult to
introduce the rubber cap, and a metallic wedge should be
used instead (Fig.6). The following steps in the repair
procedure are exactly the same if either the wedge or the cap
is used.
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Introduction of an internal rubber
cap to avoid spillage of epoxy resin
Fig.4. Surface preparation.
The epoxy adhesive layer applied externally should cover an
area approximately five times that of the ellipse (Fig.7), and
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The cap should allow formation of and internal layer of
adhesive with approximately the same thickness as the pipe
Application of the first external layer of epoxy adhesive
Fig.5. Rubber cap to avoid
adhesive spillage.
Fig.6. Metallic wedge for
smaller defects.
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299
Smooth
Finishing
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Non-Smooth
Finishing
Fig.7. External epoxy adhesive layer.
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corrosion defect is very complex, but if the size of the defect
is limited, a rough estimate of the magnitude of the
permanent deformation close to the defect can be
performed. The term on the left-hand side of Eqn 2 is the
maximum stress in a thin-walled infinite plate with an
elliptical defect with semi axes a and b subjected to traction
of a uniform force per unit area S = PR/t (see Fig.8). The
stress concentration factor in this case is Kt = ( 1 + 2 ab ) .
The criterion in Ref.2 states that a permanent deformation
close to the defect in a pipe can be neglected when KtS is less
than the yield stress σy. For closed-ended pipes, the yield
stress should be adjusted by a factor of 1.115 [3].
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the thickness of this first layer must be at least equal to the
thickness of the pipe; the layer should also have a smooth
boundary for improved performance. After application, an
initial epoxy polymerization time is allowed according to
the manufacturer’s instructions (the maximum desirable
being 20mins).
Application of the second layer of epoxy adhesive
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a ⎞ ⎛ PR ⎞
⎛
⎜1 + 2 ⎟ ⎜ ⎟ ≥ σ y
b ⎠⎝ t ⎠
⎝
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A second layer of adhesive must be applied without sanding.
The repair procedure is considered adequate when:
(2)
where a and b are, respectively, the semi-major and the semiminor axis of the ellipse, R is the inner radius of the pipe,
t the wall thickness and σy the yield stress of the pipe
material.
The stress distribution in a general through-thickness
Fig.8. Equivalent system.
If this condition is verified, immediately after the application
of the second epoxy layer a rubber sheet should be applied
over the repair around the perimeter and a simple metallic
clamp, similar to those used for garden hoses, can be
attached (Fig.9). The clamp is not used to improve the
structural integrity of the pipe, but to prevent the two
possible major failure mechanisms of the adhesive repair
shown in Fig.2, mainly at the beginning of operation when
the resin may not be fully cured.
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Epoxy
Adhesive
Pipeline with throughthickness defect
Rubber Cap to avoid
adhesive spilling
Fig.9 (left). Complete repair system.
Rubber Band
Fig.10 (below). Test apparatus.
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Metallic Clamp
through-wall defect in the pipe, and not on throughthickness defects.
An alternative method for defining the necessary thickness
of composite material to ensure both the safety of repairs
under operational conditions and the lifetime extension
under operational conditions, can be found in Ref.4. This
method, although simple, is acceptable for different failure
mechanisms, including plasticity, fatigue, and fracture.
The method meets the most widely-used criteria for the
assessment of corrosion defects under internal pressure
loading – a family of criteria described in [5] as the effectivearea methods. These include the ASME B31G criterion
and the RSTRENG 0.85 criterion (also known as the
modified B31G criterion). Nevertheless, this study is mainly
focused on metal loss due to corrosion treated as a part-
• specimen 1: 2-in diameter Schedule 80 pipe with a
3-mm diameter circular hole
• specimen 2: 2-in diameter Schedule 80 pipe with a
10-mm diameter circular hole
• specimen 3: 12-in diameter Schedule 20 pipe,
1300mm long, with a 10-mm diameter circular hole
• specimen 4: 12-in diameter Schedule 20 pipe,
1300mm long, with a 30-mm diameter circular hole
• specimen 5: 3.5-in diameter Schedule 20 pipe,
1000mm long, taken from the field with real
corrosion defects (see Fig.4).
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Under these circumstances, the proposed procedure is
effective as a repair system by itself. Nevertheless, this
procedure is intended to be used together with a composite
sleeve (which is normalized, for instance, by Ref.1). The
main objective is to ensure that composite repairs of
leaking defects when qualified, designed, installed, and
inspected using ISO/TS 24817 and the proposed procedure,
will meet the specified performance requirements. The
suggestion is to apply the epoxy resin as described in this
paper and then apply a composite material sleeve, of a
normalized thickness, to restrain the plastic strain and to
assure a satisfactory level of structural integrity.
Results and discussion
An experimental set-up was designed to examine the
effectiveness of the methodology, approximating to a real
repair operation as far as possible. Five different specimens
of API 5L grade B steel pipes, normally used in offshore
platform for produced water, were used as the specimens
for hydrostatic tests:
Initially, all the repaired specimens (no composites sleeves
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Fig.12 (top). 12-in SCH-0 steel pipe
with a 10-mm repaired hole, before
and after testing.
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Fig.11 – Detailed temperature control
system: 1 – the pressured water
machine connection; 2 – the
temperature control thermostat; 3 –
the electrical resistance.
Fig.13 (bottom). Deformed end cap
after testing at 60kg/cm2 and 80ºC.
were used, only the clamp) with the two systems were
submitted to a classical hydrostatic test at room temperature
to evaluate its strength and effectiveness. The maximum
allowable time for each repair was 60mins, and all tests
began exactly 75mins after the start of the repair process. In
the tests, the pipe pressure was raised to 30kg/cm2 and
maintained at this level for 60mins. After five cycles, if the
repair did not fail, the specimen was unloaded and inspected
to check any eventual small leaks or reinforcement
disbonding.
As a second step, the specimens were repaired with system
B (no sleeves were used, only the clamp) and submitted to
five pressure cycles (60mins at 30 kg/cm2) with the water
temperature inside the specimen at 80ºC, increased while
the water was at atmospheric pressure. The internal pressure
was not increased until after the temperature had stabilized.
After each pressure cycle, the specimen was cooled to room
temperature, and each specimen was therefore also
submitted to five temperature cycles during testing.
Once again, the maximum allowable time for each repair
was 60mins, and all tests began exactly 75mins after the
beginning of the repair. The temperature level of 80ºC was
chosen in order to simulate average offshore fluid
conditions.
The system to control water temperature inside the
specimens was designed specially for this procedure, and
the whole system (including the electrical resistance) was
installed at one end of the specimen, as can be seen in Figs
10 and 11.
All the repairs performed with Systems A and B using the
above methodology withstood the five pressure cycles with
water at room temperature. The repairs also resisted the
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F a ilu re p re ssu re (k g /c m 2 )
Te st
1
8 .9 2
2
17.64
3
16.17
4
18.35
5
14.27
Av e r ag e
1 5 .0 7
Table 1. Failure pressure for
specimen 2 if the repair procedure is
not adopted.
F a ilu re p re ssu re (k g /c m 2 )
20.18 (f ir st cycle )
2
4.92 (se con d cycle )
3
30.00 (f ir st cycle - af te r 10 m in )
4
13.92 (f ir st cycle )
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Te st
surprisingly well when the proposed repair procedure was
adopted, even at temperatures above the heat-distortion
temperature. All the repairs resisted to five cycles at 80oC
in tests performed on specimens 1, 2, and 3.
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high-pressure tests; it was not possible to obtain a failure
pressure since the pipe end caps were not designed for burst
testing and they deformed plastically and failed before the
repair failed, as can be seen in Fig.13.
Table 2. Failure pressure for
specimen 4 at 80oC.
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9.84 (f ir st cycle )
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If the proposed procedure is not adopted, however, the
repair may not be able to resist the loading. Table 1 shows
the failure pressure obtained for specimen 2 – the 2-in
diameter Schedule 80 pipe with a 10-mm diameter circular
hole – repaired using system A (no cap and no clamp).
All the pipes repaired with System B at 80ºC resisted for the
five cycles. In order to decide whether a given epoxy system
can be used at higher temperatures, it is suggested that the
same conditions are used as presented in Ref.1 for composite
sleeves: “For a design temperature greater than 40oC the
repair system shall not be used at a temperature higher than
the glass transition temperature (Tg) less 30oC. For repair
systems where Tg cannot be measured, the repair system
shall not be used above the heat-distortion temperature less
20oC. For repair systems which do not exhibit a clear
transition point, i.e. a significant reduction in mechanical
properties at elevated temperatures, then an upper
temperature limit, Tm, shall be defined (or quoted) by the
repair supplier.”
As an example, the failure pressures observed in hydrostatic
tests performed with specimen 4 (which has heat-distortion
temperature of 51oC) repaired using system A at 80oC are
presented in Table 2.
It is interesting to note that the adhesive System A behaved
Conclusions
The present work is a first step towards the definition of
safer and more-reliable procedure for applying epoxy repair
systems to through-thickness flaws caused by corrosion in
metallic pipelines. This procedure is designed to be used
together with a composite-sleeve repair system (which is
normalized, for instance, by the ISO technical specification
24817). The proposal is to apply the epoxy resin as described
in this paper and then to apply a composite material sleeve,
with a normalized thickness, to restrain the plastic strain
and to ensure a satisfactory level of structural integrity. The
main objective is to ensure that composite repairs to
leaking defects when qualified, designed, installed, and
inspected using ISO/TS 24817, and also the proposed
complementary procedure, will meet the specified
performance requirements.
The main requirements for epoxy resins to be used as repair
systems are: fast curing, high heat-distortion temperature,
and a thermal expansion coefficient similar to that of the
material of the pipe. The full validation of this simplified
repair methodology still requires an extensive programme
of experimental investigation, mainly concerning fatigue,
creep, ageing, and resistance to UV degradation and
weathering.
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References
4. H.Costa Mattos, R.F.Sampaio, J.M.L.Reis, and V.A.Perrut,
2007. Rehabilitation of corroded steel pipelines with epoxy
repair systems. In: Solid mechanics in Brazil 2007, Eds
M.Alves and H.S.da Costa Mattos, Brazilian Society of
Mechanical Sciences and Engineering, ISBN 978-85-8576930-7, pp485 – 496.
5. D.R.Stephens and R.B.Francini, 2000. A review and
evaluation of remaining strength criteria for corrosion defects
in transmission pipelines. ETCE2000/OGPT-10255,
Proceedings of ETCE/OMAE2000 Joint Conference, Energy
for the New Millenium, New Orleans, USA, 2000.
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1. ISO Technical Specification 24817, 2006. Petroleum,
petrochemical and natural gas industries - composite repairs
for pipework - qualification and design, installation, testing
and inspection.
2. C.A.Jaske, B.O.Hart, and W.A.Bruce, 2006. Pipeline repair
manual. Pipeline Research Council International, Inc.
Virginia.
3. A.T.de Mello dos Santos, 2006. Simplified analysis of the
caps influence in elasto-plastic pipe burst tests. MSc Thesis,
Universidade Federal Fluminense, January.
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307
In-service recoating of a 40-in
crude oil pipeline in Kazakhstan
by Sidney Taylor
Incal Pipeline Rehabilitation, Paris, France
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HE CPC pipeline is owned by a consortium of Russia, Kazakhstan, Oman governments, Chevron, and
a number of other companies. They started construction in 1998 and the pipeline became operational
in March, 2001. It was initially designed to deliver 28.2 million tons of crude annually with planned expansions
that would bring annual exports to 67 million tons.
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Built to Russian/Kazakh standards, the pipeline was coated with cold applied tape. Part of the pipeline route
runs close to the Caspian Sea. In some areas the pipeline is below the water table and completely immersed
in brackish water. They are now experiencing severe corrosion in several areas because: the wrong coating
was selected initially, poor-quality materials were used, there was a poor application technique (no surface
preparation prior to application), soil stresses damaging the coating, and the salt water environment
accelerated the corrosion rate.
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Areas of the pipeline are being recoated by a Russian contractor who is able to recoat about 150 linear
meters of pipe per day with the line in service. This paper describes the methods being used to excavate
the pipeline, remove the existing coating, prepare the surface of the pipe, and apply the new coating.
Historical perspective
The CPC crude pipeline system is the largest operating
investment project with foreign participation on the territory
of the former USSR. The cost of the first phase of
construction amounted to $2.6 billion. The 1,510-km
pipeline extends from the Tengiz oilfield in Kazakhstan to
the Novorossiisk-2 Marine Terminal on Russia’s Black Sea
coast, and the route is shown in Fig.1. The pipeline
diameter is 42in (1,067mm) between Kropotkin and the
terminal, and 40in (1,016mm) for the rest of the pipeline.
There are currently five pump stations in operation along
the route, and the throughput of the pipeline is currently
rated at 28.2 million tons of oil per year.
There is a planned expansion of the pipeline network. The
total number of pump stations will be increased to 15,
Author’s contact information:
tel:+1 713 621 6637
email: [email protected]
additional storage facilities will be added, and a third
loading buoy constructed at CPC’s marine terminal at
Novorossiysk. After all phases of the pipeline have been
completed, the maximum throughput of the CPC pipeline
system will reach 67 million tons of oil per year.
CPC has a complex organizational structure. Three
Governments and ten companies representing seven
countries participate in the project. Two joint stock
companies – CPC-R (Russia) and CPC-K (Kazakhstan) –
have been created to implement the project. The Structure
of CPC Shareholder Capital is the following:
Russia - 24%
Kazakhstan - 19%
Oman - 7%
Chevron Caspian Pipeline Consortium Co - 15%
LukArco – 12.5%
Mobil Caspian Pipeline – 7.5%
Rosneft-Shell Caspian Ventures Ltd – 7.5%
Agip International (NA) NV - 2%
BG Overseas Holdings Ltd - 2%
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The new sections of the pipeline in Kazakhstan were
constructed to Russian/Kazakh standards. The pipe coating
material selected was cold-applied tape which was field
applied over a Swedish Standard ST3 power tool cleaning
brushed surface. As can be seen in Fig.1, part of the pipeline
route runs close to the Caspian Sea. In some areas the
pipeline is below the water table and the pipeline is
completely immersed in brackish water.
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Corrosion problems
lack of adequate surface preparation, and the inherent
deficiencies in applying cold-applied tape in the field all
contributed to the problem. A major problem was tenting
of the tape over the weld seams: soil stresses caused rippling
of the coating and allowed water to enter the tented area
next to the weld seam. The water could then migrate along
the weld seam, resulting in spiral corrosion. The salt water
environment accelerated the corrosion rate.
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Oryx Caspian Pipeline LLC – 1.75%
Kazakhstan Pipeline Ventures LLC – 1.75%.
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Fig.1. Pipeline route.
In hindsight, cold-applied tape was the wrong coating for
this section of the pipeline. Poor-quality coating materials,
There are only three solutions at this point:
• replace the line
• recoat the line, or
• a combination of the two
In January, 2008, Stroytransgaz signed an agreement with
the Caspian Pipeline Consortium-K to replace the CPC
Fig.2. The entire spread
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Excavation
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This paper describes the efforts of the Russian contractor
Grasco to recoat portions of the KP 0-60 section of the CPC
pipeline. The project reported on here was done in the
summer of 2006, and additional work was done in 2007
and 2008 using the same methodology. CPC plans to
award additional work through 2011.
The entire spread of equipment, shown in Fig.2, was very
compact and consisted of only three excavators, four
sidebooms, and the specialized line-travel equipment
described below. There were approximately 40 people in
the crew including project management and inspection.
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pipeline section 0 km–116 km in Atyrau region in
Kazakhstan. Stroytransgaz will build a new pipeline section
with length of 130.3km and 40-in (1020mm) diameter, laid
along a new route. Upon completion of construction and
tie-in of newly-constructed section into the existing pipeline,
Stroytransgaz will also dismantle the old, decommissioned,
section of the oil pipeline.
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Fig.3. Excavation
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The recoating work was done with the line in service but at
a reduced operating pressure. Work on the line was
permitted when the operating pressure of the pipeline was
between 50 and 80% of normal operating pressure: work
had to stop if operating pressures were outside of this range.
Fig.4. Under-pipe excavator.
Excavation was done using two excavators, one on each
side of the pipeline as shown in Fig.3. The pipe is excavated
to a depth of about 1.5m below the bottom of the pipe on
both sides of the pipe, and all the spoil is placed on the far
side of the pipeline.
The next step in the excavation process is to remove the soil
from directly under the bottom of the pipe. This soil is very
difficult to remove, as it has been compacted over the years
by the weight of the pipeline and its contents. To accomplish
this, Grasco used the under-pipe excavator, shown in Fig.4.
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Fig.5. Under-pipe excavator in
operation - retracted position.
The soil is removed by two electrically-driven rotating
drums. The drums are about 0.7m high and about 1.37m
in diameter, and are equipped with teeth that dig through
the soil as the drums are rotated. The unit is about 5.5m in
length and weighs about 5 tons.
The under-pipe excavator is shown in operation in Fig.5.
The unit is held in place on the pipe by the two clamps at
the rear of the unit (directly in front of the operator) in the
photo. The clamps are in the retracted position and the rear
clamp is engaged and the front clamp is disengaged. A
hydraulic cylinder moves forward forcing the rotating
drums into the soil. The under-pipe excavator is shown in
the extended position in Fig.6. At this point the forward
clamp is engaged and the rear clamp disengaged and the
cylinder pulls the rear clamp forward and the process is
repeated.
Fig.6. Under-pipe excavator extended position.
The soil removed from under the pipe is deposited in the
excavated area on each side of the pipe. The end result is
about 0.8 m under-pipe clearance from one side of the
trench to the other. There is no chance of hitting or
damaging the pipe using this equipment as the unit rides
directly on the line.
A sideboom is positioned directly behind the under-pipe
excavation unit. The sidebooms are equipped with an Aframe boom, the feet which are placed against the spoil
bank and the load line is attached to a cradle holding the
pipe, as shown in Fig.7.
The sidebooms are there to hold and support the line in the
same position that the line was in prior to excavation,
neither raising nor lowering the line, and this minimizes
the additional stress the line is subjected to during the
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Fig.7. Sideboom A-frame.
Fig.8. Coating-removal machine.
recoating operation. Once the operation in front of the
sideboom has advanced about 15m, the sideboom operator
lowers the load line, raises the boom, and moves forward
15m. He then lowers the boom and raises the load line
until he is once again supporting the line. During this
operation the line is supported by the sideboom in front
and behind the sideboom being repositioned.
Coating removal
The tape coating is removed by the mechanical cutting
machine shown in Fig.8; the tape is actually being cut off
the pipe by a series of cutters. In addition, other cutting
tools located at the rear of the machine are actually milling
off several millimeters of pipe wall. The cutting tools are
shown in Fig.9.
Pipelines designed to Russian / Kazakh standards provide
for a 20% corrosion allowance when determining the
minimum wall thickness required, as opposed to a 5%
corrosion allowance used in designing most Western
pipelines. This allows them to reduce the wall thickness by
a couple of millimeters without affecting the MAOP of the
pipeline. This process has several negative results: the
milling process leaves a large amount of metal cuttings in
the ditch as can be seen in Fig.10; the milling tools also
create stress risers on the surface of the pipe as shown in
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Fig.9. Cutting tools.
Fig.10. Metal cuttings
left in the trench.
Fig.11. Cleaned pipe.
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Fig.13. Primer applicator.
Fig.14. Primed pipe.
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Fig.12. Blasting weld joints.
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Surface preparation
The area around the spiral weld seam cannot be completely
cleaned by the mechanical cutting machine. The cutters
tend to jump over the weld, leaving corrosion deposits still
adhering to the pipe. The weld seam area is particularly
vulnerable to corrosion because of the tenting of the tape
described earlier.
The fibreglass inner wrap is applied after the material has
been flooded on to the pipe. A roll of fibreglass material is
on one of the two tape arms and can be seen above the top
of the pipe in Fig.17. The tension on the fibreglass roll
provided by the tape arm allows the material to be pulled
into the hot bitumastic material, providing additional
strength to the coating system and helping to keep the
material from sagging to the bottom of the pipe. The
second tape arm holds the outer tape material. Figure 18
shows the tape being applied over the hot bitumastic
material.
The bitumastic material is kept at the proper application
temperature in a ‘dope’ kettle shown in Fig.19. The unit is
electrically heated, and temperature control is very good.
The reservoir is refilled from the dope kettle by the operator
(Fig.20).
Coating application
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Modified Bikaz, a bitumastic coating system, was selected as
the new coating to be applied. The coating is manufactured
in Russia and is a very thick coating system consisting of a
primer, a hot bitumastic inner coating, fibreglass
reinforcement layer, and a tape outerwrap. It is one of the
few coatings approved for pipeline use in Russia and
Kazakhstan.
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The weld seam area is cleaned using manual air abrasive
blast equipment as shown in Fig.12, and this is done just
prior to application of the primer. Figure 13 shows the blast
operator in the ditch: note the presence of water in the
bottom of the trench. The trench is starting to fill with
water indicating that it is below the water table at this point.
This creates additional problems and hazards for the
workers.
is similar to that of a hot coal tar enamel application
operation. As in the primer application, the hot bitumastic
material is applied using a flood-wipe system: the hot
material is stored in a reservoir on top of the unit and a
valve is opened allowing the hot material to run over the
pipe. The pipe rapidly cools the material in contact with it,
and allows the material to build up to the desired thickness.
Excess material is caught in a pan underneath the unit
where a pump returns it to the reservoir on top.
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Fig.11, and the weld cap is also milled off along with the
pipe surface. The cutting tools also raise fine “hairs” on the
pipe surface making it necessary to apply a very thick
external coating.
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Primer is applied using a ‘flood wipe’ system. The primer
application unit is shown in Fig.13: the primer is stored in
a tank on top of the unit and a valve at the bottom of the
tank allows the material to run on to the pipe upon which
a spinning ‘rug’ wipes or smears the primer around the
pipe. Primer application is often inconsistent when applied
in this manner, as can be seen in Fig.14. When the unit
stops, the primer will often run on to the ground if the valve
is not shut off immediately, and a puddle of primer can be
seen beneath the unit in Fig.14. This would certainly create
an environmental problem in some jurisdictions.
Following primer application, a sideboom is used to support
the pipe. The pipe is held by a steel wheeled cradle, as
shown in Fig.15; this damages the primer at the specific
location where the pipe is picked up. However, the cradle
does not roll along the pipe during the recoating operation,
so the damage is limited to just those points where the
cradle supports the pipe, and this does not create a significant
problem for the coating system.
The rest of the coating system is applied with the line-travel
applicator shown in Fig.16, which shows the coating
applicator in operation. The cloud visible in the photograph
Backfilling
Once the coating material has cooled sufficiently, a third
backhoe begins backfilling (Fig.20). The soil is taken from
the spoil bank and placed in the trench; the backhoe
operator also forces soil under the pipe using the bucket.
Initially the trench is only backfilled to the top of the pipe;
once the coating has cooled overnight and becomes hard,
the remaining soil is placed over the top of the pipe.
The pipe coating is checked for adhesion periodically. A
test site is shown in Fig.21. No attempt is made to ‘jeep’ the
entire surface of the pipe to check for holidays.
Will this work on Western lines?
There are many obvious advantages to this method of pipe
recoating:
•
•
•
•
recoating done with the line in operation
minimal amount of equipment required
40-man work crew
150 linear meters of 1020-mm diameter pipe
recoated per day.
Western companies designed their pipelines to different
standards, have different methods of operating, and have
different legal and environmental considerations. The
question becomes: what would have to be done to adapt
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Fig.15. Steel cradle on primed pipe.
Fig.16. Line-travel coating applicator
in operation.
Fig.17. Application of the fibreglass
inner wrap.
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Fig.18. Tape application.
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Fig.19. Refilling bitumastic material.
this recoating methodology to western pipeline recoating
projects?
Engineering considerations
One of the key benefits of this method is being able to
recoat the line while it is in-service. The CPC line is a
relatively-new line, only 16-17 years old. Construction
inspection records exist for this section of the pipeline and
the pipeline has had numerous in-line inspections.
Consequently a great deal is known about this section of
the line.
It is necessary to perform a credible failure analysis in order
for this to work on older western lines. The line must have
undergone recent in-line inspections and, if the welds are
questionable, an ultrasonic inspection for cracks should be
considered. Axial and circumferential stresses on the pipe
must be evaluated. In the end, a safe operating pressure
range must be determined. You have to develop methods
for resolving problems concerning pipe operating pressure
requirements and work schedules.
Civil work
It will be necessary to evaluate company operating
procedures and governmental regulations affecting
mechanical excavation next to an operating pipeline.
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Fig.21. Repair.
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Fig.20. Backfilling operation.
Particular attention should be paid to the need to compact
the soil under the pipeline. The lack of rigorous soil
compaction on the CPC line will certainly result in some
additional settling of the line over time. It must be
determined how much additional settling would be
acceptable.
Inspection
Coating removal
Surface preparation
The coating-removal unit used on the CPC project would
not be acceptable on most western lines. The lines have
smaller corrosion allowances, the milling machine damages
the weld caps and leaves stress risers on the pipe. However,
it is possible to remove the coatings using high-pressure
water jets at production rates that meet or exceed those of
the CPC coating-removal equipment. Using water jets to
remove the coating has the additional advantage of removing
any soluble salts from the surface of the pipe.
Most modern coating systems require an SA 2.5 surface
preparation grade before coating application. Automated
air abrasive blast equipment can achieve this at comparable
production rates. Another question to consider is the
containment and recovery of blast media. As the entire
spread of equipment is very compact, it will probably be
necessary to contain and recover the blast media to prevent
it from impacting the other operations going on at the same
time.
The methodology used on this project did not incorporate
100% visual and NDT inspection of the pipe. It will be
necessary to develop an inspection programme and a way to
protect the inspectors while they are in the trench.
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Repairs
A repair procedure must be developed prior to the start of
work. The procedure must address the following issues:
• what type of repairs are going to be made and how
to do them?
• when do you do the repairs?
• before coating application
• after coating application
• how to protect people in the trench while they make
the repair?
• moveable shoring?
• additional excavation at the site?
requirements. However these are new coatings and, while
laboratory tests look very encouraging, the coatings do not
have a lot of in-ground experience.
It is also necessary to be able to start and stop the application
of the coatings without allowing solvents to contaminate
the coating applied to the pipeline.
Conclusions
• In-situ rehabilitation of large diameter pipelines in
operation is possible with production rates of about
450 to 500 sqm/d of pipe.
• The methodology used on the CPC line greatly
reduces the amount of equipment and manpower
required to recoat long pipeline segments.
• Comprehensive engineering analysis of the pipeline
must be done to determine the pipeline operating
parameters while work is being performed.
• Other coating-removal, surface-preparation, and
coating-application equipment will be required for
work on western pipelines.
• New rapid-curing polyurethane coatings will have
to be evaluated.
Coating application
PL
E
C
O
PY
Many western countries no longer permit the field
application of hot coal tar or bitumastic coatings, primarily
for environmental and health and safety reasons. The only
liquid coatings that could be used are very-rapid-setting
urethane coatings. The coating should be stackable in 1020 minutes when applied at the operating pipeline
temperature. Recently, coating manufacturers have
developed some Polyurethane coatings meeting these
SA
M
This paper was presented at the Evaluation and
Rehabilitation of Pipelines Conference held in Prague in
October, 2008, and organized by Clarion Technical Confrences
and Global Pipeline Monthly.
AD
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319
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4th Quarter, 2008
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Two full days of technical presentations will address:
‘Unpiggable’ pipelines, New pigging technologies,
Mechanical damage, Uncertainty in integrity
assessments, Pipeline mapping and locating,
Improved data analysis, Inspection of cased pipe,
and much more!
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53"*/*/($0634&4t'&#36"3:ű
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Visit one-on-one with the world’s top providers of
pigging, ILI, and integrity management services —
more than 60 companies will be represented.
See inside for details!
RE
320
The Journal of Pipeline Engineering
ADVERTISEMENT
$0634&
NEW! PERFORMING PIPELINE REHABILITATION
WHO SHOULD ATTEND
Topics: Introduction, Rehabilitation Options, In-Plant
Rehabilitation of Pipeline, Out of the Ditch Rehabilitation
Projects, In-situ and Short Segment Rehabilitation Projects, New
Approach to In-Situ Rehabilitation, Internal Pipeline Rehabilitation
Projects, Inspection of the pipeline, Making necessary repairs,
Environmental Issues, Industry Standards to be incorporated in Job
Specifications, Tying it all together.
PL
E
C
Engineers involved in: Determining the best way to rehabilitate
a section of pipeline, Preparing the project specifications,
Performing the necessary engineering calculations to insure the
project is carried out safely, Health and safety issues specific to
rehabilitation projects. Field Operations Personnel and contractors
who need to be aware of many alternatives techniques available for
pipeline rehabilitation and their cost impact. Inspection Personnel
involved in evaluation of defects and selection of proper repair
techniques.
LECTURER
Sidney A Taylor is president of Incal Pipeline Rehabilitation, Inc.
He has over 30 years’ experience in the design and development of
automated high-pressure water jet cleaning and coating systems.
Prior to Incal, Sid worked with Schlumberger as a designer and
manufacturer of well-logging tools and equipment, with MW
Kellogg as a senior regulatory attorney, with Weatherford as
general manager of water jetting systems, and with CRC-Evans
as vice-president, engineering and marketing, where he was
responsible for engineering design, manufacturing, and world-wide
marketing of pipeline rehabilitation systems.
PY
his course is centered on the practical aspects of pipeline
rehabilitation and covers both internal and external
rehabilitation. The course goes into depth on how to safely
rehabilitate operating pipelines using manual and automated
equipment. Movement of in-service pipelines is analyzed in detail
including the application and methodology of recommended
practice API 1117. Other industry standards applicable to pipeline
rehabilitation are discussed as well as how they should be
incorporated into project specifications. Approximately half of
the course is spent in analyzing case studies of field rehabilitation
projects from around the world. Over 400 photographs are used
to illustrate how the work was performed and the results obtained.
The course presents techniques for performing the work with a
combination of in-house personnel and outside contractors to
minimize costs while maintaining clear lines of responsibility.
O
T
$0634&
EXCAVATION INSPECTION & APPLIED NDE
FOR ILI/DA VALIDATION AND CORRELATION
T
SA
M
he course is designed around the critical step of “Excavation
Inspection and Documentation,” which has recently been termed
the 3rd step in Direct Assessment. The focus will be on the validation
and correlation of both ILI results and/or Direct Assessment
techniques through non- destructive testing in the excavation.
$0634&0#+&$5*7&
On completion of the course, participants will have a solid
understanding of the minimum requirements to ensure maximum
correlation with ILI and Direct assessment results during an
excavation program. In addition, each participant will walk away
with a general understanding of the available technology and
procedures to implement contracts, increase quality, and reduce
overall project costs.
WHO SHOULD ATTEND
The course is specifically designed for project managers, engineers
and technical personnel responsible for the management,
implementation and reporting of pipeline integrity inspection
activities.
and correlation, data management, and the characterization of
the environment around the pipe. He has published numerous
papers related to SCC, investigative procedures, and environmental
relationships related to time-dependent pipeline threats.
Brent Zeller is an advanced NDT consultant with Eclipse Scientific
Inc. With offices in Waterloo, Ontario and Edmonton, Alberta,
Eclipse Scientific develops specialized products and techniques
for the NDT industry, specifically in the advanced ultrasonic (UT)
discipline. Brent now provides Advanced UT Expertise to clients
worldwide, to assist with implementation of new technologies,
training of personnel, and procedure and technique development for
the industry.
Rick Desaulniers is currently Line Product Manager (Analysis) with
Baker Hughes Management Group. He has been involved in the
pipeline industry for the past 20 years in the Data Interpretation
Department analyzing 1000’s of miles of pipelines around the world,
specifically in Magnetic Flux Leakage type tools. He was on the
Standards Development Committee for ANSI/ASNT ILI-PQ-2005
In-Line Inspection Personnel Qualification and Certification
Standard. He received his Bachelor of Science in Geology from
McMaster University in Hamilton, Ontario.
LECTURERS
Jim Marr is currently technical integrity specialist with Baker
Hughes Pipeline Management Group. He is also president of
the pipeline consulting firm Marr Associates. Jim has worked in
pipeline integrity for the past 20 years, focusing on SCC, external
corrosion, direct assessment, direct examination, ILI development
Topics: Risk, Engineering Critical Assessment, Data collection and
evaluation, In-Line Inspection, Tools, Direct Assessment, Direct
examination, Hydro Testing, Remediation & Repair Technologies,
Developmental and new application NDE Techniques, Mitigation and
Fitness for Purpose, Case studies.
4th Quarter, 2008
321
SEMENT FEATURE
S
tress-corrosion cracking (SCC) continues to be a safety concern to pipeline operators
and government regulatory agencies, and it must be addressed in integrity management
plans. This course will provide a detailed description of what is known about the appearance
and causes of SCC, and it will discuss various approaches to mitigating and managing the
problem. Practical information on recognizing and dealing with SCC will be presented along
with descriptions of research results that have led to our current understanding of causes and
methods of management.
WHO SHOULD ATTEND
Pipeline engineers, designers, and service professionals who are involved with the maintenance,
inspection, and repair of pipelines. Researchers and regulatory personnel who want to be aware
of the current understanding of SCC in pipelines.
LECTURERS
T
he use of in-line tools for inspection
and cleaning is accepted as essential
for the safe and profitable operation
of all pipelines. Now, Regulations
require internal inspections using
geometry pigs for detecting changes in
circumference and MFL or ultrasonic
pigs for determining wall anomalies, or
wall loss due to corrosion in onshore
pipelines in the US. Offshore, pipeline
operators wage a constant battle for flow
assurance against paraffin, hydrate, and
asphaltene formation in deepwater lines,
and pigging technology combined with
chemical treatment is their primary
weapon.
WHO SHOULD ATTEND
The course is especially designed
for project managers, engineers,
maintenance and technical personnel
responsible for pipeline integrity
assurance, flow assurance, corrosion
control, and safety.
C
O
Dr. Raymond R. Fessler worked on the Pipeline Research Committee project on SCC since its
inception in 1965. He personally conducted most of the early field investigations of SCC, from
which he identified the major factors that cause high-pH SCC in pipelines. For the past several
years, he has been the SCC consultant for GRI and PRCI.
John Mackenzie is a senior pipeline specialist with Kiefner & Associates, focusing on the
areas of Integrity Management Plans and Stress Corrosion Cracking. John was previously
with TransCanada Pipelines for 25 years, where he was responsible for the company’s original
investigation into SCC (1986-1990). This work led to the discovery of near-neutral pH SCC
and identified the conditions under which it occurs. He also served as Chair of the PRCI’s
SCC Subcommittee for two years.
COURSE 5
PIPELINE PIGGING AND
IN-LINE INSPECTION
PY
COURSE 3
STRESS CORROSION CRACKING IN PIPELINES
PL
E
Topics: Description of SCC. History of SCC in pipelines. Stages of SCC. Test techniques to
study SCC. Environmental factors. Stress factors. Metallurgical factors. Mechanisms of SCC.
Likely locations for SCC. SCC detection and integrity assurance. Mitigating SCC. Integrity
management plans.
COURSE 4
PIPELINE MAPPING, GIS AND DATA INTEGRATION
T
SA
M
his course is designed for pipeline company personnel in need of either a refresher or
introduction to data management for pipeline integrity support and to support the risk
analysis process. It will review data model types, where to locate data, how to integrate data
from different sources, and how to best make this data work for you. On completion of this
course attendees will have an understanding ways data can be stored, including a review of
industry standard data models; will be able to identify possible data sources and will have
learned methods for review and acquisition of data. In addition attendees will have powerful
insight into getting the most out of the vast amounts of data available to make better-informed
decisions regarding risk and integrity management.
WHO SHOULD ATTEND
Pipeline integrity managers, pipeline engineers involved in assessment activities including risk
assessment, and anyone requiring a general knowledge of pipeline data management.
LECTURER
Nick Park has 12 years of software product management experience with more than six
years specifically in the pipeline industry. As a Consultant and, most recently, Vice President
of Technology for GeoFields Inc., Mr. Park is involved in the design and implementation of
data management systems for complex pipeline operations, which are currently being used
by thousands of individuals across a diverse client base. Mr. Park has an MS in Geographic
Information Systems and continues to provide support to a range of mapping and GIS projects.
Topics: Data Storage. Data models. What is GIS? Spatial Data Overview. Pipeline data in GIS.
GIS vendor options. Pipeline mapping. Geocoding. Spatial analysis (geoprocessing). Topology.
Establishing the data framework. Asset data. Off-pipe spatial data. Links to external systems.
Integrating new data. Asset data. GPS. Field surveys. Applications to analyze data. Delivering
data and analyses.
LECTURERS
Gary Smith is president of Inline
Services, specializing in pigging
equipment and services. He has 27
years experience in the pipeline pigging
industry, working in services such as
commissioning and maintenance of
pipelines as well as with designing and
manufacturing pigging equipment.
Patrick Vieth is Sr. Vice President
with CC Technologies. He has 18 years
of experience working with pipeline
operators to reduce the likelihood of
failures through in-line inspection,
hydrostatic testing, defect assessment,
risk assessment, and fitness-for-purpose
assessment.
George Williamson has 25 years of
experience in pipeline and oil and
gas field operations, maintenance,
and engineering. He is a registered
professional engineer.
Topics: Utility and maintenance
pigging. Metal loss in-line inspection.
Other in-line inspection tools. Crack
detection pigs. Mapping. Geometry and
bend-detection pigs. Wax deposition
measurement. Spanning pigs. Semiintelligent pigs. Designing and
implementing an in-line inspection (ILI)
program. Post in-line inspection issues.
322
The Journal of Pipeline Engineering
ADVERTISEMENT
COURSE 6
DEFECT ASSESSMENT
IN PIPELINES
COURSE 7
PIPELINE REPAIR METHODS/
IN-SERVICE WELDING
T
T
LECTURER
LECTURERS
Bill Bruce is director of welding technology with CC Technologies. Prior to joining CCT,
he was a technology leader at Edison Welding Institute and a senior engineer at Panhandle
Eastern Pipeline Co. He is a member of the American Petroleum Institute API 1104
Committee and is the chairman of the Maintenance Welding Subcommittee.
PY
Dr. Chris Alexander is a Principal with Stress Engineering Services, Inc. He has been
integrally involved in assessing the effects of dents and mechanical damage on the
structural integrity of pipelines. Mr. Alexander has also been involved in assessing the
use of composites in repairing pipelines and has published numerous papers and made
international presentations on this subject.
Topics: Defect assessment prior to repair. Selecting an appropriate repair method.
Burnthrough and related safety concerns. Hydrogen cracking concerns. Full-encirclement
repair sleeves. Hot tap branch connections. Pipeline repair by weld deposition. Nonwelded
repairs. Code and regulatory requirements. Procedure selection for hot tap and repair
sleeve welding. Practical aspects of hot tap and repair sleeve welding. Lessons learned.
SA
M
PL
E
Professor Phil Hopkins has more
than 26 years’ experience in pipeline
engineering, and is Technical Director
with Penspen Integrity and Visiting
Professor of Engineering at the University
of Newcastle-upon-Tyne. He has worked
with most of the major oil and gas
companies and pipeline companies
around the world, providing consultancy
on management, business, design,
maintenance, inspection, risk analysis and
safety, and failure investigations. He is the
immediate past-chairman of the Executive
Committee of the ASME Pipeline Systems
Division and has served on many other
professional committees, including the
British Standards Institution, European
Pipeline Research Group, the American
Gas Association’s Pipeline Research
Committee, and the DNV Pipeline
Committee. More than 1700 engineers and
technical personnel around the world have
attended his Pipeline Defect Assessment
and Pipeline Integrity-related courses.
WHO SHOULD ATTEND
Pipeline engineers, Operations and Maintenance personnel, inspectors, and welders.
O
WHO SHOULD ATTEND
Pipeline engineers, designers and service
professionals who are involved with the
maintenance, inspection, and repair of
pipelines.
his course will cover the various aspects of pipeline repair using weld and nonweld methods, as well as the concerns for welding onto in-service pipelines and the
approaches used to address them.
C
he increasing use of inline inspection
methods is helping pipeline owners
to assess the condition of their lines,
and if these methods are combined with
modern defect-assessment methods, they
can provide a very powerful, and costeffective, tool. This course will present the
latest defect-assessment methods, which
range from simple, quick, assessment
methods, to more-detailed fitness for
purpose analysis. It will cover assessment
of internal and external corrosion, dents
and gouges, cracks (e.g. SCC), weld
defects, and fatigue. The course is highly
interactive and takes the form of lectures,
workshops, and case studies.
Topics: Defect failure relationships.
Corrosion defects. Workshop: corrosion
assessment using fitness for purpose.
Gouges. Dents. Cracks. Weld defects.
Limit-state design. Fracture mechanics.
Fatigue. Setting intelligent pig inspection
levels. Pipeline repair and rehabilitation.
Risk and integrity management and
analysis.
Workshop: setting priorities.
$0634&ŷ'&#36"3:Ÿ
OPTIMIZING ILI INSPECTION SCHEDULING
T
his new one-day course presents methods for dealing with inherent uncertainties
about corrosion growth rates as well as ILI tool measurements, with the object of
improving the reliability of ILI inspections, and the interpretation of the inspection results
into maintenance decisions. It examines methods of determining corrosion rates, timing
of inspections, and deterministic-, reliability-, and risk-based approaches to dealing with
uncertainties and establishing failure criteria. The course is intended for those with basic
familiarity with ILI tools and their capabilities.
WHO SHOULD ATTEND
The course is especially designed for pipeline integrity engineers and inspection specialists,
ILI data analysts, and technical personnel responsible for pipeline integrity assurance and
corrosion control.
LECTURER
Guy Desjardins is president of Desjardins Integrity, a consulting firm in Calgary, AB. He
has more than 25 years experience in the oil and gas industry and 12 years with pipelines.
In 1997, he became a principal co-owner of Morrison Scientific and became Morrison’s
president in 1998. He has been an independent consultant since 2005, offering services of
data analysis, research, and software development.
Topics: Introduction, corrosion rates, introduction to inspection timing, deterministic
approach, reliability approach, risk approach, assessing ILI uncertainty, methods of
assessing corrosion rates, assessment of failure pressure, miscellaneous topics, OPIS
software tutorial.
4th Quarter, 2008
323
SEMENT FEATURE
5IJTQSPHSBNJTTVCKFDUUPDIBOHF
6QEBUFTXJMMCFQPTUFEBU888$-"3*0/03(
COCKTAIL RECEPTION,
EXHIBITION OPENS
8&%/&4%":'FCSVBSZ
Registration
BRUSHES FOR
PIPELINE CLEANING
DOUG BATZEL
Galaxy Brushes, Moosic, PA, USA
FACTORS AFFECTING THE
DESIGN AND SELECTION
OF PIGGING TOOLS FOR
Dh>d/ͳ/DdZW/W>/E^
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This paper contrasts the different
types of brushes used in utility pipeline
pigging, and in ILI on MFL pigs. The
various brush constructions will be
presented along with their advantages
and disadvantages. While there are
many pig designs, in the end it is the
brush that produces the desired result,
a clean and inspectable pipeline. Thus,
understanding how brushes work and
their relative effectiveness is important,
particularly in treating black powder,
MIC, and pipeline pits.
PETER FRETWELL
Pipeline Engineering, Catterick, UK
$PGGFFFYIJCJUJPO
DETERMINING AN ACCURATE
PIPELINE PROFILE PRIOR
TO REHABILITATION
OTTO BALLANTIJN
Reduct, Schelle, Belgium
There are essentially three efficient
moments in the lifetime of a pipe to
PY
o1.
pig body to reduce travel speed while
incorporating an inertia/flow actuated
valve to minimize stalling and surging.
Many common cleaning elements can
be installed on the pig, while the high
bypass flow improves the effectiveness of
cleaning operations by suspending large
amounts of debris in the flow well out in
front of the pig. The tool provides highly
efficient maintenance pigging without
the need to reduce product flow rates.
O
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RECEPTION
Professional Institute of
Pipeline Engineers - PIPE
Non-members welcome!
PL
E
1.
determine its exact XYZ location: at
initial installation, during regular
maintenance, and when it is being
rehabilitated. Particularly during
rehabilitation projects, determining the
XYZ location of a pipe adds significant
value because usually old pipes are
rehabilitated for which no reliable digital
XY data exists, not to mention accurate
depth and/or inclination information.
If pipeline mapping can be done
efficiently and at a low incremental
cost, the threshold to upgrade the GIS
platform is very low for the pipeline
owner/operator. Furthermore, it will
benefit the uniformity of the handover
procedure. From a contractor’s
perspective, determining and accurate
segment profile pre-rehabilitation may
avoid costly faulty installations. This
paper discusses Gyroscopic mapping
tools that provide a practical and efficient
solution. Starting from ID 40mm, the
systems are deployable in most pipeline
rehabilitation projects.
M
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ERIC FREEMAN, ROBERT STRONG,
and COLIN DRYSDALE
TD Williamson, Houston, TX, USA
This paper outlines performance
characteristics and field testing results
for a new Speed Reducing Pig which
utilizes high bypass flow through the
DESIGN AND CONTRUCTION
K&ϰϮͳ/E>/Yh/W/W>/E
BATCH PIG FACILITY
ROBERT KRATSCH
Enbridge, Edmonton, AB, Canada
A SOLUTION FOR PIPELINES
PREVIOUSLY CONSIDERED
UNPIGGABLE: A NORTH
AMERICAN PIPELINE
OPERATOR’S EXPERIENCE
(speaker to be confirmed)
GE Oil & Gas PII Pipeline Solutions
Cramlington, UK
Almost 30% of the world’s oil and gas
transmission pipelines are not suitable
for ILI tools. In fact, many of these
lines were built before intelligent pigs
were invented. This is an opportunity
to combine experience of pipeline
inspection with the requirement
of pipeline operating companies to
develop technologies to inspect these
challenging pipelines. One example of
this cooperation arose in 2007, when a
North American pipeline operator needed
to conduct metal-loss inspections of 13
natural gas pipelines in the US. This
paper gives an insight into the project’s
many challenges in terms of pipeline
configuration, cleanliness, regulatory and
internal deadlines, and inspection.
324
The Journal of Pipeline Engineering
ADVERTISEMENT
TREVOR BURON, TOM LIVERANCE
and JEFF GRIES
Coffman Engineers, Anchorage, AK, USA
PETE LAPELLA
Chevron, Anchorage, AK, USA
JOHN MOHR
A Hak Industrial Services
Houston, TX, USA
$PGGFFFYIJCJUJPO
EVALUATING DAMAGE TO
ONSHORE AND OFFSHORE
PIPELINES USING ILI DATA
DR CHRIS ALEXANDER
Stress Engineering Services
ORAN TARLTON
Williams Midstream
ARTHUR PRAYTHER
Rosen Inspection, Houston, TX, USA
SA
M
PL
E
Increased aversion to risk is forcing
many owners to reassess pipelines
previously considered impossible to inspect.
This paper discusses the process utilized
and challenges overcome to successfully
inspect a pipeline from the initial planning
stages through cleaning and finally to the
in-line ultrasonic wall thickness inspection.
It illustrates that patience and improving
technology allow for detailed metal loss
data acquisition in pipelines deemed
un-inspectible only a few years ago.
The project involved integrity
assessment of a 40-year old 6-inch
subsea oil pipeline in the Cook Inlet of
Alaska. Hydrotesting and in-line caliper
surveys were utilized to establish baseline
assessments. The project offered many
challenges that had deterred previous
attempts at in-line-inspection: multiple
internal diameters, ownership changes
that led to inadequate engineering records,
sections constructed of ultra heavy wall
pipe, and heavy wax deposits. Limited
maintenance pigging led to a difficult
cleaning process prior to performing the
ILI survey. A project requirement was to
have no production downtime, thus surveys
were all conducted in the normal crude
production stream.
PY
IN LINE INSPECTION
OF AN UNPIGGABLE
Dh>d/ͳ/DdZZhK/>
PIPELINE IN COOK INLET
O
become an extension of the PHMSA-DOT
regulations. The threats are similar but
the consequences high due to population
density of end users. Therefore, as
was required through the National
Pipeline Mapping System, the need
for accurate location of the lines and a
management framework will be required.
This presentation will cover relevant
technologies such as ILI mapping tools,
ground penetrating radar (GPR), oblique
aerial imagery, and horizontal directional
drilling.
C
-VODIFYIJCJUJPO
LDC COMPLIANCE:
BASELINE SURVEYS AND A
MANAGEMENT FRAMEWORK
TODD PORTER
Geospatial Corp, Houston, TX, USA
Pipeline Integrity Management for
gas distribution pipelines will soon
The paper outlines a systematic
approach for evaluating damaged pipeline
using ILI data. The authors offer a case
study that used data collected during an
ILI run of a damaged subsea pipeline.
The assessment included development of
finite element models using geometric
ILI data. The assessment integrated actual
pressure history data in conjunction with
a cumulative damage assessment model to
determine the remaining life of the selected
anomalies. It also utilized prior full-scale
experimental data to confirm the accuracy
of the models.
INTEGRATING MFL
AND ULTRASONICS:
A PROJECT FOR BP ALASKA
ΈTITLE TO BE CONFIRMEDΉ
THOMAS BEUKER
Rosen, Houston, TX, USA
High-resolution MFL and UTWM
ILI tools have been around for a long
time. Most of us understand that the
technologies have complementary
strengths and weaknesses in detection
and sizing capabilities. For example, MFL
offers better detection capabilities for small
pitting anomalies while UTWM is better
at measuring general wall thinning. The
inherent imperfections of the approaches
can sometimes leave you guessing about
what might be missing from your data.
BP Alaska and Rosen partnered in 2008
to identify a candidate pipeline to test a
combination MFL-UTWM tool, RoCorr-UT.
This paper discusses the successful run of
the tool through BP’s 28-mile crude line
from Endicott Island to Pump Station #1.
A METHODOLOGY FOR THE
PREDICTION OF PIPELINE
&/>hZ&ZYhEzhdK
EXTERNAL INTERFERENCE
C LYONS and DR JANE HASWELL
Pipeline Integrity Engineers
Newcastle, UK
DR PHIL HOPKINS
Penspen Integrity, Newcastle, UK
R ELLIS
Shell UK, Stanlow, UK
N JACKSON
National Grid, Warwick, UK
The United Kingdom Onshore
Pipeline Operators Association (UKOPA)
is developing supplements to the UK
pipeline codes BSI PD 8010 and IGE/
TD/1. These supplements will provide a
standardized approach for the application
of quantified risk assessment to pipelines.
UKOPA has evaluated and recommended
a methodology: this paper covers the
background to, and justification of, this
methodology.
The most relevant damage mechanism
in pipeline failure is external interference.
Interference produces a gouge, dent
or a dent-gouge. This paper describes
the fracture mechanics model used to
predict the failure probability of pipelines
containing dent and gouge damage. It
contains predictions of failure frequency
obtained using the gas industry failure
frequency prediction methodologies FFREQ
and operational failure data from the
UKOPA fault database. The failure model
and prediction methodology are explained,
and typical results are presented and
discussed.
3FDFQUJPOJOFYIJCJUJPOBSFB
4th Quarter, 2008
325
SEMENT FEATURE
MULTIPLE APPROACH TO
INTEGRITY MANAGEMENT
OF AGING PIPELINES
h^/E'd,Et^d/Eͳ>/E
INSPECTION TECHNOLOGIES
MORE LEGAL ISSUES
IN PIPELINE INTEGRITY
PROGRAMS: AN UPDATE
CHRIS PAUL
Joyce Paul, Tulsa, OK, USA
The presentation will review the
legal issues and the demands that
pipeline integrity programs place upon
operators including data integration
and records retention, and a discussion
of how these issues and demands may
result in misinterpretation and misuse
of data and documents. The bases for
management and company exposure will
be discussed, as will the criteria used by
the government for determining whether
or not information within the knowledge
PANELISTS TO BE ANNOUNCED
The panel will discuss benefits of
standardizing procurement contracts
to allow more focus on correct tool
selection and performance criteria.
-VODIBOEFYIJCJUJPO
ETHANOL TRANSPORTATION:
STATUS OF RESEARCH AND
INTEGRITY MANAGEMENT
PATRICK VIETH, JOHN BEAVERS
CC Technologies, Dublin, OH, USA
The pipeline industry is undertaking
considerable research to determine the
best approach to manage the potential for
internal stress corrosion cracking (SCC)
to occur while transporting ethanol and
fuel grade ethanol. The parameters that
affect the potential for SCC (e.g., oxygen,
water, etc.) are understood, and the
research is now focused on methods to
reduce the likelihood of SCC. The current
state of the research and testing will be
presented
DEVELOPMENTS IN
Z>//>/dzͳ^
CORROSION MANAGEMENT
AND SIGNIFICANCE OF ILI
SA
DR V KANAYKIN, DR B PATRAMANSKIY,
and DR V LOSKUTOV
Spetsneftegaz, Moscow, Russia
PANEL:
TOWARD A MODEL FOR
GLOBAL ILI CONTRACTS
DILIGENT STATISTICAL
ANALYSIS OF REAL ILI DATA:
IMPLICATIONS, INFERENCES
AND LESSONS LEARNED
PY
Self Excited Eddy Currents (SEEC)
present a unique and novel method for
internal in-line inspection of natural gas
transmission pipelines for the presence
of features aligned with the main pipe
axis such as Stress Corrosion Cracking
(SCC). This paper outlines the theory,
methodology and basic design principles
of an SEEC based tool. Initial field trials
and results are presented
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DR. SLAVA TIMASHEV
Russian Academy of Sciences
Ekaterinburg, Russia
O
GRANT COLEMAN
BJ Systems & Services
RICHARD KANIA
TransCanada PipeLines
Calgary, AB, Canada
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THE DETECTION OF SCC
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of the company might result not only in
simple liability, but also the possibility
of criminal exposure. The presentation
will review solutions to the legal issues,
including how to deal with improved
ILI tools which provide tremendous
amounts of data that must be captured
and integrated with other information
involving the operator’s pipeline systems.
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MARK STEPHENS
C-FER Technologies
Edmonton, AB, Canada
ALBERT VAN ROODSELAAR
Chevron, Houston, TX, USA
This paper provides an overview of
an ongoing research project, sponsored
by the Pipeline Research Council
International (PRCI), which is developing
a reliability-based process that will
form the basis for an industry-accepted
approach to assessing and managing
pipeline integrity with respect to
corrosion. It also discusses the sources
of uncertainty inherent in the in-line
inspection process and their significance
in the context of corrosion reliability
analysis.
Real ILI data was analyzed with a
sophisticated and rigorous algorithm
developed using Monte Carlo simulation.
The data was gathered from ILI runs on
three continents. The research results
point the way toward a new generation of
ILI and DA/Verification tools combining
sophisticated statistical analysis of the
data obtained using these tools and
suggested improvements to API RP1163.
Lessons learned include:
x Role of false negatives and false
positives in determining probability of
failure
x How to assess variances of specific ILI
tools and verification instruments
x The Regression line and the Unity
curve
x Assessment of the immeasurable
defect sizes
x Influence of the number and location
of verification points on accuracy of
defect size assessments
x How to use these assessments when
predicting probability of exceedance,
corrosion rates, performing RPR
and fitness for purpose analysis, and
planning the next repair or ILI tool
run
326
The Journal of Pipeline Engineering
ADVERTISEMENT
Many pipeline standards and
regulations refer to fitness for service
assessments without providing much
detail as to their expected extent
or proof of adequacy. This paper
discusses measurement, modeling, and
interpretation errors that could affect the
validity of integrity assessments. A case
study identifies the uncertainty effects
of in-line inspection accuracies during
the criticality assessment of reported
metal loss anomalies that could fail by
leak or rupture. Technical approaches are
proposed on how to deal with uncertainty
in the development of integrity
verification and rehabilitation programs
when using in line inspection data.
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In 2007, the Canadian Energy Pipeline
Association (CEPA) published a report
titled ‘Integrity First’. This document
strives to achieve two goals: (1) for
the pipeline industry to communicate
performance with its stakeholders
and regulators in the areas of pipeline
integrity, health and safety, and
environmental performance; and (2) to
define performance success quantitatively
with appropriate metrics and statistics.
This paper will focus on discussing the
second goal – most specifically, on how
voluntary reporting of performance
metrics is a necessity in an era of goalbased regulations.
RAFAEL G MORA, DR. ALAN MURRAY,
JOE PAVIGLIANITI, and
SARA ABDOLLAHI
NEB, Calgary, AB, Canada
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APPLICATION OF THE ECDA
PROCESS FOR CASED PIPE
ALAN EASTMAN
Mears Group, San Ramon, CA, USA
ASSESSING PIPELINE
INTEGRITY USING
FRACTURE MECHANICS AND
CURRENTLY AVAILABLE
INSPECTION TOOLS
PY
ZIAD A SAAD, KIM J MCCAIG,
and BRENDA KENNY
CEPA, Calgary, AB, Canada
DEALING WITH
UNCERTAINTY IN PIPELINE
INTEGRITY AND REHAB
ASSESSMENT
O
INTEGRITY FIRST:
VOLUNTARY PERFORMANCE
REPORTING IN A
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REGULATORY ENVIRONMENT
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DR KIMBERLY CAMERON
and DR ALFRED PETTINGER
Exponent Failure Analysis
Menlo Park, CA, USA
Some pipeline systems are subjected
not only to internal pressure but also
to significant external loads. These
loads can well exceed the axial pressure
load and present a much greater risk
for circumferential welds and cracks.
This paper addresses the appropriate
fracture mechanics needed to assess
circumferential cracks under axial loads
and summarizes current inspection
capabilities for circumferential defects.
Specific examples from a pipeline buried
in an active landslide region are given as
well as a general review of the available
inspection tools and appropriate fracture
mechanics.
$-04&0'$0/'&3&/$&
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327
SEMENT FEATURE
EXHIBITORS
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$VEE&OFSHZ4FSWJDFT )ZESPMPHJDBM4PMVUJPOT*OD 328
The Journal of Pipeline Engineering
CAN’T ATTEND THE CONFERENCE? DON’T MISS THE EXHIBITION...
A
key feature of the conference is the
opportunity to visit one-on-one with the
leading technology suppliers in this fast-evolving
field. Exhibiting company representatives will
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for pipeline integrity management, including
ILI; pigging for cleaning, geometry, sealing, ILI
prep, and other utility applications; validation
digs, NDE and Direct Assessment; hydrotesting,
data management, leak detection, mapping,
emergency response, and repair.
507*4*55)&&9)*#*5*0/
It’s included free if you are attending the
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See the reservation form on the following page.
503&4&37&&9)*#*5*0/41"$&
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&9)*#*5*0/)0634
Tuesday, February 10, 2009 - 5:00pm to 7:00pm
Wednesday, February 11, 2009 - 9:00am to 6:30pm
Thursday, February 12, 2009 - 9:00am to 2:00pm
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EXHIBITION FLOORPLAN
10:20:41 AM
4th Quarter, 2008
321
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O &YDBWBUJPO*OTQFDUJPO"QQMJFE/%&GPS*-*%"7BMJEBUJPOBOE$PSSFMBUJPO'FCSVBSZ
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O1*1&.FNCFSTEJTDPVOUNBZOPUCFDPNCJOFEXJUIPUIFSEJTDPVOUT
1*1&.FNCFS/P____________
'PSJOGPSNBUJPOBCPVUKPJOJOH1*1&QMFBTFWJTJUXXXQJQFJOTUPSH
O"4.&.FNCFSTEJTDPVOUNBZOPUCFDPNCJOFEXJUIPUIFSEJTDPVOUT
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OR FAX or mail this form to:
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CLARION 5FDIOJDBM$POGFSFODFT5.
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1":.&/5015*0/4 DIFDLBTBQQSPQSJBUF
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Fees do NOT include accommodation. The event will be held at
Houston Marriott Westchase Hotel
2900 Briarpark Dr.
Houston, TX 77042 USA
PSt'"9
Online: www.clarion.org/marriott.php
Group Discount Code: PIPPIPA
%POUGPSHFUUPTBZ you are attending the Pipeline Pigging and
Integrity Management Conference and Courses to take
advantage of the special rate (limited availability).
Cancellations made in writing and received on or before January 19, 2009 will be refunded
less a $150 handling fee. Exhibit space cancellations must be received on or before January 5,
2009 and will be refunded less a $150 processing fee. Cancellations received after January
19, 2009 (January 5, 2009 for exhibit space) will not be refunded. The full invoice fee will
be payable regardless of whether you attend the event or not. Substitutions may be made
at any time. Confirmation will be made in writing as soon as possible upon receipt of payment.
This confirmation will be sent to the email or other address given on the registration form, unless
otherwise required. The organizers reserve the right to cancel any event due to insufficient
enrollment. In this event fees will be refunded in full.
However, the organizers assume no liability for travel or any expenses other than fees paid.
ppim09-final.indd 11
12/22/2008 10:20:46 AM
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