Design CO2 - Journal of Pipeline Engineering

December, 2008 Vol.7, No.4

ScientificSurveys Ltd, UK

ClarionTechnical Publishers, USA

Journal ofPipeline Engineering

incorporatingThe Journal of Pipeline Integrity

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Journal of Pipeline Engineering

Editorial Board - 2008

Obiechina Akpachiogu, Cost Engineering Coordinator, Addax PetroleumDevelopment Nigeria, Lagos, Nigeria

Mohd Nazmi Ali Napiah, Pipeline Engineer, Petronas Gas, Segamat, MalaysiaDr Michael Beller, NDT Systems & Services AG, Stutensee, Germany

Jorge Bonnetto, Operations Vice President, TGS, Buenos Aires, ArgentinaMauricio Chequer, Tuboscope Pipeline Services, Mexico City, Mexico

Dr Andrew Cosham, Atkins Boreas, Newcastle upon Tyne, UKProf. Rudi Denys, Universiteit Gent Laboratory Soete, Gent, Belgium

Leigh Fletcher, MIAB Technology Pty Ltd, Bright, AustraliaRoger Gomez Boland, Sub-Gerente Control, Transierra SA,

Santa Cruz de la Sierra, BoliviaDaniel Hamburger, Pipeline Maintenance Manager, El Paso Eastern Pipelines,

Birmingham, AL, USAProf. 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 Engineeringand Applied Science, St Johns, Canada

Dr Gerhard Knauf, Mannesmann Forschungsinstitut GmbH, Duisburg, GermanyLino Moreira, General Manager Development and Technology Innovation,

Petrobras Transporte SA, Rio de Janeiro, BrazilProf. Andrew Palmer, Dept of Civil Engineering National University of Singapore,

SingaporeProf. Dimitri Pavlou, Professor of Mechanical Engineering,

Technological Institute of Halkida , Halkida, GreeceDr Julia Race, School of Marine Sciences University of Newcastle,

Newcastle upon Tyne, UKDr John Smart, John Smart & Associates, Houston, TX, USA

Jan Spiekhout, NV Nederlandse Gasunie, Groningen, NetherlandsDr 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, CanadaDr Xian-Kui Zhu, Senior Research Scientist, Battelle Pipeline Technology Center,

Columbus, OH, USA

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4th Quarter, 2008 233

The Journal ofPipeline EngineeringincorporatingThe Journal of Pipeline Integrity

Volume 7, No 4 Fourth Quarter, 2008

Contents

Dr Mo Mohitpour, Andy Jenkins, and Gabe Nahas ........................................................................................... 237A generalized overview of requirements for the design, construction, and operation of new pipelines for CO2 sequestration

Professor Jos Luiz de Medeiros, Betina M Versiani, and Oflia Q F Arajo .................................................... 253A model for pipeline transportation of supercritical CO2 for geological storage

Dr Andrew Cosham and Robert J Eiber ............................................................................................................... 281Fracture propagation in CO2 pipelines

H S Costa-Mattos, J M L Reis, R F Sampaio, and V A Perrut ............................................................................. 295Rehabilitation of corroded steel pipelines with epoxy repair systems

Sidney Taylor .......................................................................................................................................................... 307In-service recoating of a 40-in crude oil pipeline in Kazakhstan

Advertisement feature: 2009 Pipeline Pigging and Integrity Management conference and exhibition ............................. 319

THE COVER PICTURE shows pipe recoating under way on a project to rehabilitate and recoat 60km of the CPCpipeline in Kazakhstan. The project is discussed in Sidney Taylors paper on pages 307-318.

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The Journal of Pipeline Engineering234

1. Disclaimer: While every effort is made to check theaccuracy of the contributions published in The Journal ofPipeline Engineering, Scientific Surveys Ltd and ClarionTechnical Publishers do not accept responsibility for theviews expressed which, although made in good faith, arethose of the authors alone.

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THE 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 andimproving pipeline integrity for oil, gas, and products pipelines. The editorial content is original papers on all aspectsof the subject. Papers sent to the Journal should not be submitted elsewhere while under editorial consideration.

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Notes

v v v

www.j-pipe-eng.comwent live on 1 September 2008

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Editorial

THE RECENT international seminar in Salvador, Brazil1,on the subject of carbon dioxide capture and geologicstorage (CCGS) gave rise to a number of interestingdiscussions as participants were updated on the latest viewsand research in this important area. CCGS - or, perhapsmore usually, CCS is a subject of widespread importanceand frequent discussion, although there seem as yet to befew solutions to either the capture or the geologic storageproblems. Some of the figures for quantities of CO2 thatwill need to be both captured and stored are breathtakingin their size, and thy are followed by unanswered questionsabout how long-term storage (is this a hundred years, athousand years, an aeon?, and who will have theresponsibility for managing the process?) is to be effected.Another interesting aspect of the event, which seems to beechoed at similar discussions around the world, was that ofthe 150 or so papers and presentations, only eight referredto the elephant-in-the-corner issue of transportation of theCO2 from the capture site to the storage site: hence the titleof this editorial.

Arguably, CCGS or CCTGS is not the right route to befollowed to reduce the effects of global warming, and thereare many other fora in which this is being debated. But ifit is accepted that CCTGS plays a part, than thetransportation aspect is huge. The sheer quantities of CO2that will need to be transported will probably considerablyexceed the amount of natural gas and crude oil that iscurrently being transported by pipeline world-wide,requiring a vast new international pipeline network to beconstructed from scratch. The deadlines being quoted forcarbon emissions reduction mean that this network willneed to be implemented in the next ten years or less, andthe pipelines themselves will be long-distance, and throughdeveloped regions where routeing will itself be a majorissue. The long-distance aspect is of particular relevance, asthe regions and strata suitable for geologic storage are all farfrom the locations where the carbon dioxide is beingemitted.

Wheres the T in CCGS?

A further aspect is associated with the fact that the gas to betransported will not be pure naturally-occurring CO2,which is currently being transported by pipeline withoutproblem in a number of places. It will be so-calledanthropogenic CO2 (i.e. man-made), and it will by nomeans be pure if its origins are power-station and industrialsources. The uninitiated might think: a gas is a gas, CO2is all around us, so whats the problem?. But CO2 is adifficult gas to move by pipeline, and even minor impuritiesmake it far more problematic.

The Journal is privileged in this issue to have been able topublish three significant papers on aspects of CO2transportation by pipeline, written by international expertswho have informed views of the issues involved. Dr MoMohitpour of Tempsys Pipeline Solutions in Canada andco-authors from TransCanada PipeLines introduce thesubject with their wide-ranging overview of the currentstatus of CO2 transportation, and some of the designaspects that it will be necessary to accommodate if large-scale CO2 pipelines are to become a reality. Following this,Professor Jose Luiz de Medeiros of Rio de Janeiros FederalUniversity and colleagues discuss two models that havebeen developed to design CO2 pipelines; taking as astarting point the McCoy model, the authors examine indetail the advantages and disadvantages of this base-case,and go on to introduce their newly-developed approachwhich they consider is more attuned to the actual situationthat will be faced by pipeline designers in this context. Theyacknowledge that this is only a step towards a fully-flexiblesolution, postulating that further work will be requiredproperly to incorporate all of the varying parameters thatare necessary.

The third paper on the general subject is from Dr AndrewCosham of Atkins Boreas in the UK and Robert Eiber ofhis eponymously-named consulting firm in Columbus,USA. This paper delves further into the technicalities ofpipeline design for CO2 transportation, and examines theissue of fracture propagation. The authors point out thatfracture propagation control will require carefulconsideration in the design of a CO2 pipeline, which maybe considerably more susceptible to long-running ductile

*2nd International Seminar on Carbon Capture and Geological Storage,Salvador, Brazil, 9-12 September, 2008. Organized by PetrobrasUniversity, Rio de Janeiro.

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fractures than natural gas pipelines. The need to preventsuch propagating fractures imposes either a minimumrequired toughness or a requirement for mechanical crackarrestors and in some situations the requirement for fracturepropagation control will dictate the design of a CO2pipeline. The issues are illustrated in examples involvingthe design of an 18-in and a 24-in pipeline, and the authorsconclude that if fracture control is considered early in thedesign, any constraints on the design can be identified and,in principle, resolved without too much difficulty.

The two further papers in this issue relate to pipelinerehabilitation. Professor Jorge Reis ad colleagues from theUniversidade Federal Fluminense at Niteroi in Brazil, inassociation with Petrobras research institution CENPES,describe their work on scientifically analysing epoxy repairsystems for carbon-steel pipelines. They conclude thatwhile composite repair systems may not be totally effectivefor certain circumstances (in particular, through-thicknesscorrosion defects), they have identified a simple andsystematic methodology for repairing leaking corrosiondefects in metallic pipelines with epoxy resins. Finally,Sidney Taylor of Incal Pipeline Rehabilitation (based inFrance, Russia, and the USA) discusses in detail arehabilitation project on the CPC pipeline in Kazakhstan,were 60km of the line has been recoated and refurbishedusing a somewhat unusual technology.

Performance of Europeancross-country oil pipelines

BRUSSELS-based CONCAWE the oil companiesEuropean association for the environment, health,and safety in refining and distribution has for the last 36years been collecting spillage data on European cross-country oil pipelines, paying particular attention to spillagevolumes, clean-up and recovery, environmentalconsequences, and incident causes. As many readers will beaware, the results of these surveys have been published inannual reports since 1971, and form a most importantstatistical record. CONCAWEs latest report, published inAugust2, covers the performance of these pipelines in 2006,and includes a full historical perspective going back to1971. The performance over the complete 36-year periodis analysed in various ways, including gross and net spillagevolumes and spillage causes, which are grouped into fivemain categories: mechanical failure, operational, corrosion,natural hazard, and third party. The rate of inspections byintelligent pigs is also reported.

Approximately 70 companies and agencies operating oilpipelines in Europe currently provide data for this annualsurvey. These organizations operate 159 pipeline systems

which, at the end of 2006, had a combined length of35,390km, slightly more than the 2005 inventory; thedifference is mainly due to corrections in the reported data.The volume transported in 2006 was 805m cum of crudeoil and refined products, a figure which has been stable inrecent years; total traffic volume in 2006 was estimated at130 x 109 cum km.

There were 12 spillage incidents reported in 2006,corresponding to 0.34 spillages per 1000km of line. This isslightly above the five-year average but well below the long-term running average of 0.56, which has been steadilydecreasing over the years from a peak of 1.2 in the mid1970s. There were no reported fires or fatalities but oneinjury connected with these spills. The gross spillagevolume was 726cum, equivalent to 0.9 parts per million(ppm) of the total volume transported: this corresponds to21cum per 1000km of pipeline, and compares favourablywith the long-term average of 57. Nearly 99% of the spilledvolume was recovered or disposed of safely.

Most of the reported pipeline spillages were small, and justover 5% of the spillages since 1971 have been responsiblefor 50% of the gross volume spilled. Pipelines carrying hotoils (such as fuel oil) have, in the past, suffered very severelyfrom external corrosion due to design and constructionproblems. Many have been shut down or switched to coldservice, and the great majority of the pipelines included inthis review now carry unheated petroleum products orcrude oil.

Half the 2006 incidents were related to mechanical failures,four to third-party activities, and two to corrosion. Over thelong term, third-party activities remain the main cause ofspillage incidents, although it has been progressively reducedover the years. Mechanical failure is the second largestcause of spillage; after great progress in reducing this duringthe first 20 years of the reviews, the frequency of mechanicalfailure has been following an upward trend since the mid1990s. Most of the European pipeline systems involvedwere constructed in the 1960s and 1970s. CONCAWEpoints out that in 1971, 70% of the inventory was 10 yearsold or less; by 2006, only 7% was 10 years old or less, and37% was over 40 years old. However, this ageing does notappear to have led to any increase in spillages.

Over the complete survey period (from 1971) the two mostimportant causes of spillages are third-party incidents andmechanical failure, with corrosion well back in third placeand operational and natural hazards making minorcontributions. Significantly, third-party incident frequencyhas been reduced progressively over the years although,having made good progress prior to 1991, it appears thatthis trend might subsequently be reversing.

In 2006, 78 runs by all types of intelligent pig covered7020km of pipeline. Most inspection programmes involved

concluded on page 292

2 Performance of European cross-country oil pipelines: a statisticalsummary of reported spillages in 2006 and since 1971. Published byCONCAWE, Brussels, www.concawe.org.

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CARBON DIOXIDE (CO2) is a colourless, odourless,non-flammable, non-toxic substance that may exist asa 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 inearths atmosphere at a current concentration level ofapproximately 370ppm (0.037%), although somewhathigher 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 hazardousto life by causing unconsciousness, failure of respiratorymuscles, and a change in the pH of the bloodstream.

CO2 may be shipped as either a gas or a liquid. Pipelinetransportation of CO2 is usually at high pressures in liquidstate or as a gas in dense phase.

International concerns over global warming continue togrow: man-made emissions of carbon dioxide have becomethe main focus of government policies, as carbon dioxideis the largest contributor to anthropogenic greenhouse gasemissions. With increasing global energy use andconsequential CO2 emissions (see Fig.1 [1]) and expectationof continuing high oil prices, CO2 capture and storage(CCS) is becoming a viable option for managing man-madegreenhouse gases.

Figure 2 indicates the percentage breakdown of sources ofCO2 emissions in the USA [1]. The inset in the figureprovides global breakdowns indicating that the level ofCO2 emission that can possibly lead to capture and use is

*Authors contact information:tel: +1 604 618 6784email: [email protected]

A generalized overview ofrequirements for the design,construction, and operation ofnew pipelines for CO2sequestration

by Dr Mo Mohitpour*1, Andy Jenkins2, and Gabe Nahas31 Tempsys Pipeline Solutions Inc, White Rock, BC, Canada2 Vice President, TransCanada PipeLines Ltd, Calgary, AB, Canada3 Project Manger, TransCanada PipeLines Ltd, Calgary, AB, Canada

OVER RECENT decades, carbon dioxide has been transported through pipelines with no demonstratedexamples of substantial leakage, ruptures, or incidents, and more CO2 pipelines are expected tobe built within the next ten years due to economic and environmental drivers (high oil prices, climate-change-related policies), for carbon capture and geological sequestration (CCS), for re-injection, and tosupport enhanced oil recovery (EOR) projects. While there are some differences between CO2transportation for EOR and CCS (such as impurities and routeing through more populated areas), if industryexperience 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 usingcaptured CO2 brings two benefits for same cost.

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largest from electrical power generation and industrialusage (cement, chemical, and pharmaceutical manufacture,etc.).

CO2 and greenhousegas emissions

CO2 is one of six anthropogenic greenhouse gases (GHGs)that have been targeted by the international community ascausing global warming. The other five man-made GHGsof concern are:

methane (CH4) nitrous oxide (N2O) hydrofluorocarbons (HFCs) perfluorocarbons (PFCs), and sulphur hexafluoride (SF6)

Carbon dioxide (CO2 ) is a combustion by-product offossil fuels (oil, natural gas, coal) that are used for electricityproduction, transportation, heating, and industrialapplications. It is also released when solid waste, wood, andwood particles are burned.

Carbon dioxide capture and storage is a process for reducing

Fig.1. Trend in global energy use and CO2 emissions [1].

Fig.2. Breakdown of the causes of CO2 emission.

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Fig.3. CO2 and greenhouse-gas emission chronology.

Table 1. CO2 safety profile [3].* National Institute for Occupational Safety and Health.

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GHG emissions into the atmosphere by first extractingCO2 from the gas streams typically emitted during electricityproduction, fuel processing, and other industrial processes.The CCS process involves three stages: gathering of theCO2 from emitting sources or CO2-rich reservoirs,transmission of the CO2 to the storage site, usually bypipeline, and injection of the CO2 into the geologicalreservoir.

Awareness of greenhouse-gas emission goes as far back as1896 when Svante Arrhenius (18591927), a Swedishscientist, postulated that fossil fuel combustion mayeventually result in enhanced global warming [2]. Heproposed a relation between atmospheric carbon dioxideconcentrations and temperature that is the forefather ofpresent-day CO2 emission calculations. The chronology ofCO2 and GHGs is indicated in Fig.3.

Safety data andphase characteristics

CO2 is essential for life, being a critical component inphotosynthesis. As an example of this, greenhousespurposely elevate CO2 levels in order to fertilize theplants they contain.

At low concentrations (1% by volume), CO2 causes no illeffects on humans, fauna, or flora. At concentrations ofabout 6% by volume, CO2 can cause nausea, vomiting,diarrhoea, and irritation to mucous membranes, skinlesions, and sweating. At about 10% by volume, it causeasphyxiation, Table 1 [3].

CO2 is a fluid with unusual properties. Its phase diagramis illustrated in Fig.4 [6]; CO2s triple point and criticalpoints respectively exist at 0.52MPa (5.2bar), -56.6oC, and7.38MPa (73.8bar), +31oC. The line connecting the twopoints is the vapour-liquid line separating the gaseous andliquid phases. The triple-point CO2 exists as one of thethree phases: solid, liquid, or gas.

The properties of CO2 are unusual compared to otherfluids transported through pipelines. For example pipelinetemperatures for methane are generally above the criticalpoint of methane, and therefore no phase change would beexpected to occur during the transportation. Oil pipelinesalso operate at pressures lower than the critical point, andtherefore produce no phase change.

It is important to avoid phase changes during pipelineoperation. However, as the critical point for CO2 is closerto the pressures/temperatures that may be encounteredduring pipeline operation, the design and operation of

Fig.4. Phase diagram for pure CO2 (after refs 4 and 5).

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CO2 pipelines are more complicated than that for otherfluid-transportation pipelines. To avoid phase changes,therefore, CO2 is generally transported in the temperaturerange 4-24oC [7].

CO2 pipelinemilestones and experience

World experience of CO2 pipelines is about 7500km, ofwhich 6000km (3700miles) are mostly large-diameter andoperational in the USA. The oil industry uses CO2(currently, mostly in pure form) for enhancing oilproduction. CO2-enhanced oil recovery (CO2-EOR) iscurrently employed in the USA and Canada, Turkey, andTrinidad and Tobago as well as Brazil. Of the 74 globally-active facilities, 70 are in the USA (administered by 27operators).

The following highlight achievments in EOR and CCS, aswell 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 frompower plants

1972: construction of the first onshore CO2transmission pipeline (Canyon ReefCarriers)

1972: first major CO2 flood (in ScurryCounty, Texas)

1979-1989: major naturally-occurring CO2discovered (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 projectsand, as indicated, many of these pipelines have beenoperating since the early 1970s.

From the offshore perspective, Snohvit (in the Norwegiansector of the North Sea) is the field with the (first) offshoreCO2 transmission pipeline. Since 1996, Statoil (Norwaysstate-owned oil company) has been injecting carbon dioxidefrom a by-product of natural gas recovery into a 32,000-sqkm aquifer 800m below the floor of the North Sea in thisfield (also known as the Sleipner field [5]). This innovativeapproach to greenhouse gas reduction was spurred in 1991by a government-imposed carbon tax on all carbon emissionsfrom extraction activities on Norways continental shelf. In

Fig.5. Typical thermodynamic path forcompression, cooling, and pipelineoperation for CO2.

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order to avoid a NOK 1-million/day penalty, Statoildeveloped a carbon capture, transportation, and injectionscheme that stores the carbon dioxide in the undergroundaquifer once it has been removed from the natural gas.

From an onshore perspective, transportation, injection,and storage of CO2 in the last 36 years has mostly beenfrom underground natural deposits/reservoirs such asthose located in Colorado, USA. A typical system includesCO2 gathering, CO2 dome fields, and processing (waterremoval/dehydration, compression, as CO2 from naturalsources is water saturated). Therefore CO2, after beinggathered from wells, is conditioned (through three-phaseseparators) and then compressed. A considerable amountof water is condensed during the first and secondcompression cycles, followed by removal of water by amineabsorbers and subsequently further compressions to assurewater-free and dry CO2 prior to pipeline transportation inliquid form, Fig.5 [8].

Table 2 and Figs 6 and 7 summarize the major CO2pipelines operating in North America, many of which havebeen operating since the early 1980s, with the CO2 beingtransported at over 2500psi as a supercritical or dense-phase fluid in the economically-preferable state [8].

North Americanregulatory oversight

Existing CO2 pipeline facilities have been designed tomeet current gas and/or oil pipeline system codes and

standards, and no specialty fluid-transmission code isapplicable or available. CO2 pipelines were unregulateduntil 1986; however, ASME/ANSI B31.4 and B31.8 aregenerally applicable, as appropriate.

In the US, CO2 pipelines are regulated by the USDepartment of Transportations (DOT) Code of FederalRegulation (CFR ) Section 195 Liquids Pipelines (for thetransportation of CO2 in Liquid Form). Under US DOT CFR195, CO2 is regulated as a hazardous material and carbondioxide.

In Canada, the Natural Resources Code, Chapter 117,Hazardous liquids or carbon dioxide pipeline transportationindustry, 2005, as well CSA Z662, 2007, apply.

CO2 pipelines are considered high volatile/low hazardand low risk facilities. However, the US DOT consistentlyhas adopted the language of hazardous materials andcarbon dioxide. This means that a higher level of inspectionis required for CO2 pipelines than for crude oil pipelines.

Regulations specifically call for 26 inspections (generallymonitoring of pipeline rights of way) per year. CO2 isclassified as a Class L material, in other words highlyvolatile, non-flammable, and non-toxic. No judgment ismade on CO2 as a safety risk.

There is a specific call to mitigate fracture propagation witha fracture arrestor. Generally, fracture arrestors are specifiedwhere materials do not have sufficient toughness to arrestrunning fracture. Valve material compatibility in CO2service is also a requirement.

Table 2. Major North American CO2 pipelines.

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Because CO2 is being treated as hazardous, but not declaredhazardous, all the review requirements for high-riskhazardous pipelines apply in the US if the pipeline isgreater than 457mm (NPS18), or passes through a populatedarea; the term populated area means a population densitygreater than 1,000/square mile (400/sqkm). However froma Canadian regulatory perspective, the following areapplicable:

All CO2 pipeline applications are subject to amandatory review by regulatory bodies to ensuretechnical completeness and operational safety.

Since CO2 is non-toxic, no specific requirementsfor setbacks, emergency response planning (ERP),or leak detection are required.

Because CO2 is heavier than air and tends toaccumulate in low areas (ventilation is poor), pipeline

operators are required to be trained in safe workingprocedures in oxygen-deficient atmospheres as wellin the handing of fluids that undergo phase changesunder pressure (asphyxiation occurs atconcentrations greater than 5%).

Inspection requirements (every five years) includesmart pigging (which is difficult in CO2 pipelines)and direct assessment.

From a governmental policy point of view, specific legislativeproposals are being reviewed that reflect the currentperception that CO2 capture probably represents the largesttechnological hurdle to implementing widespread CCS,and that CO2 transportation by pipeline does not presentas significant a barrier. While these perceptions may beaccurate, industry and regulatory bodies are identifyingimportant policy issues related specifically to CO2 pipelineswhich may require government attention [10].

Fig.6. Major CO2 sources and pipeline locations in North America.

Fig.7. US pipeline laterals, and theCanadian distribution system [9].

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Overall design andinstallation considerations

The pipeline industry requires that CO2 transmissionsystems be designed and constructed at optimal cost, bearingin mind that they must be safe, reliable, and have minimalimpact on the environment and the general public. This isachieved by consideration of a number of factors, includingthose of design and installation as indicated in Fig.8.

From a hydraulics point of view, CO2 composition/purityand characteristics (see Fig.4) impact system design andhence pipeline operation. These components affect thefollowing, which in turn affect pipeline capacity andoperational requirements:

density/specific volume viscosity specific heat (at constant pressure and constant

volume) compressibility enthalpy/entropy conductivity

An example of variation of density with temperature forpure CO2 is given in Fig.9; it is significant to note the non-linearity of these properties at normal pipeline operatingtemperatures and pressures [8].

Other factors affecting the design or operation of CO2pipelines are:

impurities/sensitive properties water content CO2 concentration thermodynamic characteristics dense-phase handling

leak tests pigging slinky and water-hammer effects safety considerations

CO2 composition drives pipeline design, and the followingcompositions are typical of the CO2 that is generallytransported through pipelines from CO2-rich fields:

CO2: 98.372% 98.350% N2: 1.521% 0.136% CH4: 0.107% 1.514% H2S: 0.000 (approx.)

A typical CO2 pipeline quality specification for enhancedoil recovery (EOR) is indicated in Table 3.

Excessive water content in CO2 can cause formation ofhighly-corrosive carbonic acid, levels of between 18 and30lb/MMscf (288480 mg/m3) of which are accepted byindustry for CO2 transmission in carbon steel pipelines.

Effect of impurities

Impact on pipeline capacity

CO2 impurities significantly affect pipeline design, and inparticular the system capacity. Impurities influence thevapour pressure of CO2, and thus affect the pipelinescapacity and its facilities capabilities and design. The affectof composition of CO2 on the phase diagram is shown inFig.10, and the influence on a typical pipeline capacity isshown in Fig.11. Impurities generally open-up the CO2gas/liquid bubble (i.e. increase the area of two-phase region,Fig.10), and move the critical point, thus affecting thevapour pressure and temperature. Generally, the criticalpressure increases, but the critical temperature decreases asthe level of impurities is increased or changed. This, in

Fig.8. Overall design and installationconsiderations for CO2 pipelines.

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turn, affects the operating range of a pipeline and the wayCO2 is transported (in liquid rather than supercriticaldense phase, for instance).

For a given pressure drop, the presence of impuritiesmarkedly reduces the pipeline capacity (Fig.11) as theyaffect the operating region; it has been shown that thereduction in capacity is more significant at larger diameters[7].

Centrifugal pumps are used to transport CO2 at liquiddense-phase or supercritical conditions. The advantages ofsuch pumps are their lower cost, better efficiency, higherreliability, and good operating flexibility. CO2 impuritiesaffect pump design, however. In order to prevent cavitation,

the minimum pump suction pressure must be set higherthan the fluid vapour pressure. A high pump suctionpressure requires a correspondingly-higher maximumoperating pressure so that optimum station spacing andflow rate can be attained. Alternatively, pump stations haveto be spaced closer than required to meet the required netpositive suction head (NPSH).

Impact on fracture control properties

A propagating ductile fracture is driven by fluid pressurewhich acts on the unrestrained walls of a fractured pipe. Aductile fracture will not propagate if there is insufficientenergy in the system to overcome resistance to thepropagation of the fracture. Decompression characteristics

Fig.9. Density variation of CO2 with temperature (a property significant in pipeline flow computations).

stnenopmoC tneserP% leveLlevelrofnosaeR

nrecnoc

2OC 59 niMytilibicsimmuminiM

*)PMM(erusserp

negortiN 4 xaMytilibicsimmuminiM

*)PMM(erusserp

nobracordyH 5 xaMytilibicsimmuminiM

*)PMM(erusserp

retaW m/gm084 3 )FCSMM/bl03( xaM noisorroC

negyxO )mpp01(100.0 xaM noisorroC

S2H )mpp002-01(20.0-10.0 xaM ytefaS

locylG m/lm40.0 3 )FCSMM/lagSU3.0( xaM snoitarepO

erutarepmeT 56 oC xaMgnidulcni(lairetaM

)gnitaoc

Table 3. Pipeline quality CO2 (*dueto minimum miscibility pressure)requirement for EOR use only.

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of liquid or dense-phase CO2 lead to a high vapourpressure during decompression, and this results in a highdriving force at the crack tip concentrating large stresses inthe hoop direction at the fracture tip, similar to natural gaspipelines (Fig.12).

CO2 pipelines, as natural gas pipelines, are susceptible torunning ductile fractures [11]. The pipeline has to fail firstfor fracture propagation to be an issue: when a CO2pipeline is burst (mostly due to external forces or corrosion),high vapour pressure can prevent rapid depressurizationwhich, in turn, can cause a propagating ductile fracture.The arrest of propagating ductile fractures is an importantcriterion that needs to be considered when designing CO2pipelines. The fracture-arrest criterion stipulated by Battellestates that ductile fractures will not propagate if the pipelineis designed such that:

3 332

241. cos exp

d

f

NE>

where:

ddP D

t=

2

andE

EC

ADt

Nv

f

=

2

12

2A = area beneath Charpy notch (m2)C

v= material Charpy notch toughness (J)

D = pipe outside diameter (m)E = Youngs modulus of elasticity (Pa)E

N= normalized toughness parameter

Pd

= decompressed pressure (Pa)

t = pipe wall thickness (m)

d= decompressed pipe hoop stress (Pa)

f

= pipe steel flow stress

y= yield stress (MPa)

Examination of the fracture-control equation indicatesthat the pipe flow stress

f has to be equal to or greater than

the decompressed hoop stress d by a factor of 3.33 to

ensure avoidance of ductile fracture propagation in CO2pipelines [11]. Alternatively, the pipe toughness, strength,or wall thickness has to be increased to satisfy the conditionfor no ductile fracture.

As indicated above, impurities drag the phase envelope tothe left, Fig.10, and impurities cause a lowering of thecritical pressure and, generally, temperature. The phaseboundary determines the vapour pressure; this sets thedecompression pressure at a pipeline break or rupturewhich, in turn, decides if a ductile fracture will occur ornot. Cosham and Eiber [12] indicate that the increase inimpurities in CO2 will require pipes having a higher wallthickness or toughness to arrest a ductile fracture.

Salient design andoperational considerations

Some of the special features of CO2 that need to be takeninto account in any pipeline design include [8, 13]:

The need to dehydrate the CO2 stream to reducecorrosion.

Some petroleum-based and synthetic lubricants can

Fig.10. Phase diagram showing the influence of impurities on CO2.

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harden and become ineffective in the presence ofCO2.

Supercritical CO2 can damage some elastomersealing materials. Elastomers are permeable to CO2,and a pressure release may cause explosivedecompression and blistering. The solution isgenerally to control the rate of decompression, or atleast the number of decompression cycles, and tochoose a high Durometer elastomer (> 90) elastomerthat has a solubility rating farthest from CO2.

Viton valve seats and Flexitallic gaskets are typicallyspecified in the USA for CO2 pipelines.

CO2 cools dramatically during decompression, sopressure and temperature must be controlled forroutine maintenance.

Dry CO2 has poor lubricating properties whichrequire special design features for compressors,pumps, and traps, etc.

The pipeline needs to be designed to minimize the

potential for flow transients, known as waterhammer by including some surge capacity.

Other factors include:

a provision to reduce the possibility of brittle fractureand ductile fracture propagation. Lower-grade steel,higher wall thickness and/or toughness;alternatively, installation of fracture arrestors canbe implemented.

assessments of high-consequence areas underpipeline-integrity management programmes.

The thermodynamic characteristics of CO2 make pressureand temperature ranges critical in pipeline operation.Blow-downs (Fig.13 [14]) and pipeline loading must becontrolled over significantly-longer times than in normalnatural gas pipeline procedures, to prevent excessively-lowtemperature gradients.

CO2 has significant mass, and therefore its release at highpressures is noisy, cold, and powerful. Depressuring CO2from pipeline-injection pressures to atmospheric pressurecan result in auto-refrigeration temperatures of -90C, and

Fig.11. The effect of impurities onpipeline capacity (based on 82.7kPa/km pressure drop at 10341kPa in anNPS 16 pipeline at 16oC).

Fig.12. Ductile and brittlefracture outcomes.

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this will require the use of flare pre-heaters as well as low-temperature materials. Blow-downs are sized for blowingdown a 32-km section of pipeline in 6-8 hours to avoid dryice formation.

CO2 pipelines are equipped with scraper traps, Fig.14.However, the industry has significant problems with piggingCO2 pipelines when using rubberized material for the pigscomponents. Pipeline pigging in CO2 service is also difficult

Fig.13. Blow-down of a pure CO2 pipeline [14].

Fig.14. Scraper traps in a typical CO2 pipeline application.

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without the aid of a precursor lubricant such as diesel,because dry CO2 has very poor lubricating characteristics.Industry experience indicates that, after pipelinecommissioning, the use of scrapers is redundant as verylittle moisture drops out.

Piping design, Figs 15 and 16, for CO2 operation generallyconsiders the following:

Meter runs require insulation as a 1F (0.5C)temperature differential can swing pressures by upto 20psi.

Orifice plates (with a 0.400-in pressure transmitterconnected to a flow computer) are used for CO2flow measurement.

Meter runs are typically equipped with differentialpressure and temperature recorders as well as adensitometer. A pressure-relief system is also added.

CO2 pipeline operationalsafety considerations

Incidents related to CO2 pipe operation are rare. The USDOTs Office of Pipeline Safetys statistics for the period1994 to 2000 on pipeline incidents in the USA show nosignificant statistics on CO2 pipeline incidents. Consideringthe number of CO2 pipelines, it can be concluded that thenumber of incidents is lower than for hazardous liquidpipelines in general. There were no injuries or fatalitiesassociated with incidents on CO2 pipelines that have beenreported, and the cost of the resultant property damage wassignificantly less than for hazardous liquid pipelines.

The only incident of significant importance relates to CO2release from a non-pipeline source. In August, 1986, atLake Nyos in Cameroon, West Africa, a volcanic crater lakereleased a large volume of CO2 (Fig.17 [15]). This was nota volcanic eruption, but a gas burst. A natural release of

Fig.15. Typical CO2 orifice meter run (for custody transfer).

Fig.16. Typical station block-valve arrangement.

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between 80 million and 1 billion cum of CO2 was recorded.Being denser than air, the CO2 failed to disperse, andflowed down into nearby populated valleys, resulting in thedeaths of about 1700 people.

In comparison 10km of NPS 12 pipeline contains about380 million cum of CO2 (at standard pressure andtemperature, operating at 15.3MPa and 20oC) which isabout 210 2600 times less than the Lake Nyos incident[16]. For a 32-km section of NPS 36 pipeline, this is equalto about 9 million cum. The best practice for CO2 pipelinedesign thus includes, but is not limited to, selecting sitesand methods that reduce the probability of accumulationresulting from leakage or injection well failure.

Best site selection practices would involve selecting a siteaway from populated areas and, if indoors, having sufficient

ventilation to prevent accumulation. An additional measureto reduce risk could include adding chemical odorants, likethose added to natural gas, which help in detecting leaksespecially around more populous areas. This technique hashad a positive impact on leak detection at the Weyburnfacility and its supplying pipeline [17].

Public safety is the top priority in any pipeline emergencies.Emergency is defined as any unforeseen combination ofcircumstances or disruption of normal operating conditionsthat poses a potential threat to human life, health,environment, or property if not contained, controlled, oreliminated. The two primary operational safetyconsiderations for CO2 facilities are therefore:

to avoid suffocation in areas where CO2 may beblowing-down, leaking, and displacing oxygen(especially in enclosed or low-lying areas); and

to exercise extreme caution when operating ormaintaining high-pressure CO2 facilities due to thecompressibility and potentially-violent expansion(150 to 1) of CO2 as it changes phase.

A typical dispersion of a CO2 vapour cloud after releasefrom a pipeline is shown in Fig.18 [3]. With reference toTable 1, staging areas for responding to emergencies duringa rupture can be identified. This allows for an organizedresponse to the release, including proper siting of emergency-response personnel and equipment, and safe and effectiveperformance of necessary work. Typical modelling for CO2source characterization and dispersion can be made usingcommercially-available software such as BPs CIRRUS.

Fig.18. A typical CO2 cloud after release from a pipeline (after Ref. 3).

Fig.17. CO2 release from volcanic eruption, Lake Nyos,Cameroon [15].

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Conclusions There are already in existence long-distance CO2

pipelines and also networks of CO2-distributionpipelines.

Most existing pipelines are mainly sited in areas oflow to medium population densities.

There is a significant knowledge base, developedfrom the experience gained from 36 years ofoperation and regulation of the existing CO2pipelines by operators and regulatory bodies. Thisknowledge and expertise is available whenconsidering the development of new CO2 pipelinesand networks.

Over this 36-year period, CO2 has been transportedthrough pipelines with no demonstrated examplesof substantial leakage, rupture, or incident.

More CO2 pipelines are expected to be built withinthe next decade due to the economic andenvironmental drivers (high oil prices, climate-change-related policies) for carbon capture/geological sequestration, for re-injection, and tosupport enhanced oil recovery projects.

While there are some differences between CO2transportation for EOR and CCS (such as impuritiesand routeing through more-populated areas), ifindustry experience and best practice are followed,there would seem to be little reason to be concernedabout the design, construction, operation, or safetyof CO2 pipelines for CCS.

CCS for EOR using captured CO2 brings twobenefits for the same cost.

Incentives should be designed to be revenue-positiveto government.

AcknowledgmentsThis paper is based on a continuing programme byTransCanada Ventures for the transmission of CO2 bypipeline.

Thanks are due to TransCanada PipeLines Ltdsmanagement for permission to publish this paper. Reviewsconducted by Dr H.Golshan (TransCanada) and DrA.Cosham (Atkins Boreas) are gratefully acknowledged.

References1. M.Mohitpour, 2008. Energy supply and pipeline

transportation challenges and ppportunities. ASME Press.

2. H.A.M.Sneiders, 1970. Arrhenius, savante august. Dictionaryof Scientific Biography.

3. A.Turner, J.Hardy, and B.Hooper, 2006. Risks associatedwith a CO2 pipeline: methodology and case study. GHGT8,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 bypipeline and storage in saline aquifers and oil reservoirs. PhDThesis, 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 34thSession, 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 captureand storage: the impact of impurities on supercritical CO2pipelines. Proc..ASME 7th International Pipeline Conference,Calgary Alberta, Canada, Sept 29-Oct 3, IPC2008-64063.

8. M.Mohitpour, H.Golshan, and A.Murray, 2007. Pipelinedesign and construction a practical approach. 3rd edn,ASME Press, New York.

9. K.Havens, 2008. CO2 transportation. Indiana Center forCoal Technology Research, June 5, http://www.purdue.edu/dp/energy/pdfs/CCTR/presentations/Havens-CCTR-June08.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 Conferenceand Exhibition ( ETCE), Houston, Texas, Jan 18-22.

12. A.Cosham and R.J.Eiber, 2008. Fracture control in carbondioxide pipelines the effect of impurities. Proc..ASME 7thInternational Pipeline Conference, Calgary, Alberta, Canada,Sept 29-Oct 3, IPC 2008-64346.

13. A.Jenkins and M.Mohitpour, 2008. Design, constructionand operation of new pipelines for CO2 sequestration: anoverview of technical requirements. 2nd PetrobrasInternational Seminar on CO2 Capture and GeologicalStorage, 9-12 Sept, Salvador, Brazil.

14. Kinder Morgan, 2006. CO2 transportation. Presented atWorld Resources Institute, February 28.

15. K.Krajick, 2003. Defusing Africas killer lakes. Smithsonian,34, 6. 46-55.

16. J.Dillon, 2008. Status of CO2 capture and sequestration inCanada. Hatch Energy Presentation, May 19.

17. J.Gale and J.Davison, 2002. Transmission of CO2 safetyand economic considerations. IEA Greenhouse Gas R&DProgramme, presented at the GHGT-6 Conference, Kyoto,Japan, October. http://www.usea.org/CFFS/CFFSErice/Presentations-Remarks/Kaarstad%201430.pdf.

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September 22-24

2009

RioPipeline

2009

RioPipeline

Presentation of 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 mini-courses 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 instruct ions avai lable at the event s i te . Access: www.riopipeline.com.br

Themes

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)

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.

Instructions for sending Abstracts/Final Papers

Official language of the event:

English

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

20/01/2009 Deadline to receive abstracts(new date) (100 - 500 words)

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)

Further information:Ldia BairrosPhone.: (55 21) 2112-9077E-mail: [email protected]

The abstracts must be submitted until , according

to instructions available at Rio Pipeline 2009 website.

thJanuary 20 , 2009 (new date)

www.riopipeline.com.brwww.riopipeline.com.br

OrganizationParticipation

Call for Papers

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*Authors contact information:tel: +55 21 2562 7535e-mail: [email protected]

A model for pipelinetransportation of supercriticalCO2 for geological storage

by Professor Jos Luiz de Medeiros*, Betina M Versiani,and Oflia Q F Arajo

Escola de Qumica, Federal University of Rio de Janeiro, Ilha do Fundo,Rio de Janeiro, RJ, Brazil

IT IS recognized in many broad circles as well as in restricted ones that cumulative emissions ofgreenhouse gases (basically CO2) are gradually and dangerously contributing to a measurable andconcrete anthropogenic interference of the global climate system. From the viewpoint of the currentcentury, CCGS carbon capture and geological storage is being considered as the most serious responseby industry for mitigating the effects of emissions of fossil carbon into the atmosphere. CCGS demands theco-operative intervention of three technologies: (a) capture and compression of CO2 from large industrialsources; (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 thesecond of these three legs transport of CO2 via high-pressure and high-capacity pipelines is provento be a reliable and feasible technology in the CCGS tripod.

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 economicestimates, and ample scope of the investigation. Nevertheless, the pipeline model proposed in this studyhas made certain simplifications which may compromise some of its results in view of the characteristicsof the flow.

In this context, the present work addresses a modelling and simulating resource capable of generatingquantitative responses concerning CO2 transportation issues in the CCGS scenario. The authors presenthere a rigorous pipeline model for transportation of CO2 in the supercritical state, and demonstrate its usefor simulating CO2 transportation to an appropriate geological formation for storage. This model takes intoaccount the physical parameters of supercritical CO2 within a rigorous stationary high-density compressibleflow framework. The features of this model include: (a) high-density supercritical thermodynamic andtransport properties; (b) correct topographic effects (i.e. gravitational compression and expansion of thefluid and respective thermal consequences); (c) heat transfer effects according to temperature distributionsin the soil and in the injection column; and (d) the ability to incorporate multiple machine stations such asbooster compressors, exchangers, and recovery turbines. The model was designed for engineeringapplications involving pipelines which transport dense supercritical CO2 either in its pure form, or inmixtures with other gases and fluids.

ENVIRONMENTAL CONCERNS NOWADAYS focuson atmospheric CO2 levels which have steadilyincreased from a pre-industrial level of 278ppm to thecurrent 379ppm. It is estimated [1] that the current level of

global greenhouse gas emissions has reached 50 Gt/yr (50x 109 metric tons per year), of which 60% corresponds toCO2 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 ofwhich is generated in the USA), is the main contributor toindustrial fossil carbon emissions, particularly by coal-firedplants in the northern hemisphere [1].

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As a result, if human energy supply remains fossil-carbon-based, and with the expected growth of population as wellthe understandable expectations of rising living standardsand energy usage, cumulative greenhouse CO2 emissionsmay contribute what is being called a dangerousanthropogenic interference to the climate system. The keyfactor behind for this is the global mean temperature rise(GMTR) above pre-industrial levels; measurements of theGMTR and its forecasts according to several scenarios offossil carbon emissions can be found in specialized sources,such as the IPCC AR4 [2].

As shown in Ref.1, and according to the IPCC summary,achieving the European Unions target of long-termstabilization of no more than 2oC of GMTR would requirea constant deceleration of emissions such that a reductionbetween 50% and 85% of the carbon emissions in 2000could be obtained by 2050. If, instead, long-term stabilizationis projected at 3.3oC of GMTR, a milder deceleration ofemissions will be required, leading to a level of emissionsequivalent to 2000 by 2050.

In this context, CCGS carbon capture and geologicalstorage is being considered as the most viable (projected)response by industry to the mitigation of CO2 emissionscarrying fossil carbon. CCGS demands the co-operativeintervention of three technologies: (a) the capture andcompression of CO2 from large industrial sources; (b) thetransportation of the CO2 from the sources to feasiblegeological sinks; and (c) geological injection and geologicalretention of the CO2.

As explained in Ref.1, CCGS was devised as a bridgetechnology that will be superimposed on currenttechnologies 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 alayer of costs to any current technology for energyproduction, thus decreasing the economic efficiencies ofall plants and increasing the cost of electricity (COE) inUS$/MWhr. It is expected that the capture step alone willadd about $10-30/MWhr to a current COE of about $40-60$/MWhr [1].

As can be seen, if CCGS is to become a reality, a simpleapproximation shows that a target of 10 Gt of CO2 willhave to enter into the CCGS conveyor chain every year.

Capture and compression of CO2

The capture and compression of CO2 is briefly describedhere as it will be probably responsible for the majorcontributing slice of the total CCGS cost per unit of CO2.Capture and compression also impacts all subsequent stepsin the CCGS chain because it affects the composition ofthe fluid to be transported to the site of geo-injection. Thefluid composition, by its turn, defines properties likecompressibility, viscosity, vapour-liquid equilibrium (VLE),and the potential for corrosion, all of which are factors

affecting the transportation costs. Composition is alsoimportant if the geological destination of the fluidcorresponds to applications in enhanced oil recovery (EOR)since, in this case, the purity of the CO2 is a relevant factor.

Capture and compression of CO2 is accomplished accordingto one of the three main processes shown in Fig.1:

(a) post-combustion capture, where fuel is burned withair, by the usual means, followed by the separationof CO2 from the flue gases;

(b) pre-combustion, where CO2 is separated after theconversion of the fuel into a carbonless fuel (i.e.H2);

(c) oxyfuel combustion, which occurs with pure O2 instoichiometric proportion, leading to a flue gashaving only H2O and CO2, the last being easilyseparated as a pure stream.

In terms of the probable contaminants, CO2 from oxyfuelcombustion (such as with natural gas), post-combustion,and pre-combustion systems, could be carrying smallcontents of, respectively, CH4/N2, N2, and H2.

The (total) cost of capturing and compressing CO2 rangesfrom $10 to $60 per ton of CO2, according to the planttype and other operation factors [3]. To estimate this cost,it must be noted that, in general, all alternatives in Fig.1 aretechnically well understood; it is probable that most of thecomponent activities can be found successfully operatingfor many years as parts of other chemical- and energy-production processes. Nevertheless, the three above-mentioned alternatives have not yet been proved at thescale required.

Geological injection and retention of CO2

The existence of enormous geological formations geo-sinks appropriate for CO2 storage is the decisive factorwhich supports (and formerly suggested) CCGS initiatives.But, on the other hand, as commented in Ref.1, thetheoretical capacity of geological formations as sinks forCCGS is uncertain. In spite of this, it is easy to see thatthere is, at least, a capacity of the same order of size of allknown (depleted or not) reserves of fossil carbon. Estimatedworld 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 oilreservoirs (to improve flow and recover more oil), and intocoal veins (to displace and recover methane).

Geo-sinks appropriate for CO2 storage are basicallyassociated 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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caverns in deep saline veins.

There is thus an obvious correlation between the discoveryof geo-sinks and the exploration of oil, gas, and coal. If ageo-sink is not a coal bed or a depleted oil-gas reservoiritself, there is little surprise that its discovery has occurredduring drilling in oil-, gas-, and coal fields.

Although EOR (and ECBM) operations provide an apparentCCGS paradox of using fossil carbon to get more fossilcarbon, they are considered valid CCGS destinationsbecause the coefficient expressing barrels of oil recoveredper ton of CO2 injected is both economical and CCGSfavourable. A little exercise with numbers can show this: ingeneral, EOR operations can be considered very attractiveif one ton of injected CO2 (priced, say, at the capture costof $10-60 per compressed ton or less) leads to, at least, onebarrel of recovered oil (priced, at the present time, at $80per barrel or more). In this context, Ref.1 presents EORresults for four field cases (Purdy-Northeast, SACROC,Ford-Geraldine, and Joffre-Viking), showing that, at theend of injection campaigns (respectively 9, 22, 5, and 15years), approximate recovery coefficients of 0.8, 1.3, 1.6,and 1.4 (in barrels recovered per ton of injected CO2) wererespectively obtained. Thus, it is not far from reality if weassume a conservatively typical EOR coefficient of 1 barrelof recovered oil per ton of injected CO2 (a rule of thumbin 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 ofinjected CO2 will generate less than 0.3 tons of new CO2after the complete oxidation of the recovered oil. So, EORmay be also profitable on the carbon scale of CCGS if atleast 30% of the injected CO2 remains geologically stored.

The capacity and location of geo-sinks affects CCGSfeasibility as a whole, due to their direct impact ontransportation planning, investment, and cost. It isconceivable, for instance, that CO2 would have to betransported over large distances because more distant sinkscould be more adequate destinations than nearby formations[1]. The adequacy of a particular candidate geologicalformation 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 ofinjection per well, and

safety and infrastructure concerns.

For instance, based on existing information on EORprocesses, a typical injection well in a EOR field has a depth

Fig.1. CO2 capture and compression process routes (adapted from Ref.1).

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between 1000-3000m, reservoir pressure between 100-200bar, and is usually fed with 10-50 ton CO2 per day.

Transportation of CO2

An efficient CO2 transportation system will be required toaddress the mega-assignments of transport in the CCGSscenario. In spite of the existence of many options fortransporting compressed (gas or liquid) CO2 from sourcesto geo-sinks including highway tankers, railway tankers,ships, and pipelines it is evident that the impressivetonnages that must be transported to make CCGS feasiblewill dictate that only pipelines working at high pressure andhigh capacities are suitable for the job. For instance, 2-3Mt/yr of CO2 have to be transported to dispose of theentire production of a single 500-MW coal-fired powerplant; this corresponds to transporting 230-350t/hr ofCO2, just to service a single, medium-sized, client. Lookingat the big picture this means, undoubtedly, that only anetwork of large-scale pipelines could provide viableoverland transport of massive flow rates of CO2.

In comparison to the aspects of CCGS already discussed,there is some industrial experience with pipelinetransportation 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 forEOR processes in the USA and Canada [1]. A legendaryexample (perhaps the largest and longest CO2 pipeline inthe world) is the 808-km long, 30-in diameter, CortezPipeline transporting 13Mt/yr of CO2 from Colorado tooilfields in Texas, USA.

From these real cases, and from the considerable experienceof the pipeline industry with high-pressure, long-distance,transport systems for products such as natural gas, a costestimation procedure for the pipeline transportation ofCO2 is possible. Nevertheless, the literature presents onlyfew studies addressing engineering, cost, and maintenanceof CO2 pipelines in detail, basically concentrating on rules-of-thumb for sizing CO2 pipelines, and correlations forcost estimates, corrosion monitoring, and corrosion counter-measures [1].

Reference 1 presents an extensive engineering and costmodel for CO2 pipelines. From the projected flow rate andrelated information, this model can design the basicgeometric parameters of rectilinear pipelines and estimatecapital costs and operation and maintenance costs (O&M).Since the classes of operating pressures for CO2 pipelinesare the same as for natural gas, the capital costs were basedon a regression analysis over published project costs ofnatural gas pipelines in the USA between 1995 and 2005.The data was treated in order to convert all values to 2004dollars using the Marshall and Swift equipment cost index.

Based on historical O&M data for a 480-km long CO2pipeline with no booster compressor, McCoys modelprojects a fixed O&M coefficient of $3,250/yr/km (per

year and per kilometre of pipeline) in 2004 dollars. Similarestimates were proposed for other O&M contributions foreach item, such as booster compressors.

The base-case in McCoys study considers a 100-km pipelinewith no booster compressor, no elevation change, groundtemperature of 12oC, minimum outlet pressure of 103bar,and inlet pressure of 138bar. This proposed pipeline extendsacross the Midwest of the USA with a transportation targetof 5Mt/yr of CO2. The model designed the line with adiameter of 16in (390mm). This analysis also reports acapital cost of $36 x 106 and O&M of $0.325 x 106 per year.Considering a annualized fixed cost of 15% of capital, theunitary total cost of this transport reaches only $1.16 perton of CO2 per 100km. Applying a Monte Carlo sensitivityanalysis, McCoy [1] determined a range of $0.75 to $3.56per ton of CO2 for this cost, recommending the medianvalue of $1.65 per ton of CO2 (per 100km) as a suitablerepresentative estimate for investment decisions.

This procedure for estimating transportation cost of CO2is, probably, the current best estimate which can be foundin the literature. The figure is impressive, and should becarefully compared with the above-mentioned expectedcost of capture and compression of CO2 ($10-60/t).

Nevertheless, despite the very comprehensive nature of thiswork, the model for CO2 pipeline uses some unnecessarysimplifications during the integration of the differentialflow model. Though understandable because the workwas basically interested in a engineering estimate of thepipeline diameter the truth is that the kind ofsimplifications that were made can affect the final result,and do not necessarily guarantee that a conservative designhas been achieved. These simplifications are, by the way,very common in pipeline engineering, but they can generatesmall differences that may be relevant, particularly for longpipelines with high flow rates operating with the specialpeculiarities of CO2 in the CCGS context, namely: highpressure, high density, high isothermal compressibility,non-uniformity, slight supercritical condition, and sensitiveto the influence of the topography along the pipeline route.Considering the importance of this issue, thesesimplifications should be removed in order to attain a morerigorous conclusion.

The flow model in Ref.1 assumes known values of fluidcomposition, weight flow rate, ground temperature, inletand outlet pressures, line length, and elevation changebetween the initial and final points of the pipeline. This lastparameter results in a simplified topography with constantinclination. The goal of the algorithm is the determinationof the line diameter as a floating-point number, which issubsequently rounded-up to the nearest existing commercialdiameter.

The procedure starts with a correct differential formula interms of the mechanical energy balance (i.e. a differentialform of the Bernoulli equation for compressible flow),

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which was subsequently integrated assuming averaged valuesof some properties and flow coordinates, namely:temperature (), compressibility factor (Z), density (),viscosity (), friction factor (f) and Reynolds Number (Re).

These assumptions are, in general, not significant in ordinaryflow problems but, as mentioned above, due to thesupercriticality and high density present in the CO2transportation problem, they may acquire more importance.

The main point lacking in this approach is that the flowmust be modelled with one independent variable normallythe axial position (x) in the line and two differentialequations a momentum balance (or a mechanical energybalance), and a full energy balance which have to besolved simultaneously for two flow-dependent variables:temperature () and pressure (P). The simplificationsintroduced mean that:

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.

We comment briefly below on some consequences of thesesimplifications:

1. The temperature () is assumed constant at anaverage value (

AVE) given by the ground temperature

(E). This simplification rules out a correct

description of the common situation where thefluid enters the line at a different temperature.Besides, this simplification also ignores eventualtemperature changes due to the combined action ofvelocity changes of the fluid (via kinetic energy -enthalpy conversion), adiabatic gravity compression/expansion (i.e. when the heavy fluid flows along adescending/ascending terrain), and heat transfer(heating or cooling) from the outside. As is wellknown, temperature strongly and inverselyinfluences the fluid density; the consequences oftaking temperature as a constant may result in anunderestimated line diameter, because ignoringpositive changes of flow temperature at intermediatelocations in the pipeline leads to overestimatedvalues of density and, consequently, results inunderestimation of velocity and of the coefficient ofhead loss per km.

2. Pressure is assumed constant at an average value(P

AVE) with the purpose of calculating averaged

properties like density, viscosity, and thecompressibility factor. This simplification introduceserrors in the above properties and in other averagedvariables (such as Reynolds Number, friction factor,and density) calculated using them. The impact inthe model response is difficult to evaluate, but it isnot negligible because, for instance, density errors

reverberate strongly in velocity and head losscalculations, affecting the profile of pressure (and,again, the profile of the density).

3. The compressibility factor (Z) is assumed as a constantcalculated at

AVE and P

AVE. This simplification may

be problematic because Z has a low value (0.2-0.3);assuming a constant Z may therefore lead to largerelative errors in this property, resulting in furthererrors which influence density estimation.

4. Viscosity () is calculated at AVE

and PAVE

. This is asimplification similar to (but less severe than) theabove case, causing propagation errors in theestimation of the Reynolds Number and the frictionfactor.

5. Changes of elevation were considered linearlydistributed along the pipeline, because the modelonly demands the knowledge of the initial and finalelevation values. This simplification may have seriousimpacts on the model response in the supercriticalCO2 context if the pipeline extends across a hillyterrain (see, for example, the case of the Cortezpipeline cited above). Essentially, CO2 flows as aheavy compressible fluid. So ignoring the correcttopographic, point-to-point, effects, may lead to anoptimistic description of the flow behaviour.Basically, intermediate segments in the pipelinewith sharp positive changes of elevation (veryinclined uphill segments), cause adiabatic expansionof the fluid due to momentum loss by gravity action.This loss of momentum is, at first, reversible andcan be recovered during subsequent downhillsegments, but the rapid expansion decreases thefluid density, accelerating the stream, irreversiblyincreasing the rate of loss of momentum via friction,which varies nearly with the square of velocity. Thisirreversible loss is not recovered when the fluidflows through a subsequent downhill segment. Thefinal effect is that the pressure value at the end of thepipeline is lower than the value predicted by themodel. Thus, this imprecision may lead to anunfeasible design due to an incorrect diameterselection.

Objective and scope of this work

According to the information stated above, andindependently of the acknowledgement of many previousefforts by the many specialists involved with the developmentof CCGS technology, it is easily recognizable, bothtechnically and economically, that only leg the transportof CO2 by high-pressure and high-capacity pipelines hasproved to be a reliable, feasible, and ready-to-go technologyin the CCGS tripod.

The state-of-the-art of pipeline transportation of CO2 hasbeen extensively and completely studied [1]. Nevertheless,

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as we show above, the flow model that was developedadopted some simplifications of a practical nature whichmay generate imprecision when dealing with the veryspecial type of flow that is presented by CO2 transportationin the CCGS scenario.

Consonant with this, the present work addresses a morecomplete modelling resource capable of generatingquantitative responses and profiles for all the flow variablesin the context of CO2 transportation by pipeline. Thisapproach provides a pipeline model for transportation ofCO2 (and its mixtures) in the supercritical state to anappropriate geological formation for storage. This modelnumerically solves three ordinary differential equationscorresponding to one-dimensional forms of:

momentum balance full energy balance, and inventory distribution, for three dependent

variables: pressure, temperature, and fluid inventory.

The model also takes into account the properties of CO2within a rigorous stationary high-density compressible flowframework, in conjunction with:

(a) high-density supercritical thermodynamics by thePeng-Robinson equation of state;

(b) topographic effects (i.e. adiabatic gravitationalcompression and expansion, including the respectivethermal consequences);

(c) heat transfer effects according to the temperaturedistribution in the soil and in the injection column;

(d) multiple machine stations, such as boostercompressors, exchangers, and recovery turbines;

(e) rigorous calculation of the parameters from pointto point along the pipeline.

The model was designed for engineering applicationsinvolving long-distance pipelines transporting densesupercritical CO2, either in its pure form or in mixtureswith other gases and fluids.

The remainder of this paper is organized in the followingmanner. The next section describes the physicalcharacteristics of CO2 and corresponding implications inflow problems at high density, high isothermalcompressibility, and high pressure. Following this, the

pipeline model for supercritical transportation of CO2 isintroduced. The fourth section formulates and solves anexample involving a 1000-km long, 14-in diameter, pipelinedesigned to transport 2.6Mt/yr (300t/hr) of a fluid with95% CO2 for EOR finalities. This pipeline starts at anelevation of 150m, having a destination elevation of 0m,but it has to cross a highland section rising to 850m and alength of 150km. The final 2500-m long section of this lineis a vertical 8-in column (or a set of several smaller columnswith the same total flow area) for geological injection of thefluid.

The pipeline also includes three ancillary items: a boostercompressor and cooler exchanger are located just beforethe pipeline section which has to climb the highlandsection; a heater is installed near the injection wellheads forpre-heating the fluid prior to expansion; and a recoveryturbine, preceded by the heater, is installed near thewellheads to remove the excess of head from the stream,since the descent flow in the injection column will re-compress the fluid, attaining the appropriate reservoirpressure at down-hole conditions. The investment in therecovery turbine and heater is justified because theconversion of heat into power thus obtained met therequirements for power consumption of the boostercompressor.

In order to make some comparison with the flow model inRef.1, in this fourth section we also solve another pipelineexample which was designed and analysed extensively inthe earlier study. This consists of a 100-km long, 16-in,pipeline for transporting 5Mt/yr of pure CO2 across aplain terrain in the Midwest of the USA, with inlet pressureof 138bar and minimum outlet pressure of 103bar.Although Ref.1 claims a 380-mm internal diameter pipelineis feasible, the present model shows that the final pressurewas 102.8bar, less than the intended value. Although smallin size, this difference is critical because it shows that therequired lower limit for the head, at the end of the pipeline,was not met by the design.

CO2: the fluidAs shown in the CO2 phase diagram in Fig.2, CO2 exhibitslarge state regions where it can exist as solid, liquid, andvapour phases. The boundary lines where two of these

Molar Mass (M) 0.04401

kg/mol

Critical Compressibility Factor (ZC) 0.274

Critical Temperature (TC) 304.15 K

(30.98 oC)

Critical Volume (VC) 93.9*10-6

m3/mol

Critical Pressure (PC) 73.8 bar Critical Density (C ) 469 kg/m3

Acentric Factor () 0.239 Critical Dynamic Viscosity (C ) 3.1 10-5 Pa.s

Triple Point Temperature (TTP) 216.6 K

(-56.6oC)

Triple Point Pressure (PTP) 5.2 bar Table 1. Summary of the physicaland critical constants of CO2.

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regions intersect constitute the two-phase coexistence lines,and are shown in Fig.2 as SVE (the solid-vapour equilibriumline), SLE (the solid-liquid equilibrium line), and VLE (thevapour-liquid equilibrium line). The intersection of allthree phase regions (and the coexistence lines) is located atthe Triple Point at -56.56oC and 5.2bar, where the threephases coexist. The Critical Point is another special pointin the phase diagram, corresponding to the end of the VLEline at 30.98oC and 73.8bar. The SLE line does not,apparently, have a similar critical point.

Table 1 presents a summary of physical and critical constantsof CO2. At temperatures and pressures greater than thecritical values, the fluid is in a supercritical condition: thisstate region, shown in Fig.2, is located beyond the end ofthe VLE line and below the SLE line. The region ofsupercritical fluid is very large in terms of pressure values,extending from 73.8bar to almost 104bar, where theformation of solid can occur above the critical point. In thisregion the fluid can pass isothermally, via a not necessarilylarge decrease in pressure from a typical liquid condition(high density, low isothermal compressibility) to a typicaldense-gas condition (high density, high isothermalcompressibility) without any abrupt phase transition asoccurs across the VLE line.

Historically, long-distance pipelines were constructed fortransportation of liquids (crude oil, liquid petrochemicalcommodities, fuels, and water) and certain gases (naturalgas and light petrochemical commodities). Long liquidpipelines rarely operate above 90-10 bar pressure, whereasin long gas systems the flow can leave the compressorstations at 190-200bar. These differences (and others shownbelow) are consequences of the following characteristics ofthese two operations:

Compressibility effects 1 (severe for gas pipelines,

mild for liquid pipelines): for stable liquids the fallof pressure due to friction does not appreciablyaffect the flow velocity (i.e. the fluid is assumed to benearly incompressible). For gas pipelines, on thecontrary, the decrease of pressure reduces density,increasing velocity and enhancing, by friction, thesubsequent fall of pressure/density and the rise ofthe velocity:

P v P v ...

This sequence ends, obviously, with the limit of thespeed of sound, which is a complete operationalimpossibility. For this reason, gas pipelines have tooperate at the maximum possible pressure(maximum density) so that the velocity and the headloss per km coefficient can be kept at minimum andalmost-constant values. Recompression by boostercompressors is necessary whenever the head loss perkm exhibits a trend to increase beyond a certaintolerance. More than merely increasing the pressure,the role of a booster compressor is to restore theoriginal inclination of the descending pressureprofile along the pipeline, because the negativeinclination of this profile increases rapidly inmagnitude with the fall of pressure.

Compressibility effects 2 (severe for gas pipelines,mild for liquid pipelines): for stable liquids, theconsequences of a pipe rupture can be modest ifactions are immediately taken for pump shut-down.On the contrary, for long gas pipelines, a shut-down, even followed by isolating actions along theline, will still be insufficient to prevent a sonicdischarge of fluid through the rupture orifice untilalmost all the fluid inventory of the isolated sectionof the pipeline has escaped to the atmosphere. This

Fig.2. Phase diagram of pure CO2,showing Triple and Critical Points,two-phase lines (SVE: solid-vapour,SLE: solid-liquid, VLE: vapour-liquidequilibria), and the supercritical fluidregion.

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discharge will expose, despite the shut-down andisolating actions, the environment at the rupturelocation to severe risk and damage.

High-density effects (severe for liquid pipelines,mild for gas pipelines): contrary to the case for gaspipelines, the high liquid density makes thedistribution of pressure in a pipeline to be stronglyaffected by gravity through topographic changes ofelevation. This characteristic may even change thepressure class at the end of a downhill section.

The specific physical properties of CO2 confer to CO2pipelines some important differences from the above twosystems. Going directly to the point, it is enough to say thatall three above phenomena have a severe effect on long-distance CO2 pipelines, which exhibit the properties ofboth high-pressure liquid pipelines and of high-pressurecompressible-flow pipelines. The reason for this is thatCO2 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 canreach 900-1000kg/m3.

Moreover, as can be seen in Table 1, the critical temperatureof CO2 is high (compared to natural gas), and close to theambient temperature. Thus, it is conceivable that the flowtemperature and pressure may approach the correspondingcritical values, while the fluid is maintained slightlysupercritical ( T P PC C, ). In this situation, the fluidaccesses a state region, just above the Critical Point, whereits isothermal compressibility is still very large, since thecritical isothermal compressibility is infinity:

1

= P

C( )

(1)

In other words, in the upper vicinity of the Critical Point,the density can vary rapidly with pressure (the same kind ofphenomenon that may occur with other CO2 properties),implying that small decreases of pressure cause rapidincreases of velocity and head loss per km, as shown in Eqn1b below.

This characteristic severely impacts the flow economy,enhancing even more the compressibility difficultiesdescribed above. To avoid this, the CO2 flow must beoperated at pressures above 86-90bar, where compressibilityeffects are not so intense.

As stated above, a basic rule in the design of compressibleflow pipelines (such as natural gas pipelines) stipulates that,to be efficient, the long-distance transport must be done at

densities as high as possible, and at low velocities (commonlybelow 2-3m/s) so as to keep friction head losses as low aspossible, thus maintaining the power consumption costs aslow as possible. In the CO2 ca

Design CO2 - Journal of Pipeline Engineering

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