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Material selection for supercritical CO2 transport

by Dr Shiladitya Paul, Richard Shepherd, Amir Bahrami, and Paul Woollin

TWI, Abington, UK

Paper presented at The First International Forum on the transportation of CO2 by Pipeline, Hilton Newcastle-Gateshead Hotel, Gateshead, UK, 1-2 July 2010.


Understanding materials' behaviour and assessing their integrity when in contact with supercritical CO2 is crucial to the success and sustainable implementation of carbon capture and sequestration plans. Of critical importance for the successful and cost effective operation of existing and new-build, infrastructure components, is quantifying materials' integrity in representative high pressure and supercritical CO2. This will enable confident materials selection, safe operation and accurate remaining life assessment to avoid the consequences of unexpected failure, as well as removal and replacement.

One of the most critical technical issues is quantifying degradation of different transport components, including pipes, pumps and valves, in CO2 as a high pressure gas or as a supercritical fluid, particularly in the presence of impurities. Although there is considerable experience of testing materials in lower pressure CO2, there are no standard test methods and few data for supercritical CO2. This paper explores the state-of-the-art in this field and highlights the areas of technology gap.

1. Introduction

1.1 General overview

Climate change is a major concern for most governments around the world. Evidence attributing this to anthropogenic activities in the last century or so has recently gained importance[IPCC, 2001]. Activities such as combustion of fossil fuels generate compounds, amongst others, carbon dioxide (CO2), a greenhouse gas (GHG) whose release into the atmosphere is widely acknowledged as the main cause of global warming. It is anticipated that fossil fuels will remain a major source of energy in the foreseeable future - both in the UK and internationally - with global demand for coal set to increase by about 70% by 2030[BIS, 2009]. Finding a path that mitigates emissions while utilising fossil fuels to meet energy needs is indeed a challenge for government and industry alike.

Carbon dioxide capture and storage (CCS), a carbon sequestration method, is recognised as one means of utilising fossil fuels whilst minimising impact upon the environment[IPCC, 2007; APGTF, 2009]. Primarily, this involves capturing the arising CO2 from industrial and energy-related sources, separating it from some other gases if needed, compressing it (leading to formation of supercritical or dense phase CO2), and then transporting and injecting it into a storage site such as depleted oil and gas wells or saline aquifers to ensure long-term isolation from the atmosphere.

Although the CCS concept is based on a combination of known technologies, large scale adoption and integration of individual existing technologies poses challenges. These technological challenges range from corrosion and structural integrity of materials to safety inspection during operation. Understanding these issues, mitigating if necessary, and filling the technology gaps in full scale implementation of CCS is important for its wider adoption as a CO2 emission reduction tool.

1 Phase at a temperature and pressure above the critical temperature and pressure. The critical point beyond which CO2 exists in the supercritical phase is 31.1°C and 73.9bar. The critical point represents the highest temperature and pressure at which the substance can exist as vapour and liquid in equilibrium. In the supercritical state, the density of CO2 will range from 50 to 80% of the density of water. The viscosity of supercritical CO2 is similar as in the gas phase, which can be up to 100 times lower than in the liquid phase[WRI, 2008]. This is quite important for pipeline transport as it implies lower drag. From the cost standpoint, supercritical transport allows for substantially higher throughput through a given pipe than transport as a lower pressure gas. At high pressure CO2 may exist as a liquid if the temperature is below the critical temperature. When CO2 exists above the critical pressure it is often termed 'dense phase' fluid.

1.2 Industrial Experience in Handling CO2

Handling of CO2 for industrial operations is not a new technology, but the volumes, pressures and distances involved in wider adoption of CCS pose challenges. CO2 as an industrial gas has been transported via tankers over short distances. This however becomes less economical for transportation of large volumes of liquid, dense phase or supercritical CO2, which maximises the mass of CO2 transported. In these cases pipeline transport becomes more attractive as has been utilised in enhanced oil recovery (EOR). Using CO2 in EOR projects has the advantage of adding a value to the CO2, eg oil producers in the USA are willing to pay between 9 and 18US$/ton of 'end of pipe' delivered CO2.

EOR has been an industrial practice in the oil and gas sector for over 35 years, mostly in the United States. Over this time, the oil and gas industry has developed many technologies and operating practices for efficient functioning of over 13,000 wells, over 3,900miles of high pressure CO2 pipelines and injected over 600×106 tonnes of CO2 (Table 1). As a result the USA produces over 245,000 barrels of oil per day via EOR[Parker et al, 2009]. Many of the technologies and practices that have been developed for, and the experience gained in, CO2 EOR are invaluable for CCS.

Table 1 Some existing long distance CO2 pipelines [Gale and Davison, 2004; Kinder Morgan, 2009; Dakota Gasification Company, 2009]

PipelineLocationOperatorCO2 capacity,
Year finishedOrigin of CO2
Cortez USA Kinder Morgan 19.3 808 1984 McElmo Dome
Bravo USA BP 7.3 351 1984 Bravo Dome
Sheep Mountain USA BP/Occidental Permian 9.5 657 - Sheep Mountain/Bravo Dome
Canyon Reef Carriers USA Kinder Morgan 5.2 225 1972 Gasification Plants
West Texas and Lano Lateral USA Trinity Pipeline 1.9 290 - -
Val Verde USA Petrosource 2.5 130 1998 Val Verde Gas Plants
Bati Raman Turkey Turkish Petroleum 1.1 90 1983 Dodan Field
Weyburn USA and Canada North Dakota Gasification Co 5 328 2000 Gasification Plant

In 1972, the first CO2 injection project for EOR was initiated in the SACROC unit (Scurry Area Canyon Reef Operators Committee). The project used various corrosion resistant materials to avoid corrosion problems in injection operations (Table 2). In any wetted region, Type 316 austenitic stainless steel was used for valve trim, metal piping, etc. In selected cases, operators use fibreglass piping in upstream metering/piping runs[Meyer, 2007].

Table 2 Typical construction materials for CO2 injection wells [Parker et al, 2009]

Upstream metering and piping runs 316SS, Fibreglass
Christmas tree 316SS, Ni, Monel
Valve packing and seals Teflon, Nylon
Wellhead 316SS, Ni, Monel
Tubing Hanger 316SS, Incoloy
Tubing GRE lined carbon steel, IPC carbon steel, CRA
Tubing joint seals Seal ring (GRE), coated threads and collars (IPC)
ON/OFF tool, profile nipple Ni-plated parts, 316SS
Packers Internally coated hardened rubber of 80-90 durometer strength (Buna N), Ni-plated parts
Cements and cement additives API cements and/or acid resistant speciality cements and additives

Currently, glass reinforced epoxy (GRE) lined tubing, comprising an internal fibreglass liner, or sleeve, bonded to the inside of a steel pipe is used. Some CO2 pipelines are also constructed from epoxy-coated and polyethylene-lined carbon steel[MRCSP, 2005]. Internally plastic coated (IPC) tubing consisting of a sprayed coating (phenolics, epoxies, urethanes or novolacs) to the inside of a steel pipe is also used.

Seal rings are commonly used for making up GRE lined tubing joints. For seals and joints elastomers are used. These include Buna-N and Nitrile rubbers with an 80-90 durometer hardness reading. For packers Teflon and Nylon are used for seals, whilst nickel plating is often used on all wetted parts and internally coated hardened rubber elastomers of 80-90 durometer hardness (Buna-N) are used to circumvent CO2 permeation[Parker et al, 2009]. Viton valve seats and flexitallic gaskets are typically specified in the USA for CO2 pipeline seals. [Mohitpour et al, 2008]

However, pipelines suffer from pressure drops due to drag along the transportation route, which can result in two phase flows, and operational and material problems (eg cavitation) in components such as booster stations and pumps.

From the foregoing therefore, it would seem that the oil and gas industry in the US has used CO2 without much concern. However, to avoid problems with CO2 transport its quality, ie allowable impurity levels, has been specified (Table 3). These limiting values ensure that corrosion is minimised while maintaining operational safety. For transport of CO2 from power plants for CCS applications, these specifications will probably need to be changed to accommodate the presence of impurities as purification will incur cost penalties. A compromise will probably be reached to minimise cost of purification while still using cheap pipeline materials (eg X-60, 65 carbon steels) for transport.

Table 3 CO2 quality restrictions for EOR, and recommendations for CCS [ICF, 2009; IPCC, 2005; De Visser et al, 2008]

Constituent/parameterLimiting valueReason for concern
CO2 >95% >95.5% Minimum miscible pressure for EOR
N2 <4% <4% Minimum miscible pressure for EOR
Hydrocarbons <5% <4% Minimum miscible pressure for EOR
H2O <650ppm <500ppm Corrosion
O2 <10ppm - Corrosion/reaction with odorants
H2S <10-200ppm <200ppm Corrosion/Health and safety
Total sulphur <1500ppm - safety
Glycol <4 x 10-2ml/m3 - operations
Temperature <48.9°C - Materials operating limit

A number of pilot plants and some commercial CO2 storage projects are already underway (Table 4). Most of the working projects are associated with gas processing such as Sleipner (Statoil), Snohvit (Statoil) and In Salah (BP, Sonatrach, Statoil). The first commercial CO2 storage project started in 1996 at Sleipner Vest, Norway. At Sleipner, wet CO2 is injected into the Utsira formation using 13%Cr steel casing joints to minimise corrosion. In order to optimise life, solution annealed 25%Cr duplex stainless steel has been chosen for the tubulars used in injection. 22%Cr duplex stainless steel has also been used in topside equipment[Baklid et al, 1996]. Due to the presence of approximately 150ppm H2S in this field, sulphide stress corrosion cracking was also considered. For machined components alloy 625 is used. This project being a CO2 injection system to an offshore field proved that CCS is a technically feasible method for climate change mitigation. It further demonstrates that storage is both safe and has low environmental impact. More than 10Mt of CO2 extracted from gas processing have been injected into the deep sub-sea Utsira saline formation[Soares, 2008]. Monitoring the injected CO2 in the geological reservoir using seismic surveying indicates that most of the CO2 collects in a stack of accumulations under thin layers of clay within the sand. With time the natural trapping mechanism will change from structural and stratigraphic, through to solubility and finally to mineral trapping; which is considered the most permanent and secure form of geological storage[Solomon, 2007]. At In-Salah (Algeria), BP, Sonatrach and Statoil inject ~1.2Mt/y CO2 obtained from gas processing into a saline aquifer north of the gas reservoir. It is estimated that ~17Mt of CO2 will be injected over the life of the project[BP, 2008].

Table 4 Selection of current and planned CO2 capture and storage projects [Friedmann, 2007; MIT, 2009; BP, 2008; Vattenfall, 2009]

Project nameLocationLeader / coordinatorCO2 sourceCO2 sinkApproximate storage rate, Mt/yStart year
Sleipner Norway Statoil Gas processing Offshore saline formation 1 1996
Weyburn Canada Pan Canadian Coal gasification Onshore EOR 1 2000
In Salah Algeria BP Gas processing Depleted gas reservoir / deep saline formation 1.2 2004
Snohvit Norway Statoil LNG processing Depleted gas reservoir 0.7 2008
Schwarze pumpe Germany Vattenfall Coal combustion Depleted gas field - 2008
CO2SINK Germany German Research Centre for Geosciences (GFZ) Hydrogen production Sandstone reservoir 0.03 2008-2009
Gorgon Australia Chevron Texaco Gas processing Offshore saline formation / deep water sandstone - 2009
Total Lacq France Total Oil combustion Onshore depleted natural gas field 0.08 2010 (Europe's
first full chain
CCS demonstration project)
AEP mountaineer USA American electric power Coal combustion Deep saline formation 0.1 2009-2011
Scottish and southern energy Ferribridge UK Scottish and southern energy Coal combustion Depleted gas fields 1.7 2011 (small scale demonstrated
started in 2009)
ZeroGen Australia Stanwell corporation Coal combustion Deep saline aquifer 0.4 2012
UK CCS UK - Coal combustion Offshore storage - 2014
GreenGen China China Datang group Coal combustion Sequestration/EOR - 2015-2020
E. On Benelux The Netherlands E. On Coal combustion Depleted offshore gas field - Undecided

Clearly there exists a degree of experience in storage of CO2 in geological formations in full scale applications. This experience will form an essential part in the CCS chain.

2. Materials issues in transport of CO2

2.1 Corrosion of steel pipelines in CO2-containing environments

2.1.1 General remarks

On the transport and storage side, the materials degradation issues arise from corrosion in wet CO2 environments. On the capture side, there are few issues regarding the materials used in technologies such as chemical absorption using amines. In addition to corrosion, thermal and mechanical stability and lifetime of the components used for CCS are also important.

Choice of materials is critical for the success of CCS. Low alloy carbon steel pipelines have been used for transportation of high pressure CO2 without significant corrosion issues, but in these cases, CO2 was dried to <100ppm water to eliminate corrosion risks[Seiersten and Kongshaug, 2005]. CO2 in the presence of water, however, will form highly corrosive carbonic acid. The studies related to the impact of wet CO2 on corrosion of steels have mostly been limited to up to 20bar in support of oil and gas production requirements with extensive publications and predictive models generated (Table 5). At higher pressures experimental data are sparse.

Table 5 Existing prediction models for corrosion in high pressure CO2 environments [Seiersten and Kongshaug, 2005]

ModelDeveloper(s)Temperature, °CPressure, barpCO2, barpH
de Waard-Milliams de Waard and Milliams, 1975/ Shell, IFE 0 140     10    
HYDROCOR Shell 0 150 200   20    
Cassandra 98 BP         10    
NORSOK Statoil, Saga, IFE 20 150 1000   10 3.5 6.5
CORMED Elf   120          
LIPUCOR Total 20 150 250   50    
KSC IFE (Joint Industry Project) 5 150 200 0.1 20 3.5 7
Tulsa University of Tulsa 38 116     17    
PREDICT InterCorr International 20 200     100 2.5 7
Ohio Ohio University 10 110 20        
SweetCor Shell 5 121   0.2 170    

*CORMED and LIPUCOR have been incorporated into CORPLUS by Total

Dry supercritical CO2 (pressure 98-158bar) resulted in limited corrosion (approximately 1.3µm/y) of type 304 stainless steel at temperatures between 149-238°C for up to 380days[Propp et al, 1996]. Similarly for AISI 1080 C-Mn steel, low corrosion values ~10µm/y have been measured at 90-120bar and 160-180°C during 200 days. Tests conducted at lower temperatures (3-22°C) at 140bar CO2, <1000ppm H2O and with 600-800ppm H2S gave corrosion rates <0.5µm/y for X-60 carbon steel[Seiersten, 2001].

Quantitative measurements of corrosion in wet CO2 at high pressure are sparse. Some investigations concluded that the corrosion rate is sensitive to the pH of the system and that at pH of approximately 3.5 the corrosion rate can be as high as 13mm/y at 50bar CO2 pressure. At 80bar CO2 pressure, X65 C-Mn steel corroded at a rate of 4.6mm/y at 50°C in aqueous solutions[Seiersten and Kongshaug, 2005]. A study conducted in an autoclave filled with 1M NaCl solution at 80°C and CO2 pressure up to 50bar suggested that pH changes of the test solution caused by the corrosion process affects the corrosion rates at high CO2 pressures. The corrosion rate at approximately pH 3.5 was about 10mm/y at 5bar and 15mm/y at 50bar. Under floating pH conditions corrosion rates at 5 and 50bar CO2 were similar[Seiersten and Kongshaug, 2005]. Generally it is accepted that the corrosion rates decrease with increasing pH. This is due to the formation of a protective carbonate scale. The experimental values often contradict the models available for CO2 corrosion in oil and gas production. This limitation exists as these models have been developed to cover a pressure range relevant to oil and gas transportation, ie up to 20bar CO2 pressures. These models, summarised in Table 5, with two exceptions, are restricted to <50bar, with most being only valid up to 20bar.

2.1.2 Factors influencing CO2 corrosion

Corrosion of materials in contact with CO2-containing fluid is dependent on various factors. These include: (i) water chemistry, (ii) operating conditions, and (iii) material type.

Effect of water chemistry

As studies indicate that an aqueous phase is required for corrosion in the presence of CO2 in oilfield environments, understanding the aqueous chemistry becomes important. The formation of a protective, stable carbonate scale has been linked to reduced corrosion rates in CO2-containing solutions. Supersaturation plays an important role in the formation of a protective carbonate layer in steel. The stability of this layer is dependent on the solution chemistry such as the presence of dissolved salts, compounds affecting the pH, corrosion inhibitors etc.

The pH has a direct effect on the CO2 corrosion rate[Nesic et al, 1996]. It influences both the electrochemical reactions that lead to dissolution of iron and the precipitation of protective, corrosion inhibiting, carbonate scales.

However, the indirect effects of pH that relate to scaling conditions are equally important. High pH results in decreased solubility, increased precipitation and higher scaling tendency of iron carbonate. For example, an increase in the pH from 4 to 5 causes a five-fold reduction in the solubility of iron carbonate; for an increase in pH from 5 to 6, this reduction is around 100 times[Kermani and Morshed, 2003]. A high pH does not always mean a reduction in corrosion rate. Supersaturation plays an important role in scale formation and its stability. For example, a low supersaturation at pH 6 may result in very little alteration of corrosion rates as relatively poor, unprotective carbonate scales form. At pH>6.6, higher supersaturation results in lower corrosion rates due to faster precipitation and formation of more protective scales[Chokshi et al, 2005]. There are other indirect effects of pH such as the formation of non-siderite scale. If acetic acid (HAc , where Ac = CH3COO) is present in the aqueous media2, increase in pH stabilises the acetate ions (Ac-).

The presence of organic acids is reported to increase the oxidising power of H+ by raising the limiting diffusion current for cathodic reduction[Hedges and McVeigh, 1999]. The quantity of such organic acids in the produced water may vary from 500-3000ppm of which acetic acid (or ethanoic acid) is often the major constituent[Gunaltun and Larrey, 2000]. Although top-of-line corrosion is the most widely studied CO2 corrosion in connection with HAc, bottom-of-line corrosion of pipelines containing multiphase fluids is also known[Okafor and Nesic, 2007]. Increase in undissociated HAc increases the corrosion rate of carbon steel as it provides a reservoir of H+ ions over and above that determined by the solution pH[Kermani and Morshed, 2003]. Further work in the field also suggested that HAc is particularly harmful in its undissociated state[Nesic, 2007]. At low pCO2 the presence of such acetic acid also tends to form more soluble iron acetate (as opposed to iron carbonate), thus increasing corrosion rates[Crolet et al, 1999].

Corrosion inhibition can occur either by: (i) addition of inhibitors during oil exploration or (ii) in-situ inhibition by components present in the crude oil. While the former is externally controlled by addition of inhibitors to achieve corrosion protection by surface coverage[Wong and Park, 2009; Foss et al, 2009], the control over the latter is difficult as it is dependent on the crude oil composition and hydrodynamic conditions[Nesic, 2007].

Glycols and methanols are often added (sometimes >50wt%) to prevent hydrate formation. The mechanisms that control CO2 corrosion in the presence of such inhibitors are not entirely understood. However, it has been assumed that the main inhibitive effect of such additions come from decreased activity of water due to dilution. Corrosion rates of nearly 0.03µm/y were reported for type 304 stainless steel when 1wt% water in the CO2-containing corrosive environment was replaced with 10wt% methanol at approximately 190°C and 150bar. In the presence of 1wt% water in similar conditions a corrosion rate >10 times was observed. Glycols and amines, often used in CO2 capture plant, have an effect on the hydrate formation and corrosion rate. At lower CO2 pressures, a 50/50 blend of water/glycol resulted in 50% reduction in corrosion rate of ordinary carbon steel when compared to a system devoid of glycol[Hesjevik et al, 2003]. A recent report on low temperature experiments (at circa 31°C) in a high pressure CO2 environment (approximately 79.3bar) suggested a similar outcome[Thodla et al, 2009]. A reduction of two orders of magnitude in corrosion rate, from 1-3mm/y to 0.01-0.02mm/y, was reported when a mixture of 100ppm water and 100ppm monoethanol amine was used instead of 100ppm water only.

Crude oil often acts as an inhibitor by affecting the wettability of steel to produced water. The presence of crude oil prevents water from wetting the steel surface thereby reducing corrosion rates. It is also speculated that certain components present in crude oil get adsorbed on the steel surface and affect corrosion rates. The nature of such interactions is largely unknown, but the work of Hernandez et al[Hernandez 2002,2003] suggested that the concentration of aromatics, resins, alkanes, asphaltenes, nitrogen, sulphur, oxygen and fatty acids have an effect on the degree of inhibition.

The produced water in many oil and gas wells has high total dissolved solids (TDS) content (often TDS>10wt%). For example, water analysis from a Texas gas well showed TDS content of about 23wt%[Fang et al, 2006]. At such high concentrations, theories related to ideal solutions are not valid and hence cannot be used. Instead, activity coefficients should be used in place of concentrations[Nesic, 2007]. Salts might precipitate to form scales which might adhere to the surface of steel affecting the corrosion rate. Field experience suggests that corrosion rates can be reduced in solutions with high TDS (ie high salt concentration). Increase in salt concentration changes the ionic strength of the solution which affects the solubility of CO2 and iron carbonate in the aqueous phase (also called kinetic electrolyte effect). As the solubility of these compounds in water governs the corrosion rate, the importance of salt concentration is thus recognised.

Effect of operating conditions

Operating conditions such as temperature, pressure and presence of other gases (other than CO2) and their partial pressures affect the steel corrosion rates. The presence of different gases and their partial pressures affect the corrosion rate by affecting the water chemistry.

Temperature has two opposing effects on the kinetics of CO2 corrosion. In general, increase in temperature accelerates diffusion-controlled mass transfer processes and facilitates CO2 corrosion. This is generally found to be the case at low pH. However, temperature rise has an opposing effect, particularly at higher pH when the solubility limit of iron carbonate is exceeded[Sun and Nesic, 2006]. Based on literature, Sun et al[sun et al, 2009] developed an expression relating iron carbonate solubility (K in mol2/l2) to temperature (T in K) and ionic strength (I in mol/l).


According to their expression increased temperature should facilitate the formation of a carbonate film as its solubility decreases with temperature.

At room temperature, the process of precipitation is very slow and an unprotective scale is usually obtained even at very high supersaturation[Wang et al, 2004]. On the other hand, at higher temperatures (>80°C), precipitation is likely to proceed rapidly; often forming dense and very protective scales even at low supersaturation thus decreasing corrosion rates[Kermani and Morshed, 2003; Nesic, 2007]. In the intermediate temperature range the corrosion rate progressively increases reaching a maximum between 70-80°C after which it decreases due to scaling.

The American Petroleum Institute (API), in the late 1950s, provided rule-of-thumb criteria for corrosion of carbon steels[Kermani and Morshed, 2003]. The rules of thumb suggest that at pCO2 >2bar corrosion is likely, implying that corrosion rate may be >1mm/y; whereas at pCO2 <0.5bar, corrosion was deemed unlikely (ie corrosion rate <0.1mm/y). These rules were based on field experience, primarily in the USA, but later endured several exceptions and proved qualitative at best. However, they can still be used as an aid to first-pass materials selection.

It is generally observed that in conditions where protective scales do not form, an increase in CO2 partial pressure (pCO2 ) typically leads to an increase in corrosion rate. The concentration of H2CO3 increases with an increase in pCO2 and thus more carbonic acid is available for proton-releasing cathodic reduction which ultimately increases the corrosion rate. In cases where scales can form (eg high pH), an increase in pCO2 leads to higher supersaturation, which accelerates precipitation and scale formation. This can lead to lower corrosion rates as observed by Sun and Nesic[Sun and Nesic, 2006].

At very high total pressure, the gas phase-solution phase equilibria cannot be accounted for by Henry's law. To account for this non-ideal solution case, use of a fugacity coefficient is suggested. However, obtaining such coefficients is not trivial as it involves solving the equation of state for a gas mixture whose composition may not be known with certainty (eg in case of produced fluids).

Gas composition also significantly alters the corrosion mechanism which inevitably affects the corrosion rate. Presence of gases such as H2S, CO, H2, CH4 and O2 are known to affect CO2 corrosion. The effect of other gases, for example SOx, NOx etc, which are likely to evolve during fossil fuel combustion, is not extensively studied at high pressures. However, formation of acidic aqueous solutions when these gases are dissolved in water is known. This might have an impact on the corrosion rate as the sulphates and nitrates of Fe have different solubilities when compared to the corresponding carbonate.

The effect that even small amounts of H2S can have on the CO2 corrosion rate has been recognised for over 60 years. Still, the corrosion mechanisms under H2S/CO2 conditions are poorly understood, particularly in high pressure conditions most likely experienced in sour oil and gas wells. H2S is known to cause sulphide stress cracking (SCC), but apart from the cracking aspects associated with sour service, in the presence of CO2 its effect can be varied. Often, conflicting results are reported in the literature. For example, Videm et al[Videm, 1998] and Mishra et al[Mishra, 1992] have reported two opposite effects concerning H2S. While Videm et al[Videm, 1998] reported that very small amounts of H2S in CO2-containing aqueous media accelerated the corrosion rate; the latter argued that small amounts of H2S had some inhibitive effect on CO2 corrosion of steels. Mishra et al[Mishra, 1992] attributed this effect to the formation of iron sulphide film that apparently was more protective than iron carbonate. Nyborg[Nyborg, 2009] reported in his review that corrosion in a mixed sweet-sour system is CO2 dominated if pCO2 /pH2S > 500 - 1000.

Some work[Ikeda et al, 1985] suggested that a low concentration of H2S (<30ppm) in a CO2-saturated aqueous solution can accelerate the corrosion rate significantly in comparison to corrosion in a similar CO2 environment without H2S. At higher concentrations and temperatures (>80°C) this effect seems to vanish due to the formation of a protective film. The results at low temperatures were not explained in detail in their report. At lower temperatures (<<80°C) the possible involvement of H2S to catalyze the anodic dissolution of bare steel might lead to higher corrosion rates when a protective film of FeCO3 is not formed due to its greater solubility.

There are some data on the effect of very small H2S concentrations on CO2 corrosion at low pH, where precipitation of iron sulphides does not occur. Experiments were conducted by Brown et al[Brown, 2003] for low H2S concentrations (<500ppm) in the gas phase and for pH<5, at various temperatures (20-80°C), pCO2 between 1-7bar and velocities (stagnant to 3m/s) in both single and multiphase flow. Their data strongly suggest that the presence of even very small amounts of H2S (10ppm in the gas phase) will lead to rapid and significant reduction in the CO2 corrosion rate. At higher H2S concentrations this trend is somewhat reversed. The effect seems to be universal and depends solely on the H2S concentration, as all the data obtained at very different conditions follow the same trend.

Experiments by Makarenko et al [Makarenko, 2000] proved that CO2 corrosion of carbon steel increases by 1.5-2 times with increase of H2S content (<25%) in the mixture (pH2S <5bar; pCO2 =15bar) in the temperature range 20-80°C. Further increase in H2S content (pH2S ≥ 5-15bar; pCO =15bar) weakens corrosion, especially in the temperature range 100-250°C, because of the influence of FeS and FeCO3.

FeCO3, which generally forms a passive film on the steel surface and retards CO2 corrosion, is unstable in the presence of oxygen. In field applications, if oxygen enters the production equipment due to water or inhibitors injection it will oxidise Fe2+ into Fe3+ ions and will form oxides and hydrated oxides of Fe instead of a carbonate scale. Thus the oxygen concentration should be kept under 40ppb (often <10ppb) in order to suppress this oxidation[Lopez et al, 2003; Wang, 2009].

Recently some work has been reported on CO2 corrosion in the presence of impurities[Ayello et al, 2010; Choi and Nesic, 2010]. The corrosion rate of carbon steel is reported to increase from 2.3mm/y in the presence of 1000ppm H2O to 4.6mm/y when 100ppm SO2 was added to the system at 75.8bar CO2 at 40°C[Ayello et al, 2010]. When 100ppm SO2 was replaced by 100ppm NO2 the corrosion rate increased to 11.6mm/y.

Choi and Nesic[Choi and Nesic, 2010] performed similar experiments with X-65 carbon steel in circa 6000ppm H2O at 50°C and 80bar CO2 pressure. They observed that the addition of 1% SO2 in the gas phase dramatically increased the corrosion rate of carbon steel from 0.38 to 5.6mm/y. This then increased to more than 7mm/y with addition of 4% O2. The explanation for this enhanced rate of corrosion lies in the ability of SO2 to promote the formation of iron sulfate (FeSO4) on the steel surface which is less protective than iron carbonate (FeCO3). FeSO4 is further oxidized in the presence of O2 to become FeOOH and H2SO4. This further decreases the pH and accelerates the corrosion reaction.

Effect of material type

In the case of carbon steels, the microstructure seems to have a major effect, although the information available at the present time is controversial and consequently the selection of materials is not an easy task. It is strongly recommended to be aware of it, and whenever possible, to perform online tests in order to monitor the corrosion rate and the inhibitor's efficiency.

The formation of a stable oxide of chromium is beneficial for improved corrosion resistance in CO2-containing media. The presence of Cr in steel can offer significantly improved corrosion resistance[Dugstad et al, 2000; Kermani and Morshed, 2003]. Some publications suggest the use of 13% Cr steel either in homogeneous ('solid') form or cladding on carbon steel for corrosion mitigation. If low chromium alloy steel is to be selected, it is worth noting that even though the influence of steel microstructure seems of less importance than for carbon steels, it is recommended not to have a ferritic-pearlitic microstructure[Lopez et al, 2003]. When inhibitors are required, it is important to assess the compatibility of inhibitors and the chromium-rich surface films grown on Cr-containing steels[Nesic, 2007]. As a general consideration, for any inhibitor selection, the chemical composition and the microstructure of the steel to be protected have to be taken into account.

In addition to the above, steels with high Cr content, especially stainless steels, are much more expensive than carbon steels. The price-optimal Cr level will vary with application, albeit a Cr level between 2-3wt% in conjunction with various microalloying constituents was considered essential to achieve satisfactory corrosion performance in one study[Kermani and Morshed, 2003].

2.2 Structural integrity of materials in contact with high pressure CO2

2.2.1 Metallic materials

Carbon capture from power stations will demand important changes to the composition of the product to be transported. Power station emissions will contain a number of impurities whilst the CO2 transportation in North America for EOR is essentially pure. This is believed to have serious metallurgical and safety implications for the design of pipelines for CCS. High pressure, ie dense phase or supercritical CO2 pipelines are susceptible to fast-running ductile or brittle fractures. The presence of dense phase means high saturation pressure and low decompression velocity[Mohitpour et al, 2008]. This makes the fracture behaviour more complex than for natural gas. The fast-running fractures that result can be potentially catastrophic. However, significantly, little attention has been paid to the design to arrest fast running fracture in carbon steel pipelines for CO2 and corrosion control in the presence of CO2 with a mixture of compounds, with more focus upon use of various capture technologies (post-combustion, pre-combustion or oxy-fuel). The general operational conditions and risks associated with pressurized CO2 pipelines are not yet fully investigated.

The main pipeline fracture control issues comprise a complex interaction of:

  • large-scale inelastic deformation of the pipe.
  • pressure from unsteady fluid flow of escaping CO2 gas and the associated rapid cooling of the pipeline material.
  • dynamic crack propagation.

Decompression behaviour of the natural gas (predominantly CH4), which is widely transported safely and well understood, can not be used as the basis of design and fracture control of the planned dense phase CO2 pipelines. In the event of a leak or pipeline rupture, the sudden expansion of the dense phase CO2 causes a significant temperature drop at the vicinity of the leak[Cosham and Eiber, 2008]. The high vapour pressure of CO2 can prevent rapid decompression, which in turn can cause a continuously propagating fracture by sustaining the crack driving force[Mohitpour et al, 2008].

Many models and formulae have been developed for the determination of the required toughness to arrest a crack. Among these models, the Battelle two curve method is widely used to predict the toughness requirement. The method compares the curves expressing the variation of crack velocity and of gas decompression velocity with pressure. If no intersection exists between the crack and the gas decompression velocity curves, gas decompression velocity exceeds crack velocity for all pressure levels, the pressure at the crack front will decrease and the crack will arrest. On the other hand, if an intersection exists between the crack and the gas decompression velocity curves, a pressure level exists where crack and gas decompression run together at the same velocity, no further decrease of the pressure at the crack front is possible and a crack will continue to propagate. Thus, the tangent condition between the two curves represents the boundary between arrest and propagation, and the corresponding toughness level is referred to as the arrest toughness. However, it is often difficult to apply this method for high strength steels. In order to extend its applicability to high strength steels, correction factors have to be used to align the predicted toughness with experimental results. In addition, the models depend on the decompression curves which are based on the equation of state. Benedict-Webb-Rubin-Starling (BWRS) and Lee-Kesler (LK) equations of state are often used but these have parameters which need to be modified for a particular composition of the gas. These are generalised equations of state, implying that they can be applied for both liquid and gas/vapour phases, although they are unreliable around the critical point.

GASDECOM (gas decompression modelling software) or its modifications have been used to calculate the decompression curve for hydrocarbons. One needs to construct the phase diagram to properly assess any equation of state for a given gas composition. Even when an equation of state has been assessed for various compositions its applicability tends to be limited for situations where the gas composition is beyond one's control (eg oil wells).

2.2.2 Polymeric materials

Polymeric materials, both elastomers and plastics, are used in the oil and gas sector. Generally elastomers are used for seals and sealing applications where compliance (flexibility) and the capacity to retain and transmit the applied forces of the contained fluid (gas, liquid or mixed phase) is required. Other important applications for elastomers are in the manufacture of bonded hoses. Reinforced with metallic and fabric elements these composite structures are used as part of loading/offloading systems and more recently have been proposed in riser applications. Elastomers are also used to provide load bearing, sealing and flexibility for flexible joints used in combination with steel centenary riser (SCR) solutions. Applications for thermoplastic polymers include seal system back-up rings (PEEK, PPS, PTFE) pressure linings for unbonded flexible pipes and risers (PVDF, PA11, PA12) and pipe linings. Finally epoxy and polyester type resins are used in combination with fibre reinforcement (GRP, GRE etc) although their use in critical applications such as risers and injection lines is more limited, however they do have a current role in the transport of crude products and ancillary services on-shore.

When polymers contact a fluid, if chemically compatible, then it will undergo swelling which generally can be associated with weakening. The extent of swelling will be dependent on the solubility parameter of the liquid and its proximity to the polymer and the temperature at which the process takes place. To briefly explain the mechanism; any polymer contains some inner free space distributed between the molecular chains. If exposed to a fluid there is the possibility for the material to absorb that fluid if the molecules or atoms are small enough to fit the regions of this distributed space during kinetic movements. As these spaces are filled, subsequent kinetic motion must make neighbouring chains move away to allow for these absorbed molecules with an associated increase of volume, ie swelling. This process will create more free space around the molecules to the point where an equilibrium condition is reached; the rate and extent of swelling and the volume of fluid uptake will vary but are significant for the polymer performance.

The process of absorption has two phases:

  • Adsorption, the first stage where a fluid dissolves into the surface of the material following initial contact.
  • Diffusion, the fluid molecules diffuse through the material bulk under the action of the concentration gradient (ie from high concentration to low), according to Fick's laws.

Finally, in the scenario where there is a pressure gradient across the polymer, in the case of a seal or polymer lining in a hose or a flexible joint, the above process is completed by the subsequent evaporation of the fluid from the low pressure surface out into the adjacent atmosphere; ie permeation.

For the case considered here, supercritical CO2, the fluid is absorbed by the continuous process of adsorption and diffusion (up to an equilibrium condition). Since another parameter that affects the final equilibrium condition is the viscosity of the fluid, and the viscosity of CO2 decreases as it becomes supercritical, then the rate of absorption and the associated mass of absorbed liquid increases.

Polymers, and particularly elastomers, can be sensitive to mechanical damage caused by rapid gas depressurisation (RGD) events - also known as explosive decompression (ED). The fluid (gaseous or liquid CO2 is considered here) enters the material under pressure by the mechanism described above. If the pressure is then removed then the material is no longer at equilibrium and the gas in the material tries to escape by the process of diffusion and evaporation. Where this cannot happen sufficiently rapidly, then the dissolved gas comes out of solution and inflates small bubbles at nucleation sites; these may harmlessly deflate if the gas can escape the bulk polymer by diffusion and evaporation. However, if they cannot, above a critical bubble size, irreversible crack growth occurs.

Numerous factors contribute to the RGD/ED performance of a polymer; these include material modulus and tear strength, temperature, pressure, gas type or composition, depressurisation rate, material cross-section, housing details (squeeze or compression, groove fill for a seal) and number of pressure cycles, Table 6. If the rate of depressurization could be made low enough to match the natural diffusion rate of the gases absorbed within the seal, then no RGD damage would be possible. However, it is not always possible to exert control over the critical factors which influence RGD damage.

Table 6 Factors which can influence elastomeric seal performance in a pressurized gas

Modulus Material property; high is good for resisting blister formation. High stiffness elastomers have low tear strength and vice versa see tear strength
Tear strength Material property; high is good for resisting crack growth
Diffusion coefficient High is desirable; D increases with temperature
Temperature Affects D and seal stiffness/tear strength; latter decrease with increasing temperature
Pressure Affects concentration of dissolved gas; compaction effects
Gas type High CO2 levels promote RGD damage since gas more soluble than methane
Material section Smaller the better; path for gas exit by diffusion is shortened
Groove geometry (seals) High groove fill desirable but not always possible (for other reasons)
Decompression rate Slower the better (control not always possible)
Target pressure Atmospheric pressure is worst case
No. of RGD events Fewer the better

Performance prediction via extrapolation of accelerated laboratory test data is not yet possible, and is the primary reason that testing at conditions as close to service as possible is considered essential. Also, with knowledge of polymer type and service conditions, it is possible to only qualitatively predict the likelihood of a seal being damaged by pressurised gas. Overall, the determination of RGD resistance for critical applications is not a trivial exercise and is best evaluated via a realistic test programme.

One standard procedure to address RGD resistance is NORSOK M-710; this is useful but has some limitations. The standard provides procedures for the testing and subsequent evaluation of seal (o-ring) performance after being subjected to a multi-cycle gas exposure test. Typically, O-rings having section 5.33 mm are housed in appropriate fixtures and tested in one of three listed gas mixtures - 100% CO2, 97/3 CH4/CO2 or 90/10 CH4/CO2 - at a given temperature and pressure. The rate of depressurization and the end of each soak period is usually in the 20-40 bar/min range. Material performance is determined, not by leakage, but by inspection; the seal is quartered, with each exposed surface given a rating according to the number and length of fractures present. This system is useful in comparing materials and in compound development. However, since unacceptable damage does not necessarily correlate with leakage under pressure, judgments based on experience still have to be made. Another method of inspection is the use of high resolution x-ray tomography; Figure 1 shows images obtained at TWI for an elastomer o-ring sample that has experienced an RGD event where significant internal cracking is evident.

Fig.1. Digital x-ray inspection of elastomeric o-ring subject to an RGD event
Fig.1. Digital x-ray inspection of elastomeric o-ring subject to an RGD event

It is possible to design out RGD damage; in one example, for subsea chokes operating at high pressure/high temperature (HPHT) conditions; this was achieved by changing the degree of groove fill. The 'standard' for o-rings typically provides a volume groove fill of around 70% (this varies with the different section sizes etc). By redesigning the seal housings, external constraint can limit the degree of swelling and hence the internal damage. It may not always be possible, or desirable, to have high groove fill, but it can be effective. In some situations this can be achieved by the inclusion of a thermoplastic back-up ring.

The majority of commercially available RGD-resistant compounds are high hardness materials; 85-95 Shore A. The high modulus restricts bubble growth but may make seal installation more difficult. The downside of high modulus is low tear strength. Some suppliers claim to take an alternative route; to manipulate the morphology of the cured rubber, by compounding means, in order to improve crack growth resistance. To summarise, Table 7 lists the factors which have the greatest influence on the RGD resistance of sealing elastomers.

Table 7 Factors which have the greatest influence on the RGD resistance of sealing elastomers

RGD damage increased by;Comment
High gas pressure Particularly above 100bar
High gas concentration Gas solubility varies; CO2 is more soluble in oilfield elastomers than CH4; thus CO2 is more aggressive
High decompression rate Rates above 0.7bar/min are cause for concern
Low gas diffusion rate Diffusion coefficient (D) dependent on gas, elastomer type and temperature
Temperature By the reduction of mechanical properties
Poor constraint Elastomers with low constraint (no back-ups, low groove fill) can allow blisters to form

Due to their perceived vulnerability, there has generally been greatest oil and gas industry focus on elastomers in contact with CO2, although little of this relates to supercritical conditions. The performance of other polymers such as thermoplastics, and their behaviour in supercritical CO2, remain less well established[Davies et al, 1999]. With increasing solubility and solvating power there may be greater risk of RGD effects, swelling and associated loss of mechanical properties and leaching, resulting in an unpredicted change in rate of chemical ageing.

3. Summary and future outlook

CCS is a technology that is at present mainly driven by climate change. This means development and deployment will not happen without consideration of both technological issues as well as policy intervention.

Issues related to corrosion of carbon steel in wet and dry CO2 environments are well documented. It is generally agreed that pure, dry CO2 is essentially non-corrosive to carbon steels. Use of corrosion resistant alloys is generally recommended for wet CO2 environments. For CCS, the CO2 captured from power plants is likely to contain impurities such as NOx, SOx etc (depending on combustion process) which could have significant implications in terms of the corrosion of pipelines for its transport. More research is needed to quantify the corrosion behaviour in high pressure CO2 with different amounts of impurities such as SOx, NOx, O2, H2S and H2O. Pipelines for transport will inevitably contain joints, which will include welded structures and/or elastomeric seals. Corrosion behaviour of welded structures in dense phase 'impure' CO2 also needs research. Elastomeric seals (80-90 durometer hardness) are generally recommended for sealing pipeline structures for EOR. However, the CO2 used for EOR tends to be fairly pure. For impure CO2 the decompression behaviour is likely to be different, as the equation of state with impurities will be different and thus needs further research. Very little is known about the permeability and solubility of the dense phase 'impure CO2' in elastomers. Thus, the elastomers now in service for sealing CO2 pipelines/equipment need to be re-evaluated to confirm their suitability for CCS applications.

Structural integrity of transport systems is important for safe transport of dense phase CO2. The fracture propagation characteristics of pipelines transporting CO2 are likely to be different to those experienced by natural gas pipelines due to differences in cooling behaviour associated with a leak, expansion characteristics and equations of state of the dense phase. An equation of state for CO2 with different impurities is yet to be developed. Unless such an equation is developed, fracture behaviour of pipelines transporting 'impure' CO2 needs to be experimentally determined.

Carbon capture and storage technology is at a very crucial stage in its development. Whilst all the different facets making up CCS are in operation somewhere for some reason, a single full-scale end-to-end plant is yet to be built. A few demonstration projects are now underway to prove viability of CCS. The UK Government in its Energy White Paper recognised the importance of CCS, but has agreed to provide limited funding for large scale demonstration programmes. Such programmes will pave the way for full-scale industrial deployment of CCS. This remains a pressing issue and cause of much anxiety for the stakeholders.

In addition, existing standards and best practice guides for handling CO2, most of which were developed for the oil and gas industry needs, require modification (Table 8). Specific guidelines for CCS do not exist in the public domain. Some initiatives are underway to develop specific guidelines for CO2 transport which will possibly supplement the existing design codes and standards[Eldevik, 2008].

Key cost drivers include the needs to:

  1. identify cost effective layouts of future CO2 transport infrastructures in the EU,
  2. assess the organisational implications of such an infrastructure,
  3. assess the costs involved with the operation of CO2 pipelines, and estimate tariffs for third party access,
  4. improve and possibly harmonise the legal framework with respect to safety of CO2 transport in EU member states,
  5. decrease maintenance and inspection costs by adopting better technology,
  6. increase the employment opportunities within the energy sectors.

Overall, whilst the main driver for all greenhouse gas mitigation measures, not just CCS, will be emissions policy, both at national and international level, it will be impossible to achieve effective CCS without a concerted effort to develop the necessary materials solutions.

Table 8 Specifications used in industry for operations involving CO2

49 CFR 195 Transportation of hazardous liquids by pipeline Only valid for pipeline transport of supercritical CO2
NACE TM0192-2003 Evaluating elastomeric materials in carbon dioxide decompression environments A general test method only valid for >99% CO2. The test is conducted below 30°C at pressures <53bar. Thus not valid for supercritical CO2
NACE TM0297-2008 Effect of high-temperature, high-pressure carbon dioxide decompression on elastomeric materials Only valid for >99% CO2. Test temperatures and pressures within the supercritical range, but not valid for CO2 with impurities
NORSOK M-CR-710 2001 Qualification of non-metallic materials and manufacturers Valid in the supercritical range, but only for CO2 with different amounts of CH4
API Spec 5L and 5LD Specification for line pipe and specification for CRA or lined steel pipe These are only used for well and field piping
BS PD 1080 Part 1 Steel pipelines on land and 2 - subsea pipelines Takes CO2 as a non-flammable, non-toxic fluid which is gaseous at ambient temperature and pressure
DNV OS-F101 2007 Submarine pipeline systems Only valid for submarine pipelines. No mention of supercritical phase CO2 transport
BS EN 14161 Petroleum and natural gas industries, pipeline transportation systems Not valid for CO2 transport in a strict sense. However, the standard mentions CO2 as a non-flammable, non-toxic fluid which is gaseous at ambient temperature and pressure
ASME B31.4 and B31.8 Transportation of liquids and gases by pipeline B31.8 specifically excludes pipelines carrying CO2, and whilst B31.4 does not specifically include CO2 within the list of fluids to which the code is intended to apply

4. Concluding remarks

In this review materials technology gaps in handling high pressure CO2 were identified. The data obtained from the literature suggests that knowledge exists in handling dry, pure CO2 at high pressures, but little experience exists in handling large volumes of high pressure CO2 with impurities. Thus research needs to be done to gain knowledge of:

  • Corrosion of metallic materials, eg for pipelines, in CO2-rich fluids containing impurities at high pressure, ie supercritical fluid or dense phase. This should include strategies in case of accidental incorporation ofimpurities such as water in the pipeline system.
  • Fracture propagation in pipelines transporting CO2-rich fluid at high pressure. Also the amount of impurities acceptable for safe transport at a given operation pressure.
  • Degradation behaviour of polymers in the presence of supercritical CO2. This should include examination on plastics and elastomeric seals currently in use in oil and gas service.

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