Material selection for supercritical CO2 transport

TWI Bulletin, March - April 2011

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 environments. This will enable confident materials selection, safe operation and accurate remaining life assessment to avoid the consequences of 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. As Shiladitya Paul, Paul Woollin, Richard Shepherd and Amir Bahrami report, 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 work explores the state-of-the-art in this field and highlights the areas of technology gap.

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. 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. Finding a path that mitigates emissions while using 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 using fossil fuels whilst minimising impact upon the environment. 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 the formation of supercritical1 or dense phase CO₂), and then transporting and injecting it into storage sites 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.

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 dense phase CO₂. In these cases pipeline transport becomes more attractive as has been used 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 nine 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 3,900 miles of high pressure CO₂ pipelines and injected over 600 × 10⁶ tonnes of CO₂ (Table 1).

Table 1. Some existing long distance CO₂ pipelines

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.

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).

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

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.

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. 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 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.

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).

Table 3. CO₂ quality restrictions for EOR, and recommencations for CCS ^{[De Visser et al, 2008]}

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, X-65 carbon steels) for transport.

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. 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 demonstrated that storage is both safe and has low environmental impact. More than 10Mt of CO₂ extracted from gas processing has been injected into the deep sub-sea Utsira saline formation. 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. 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.

Table 4. Selection of current and planned CO₂ capture and storage projects

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.

Materials issues in transport of CO₂

Corrosion of Steel Pipelines in CO₂-containing environments

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 a 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]}

Dry supercritical CO₂ (pressure 98-158bar) resulted in limited corrosion (approximately 1.3µ m/yr) of type 304 stainless steel at temperatures between 149-238°C for up to 380 days ^{[Propp et al, 1996]}. Similarly for AISI 1080 C-Mn steel, low corrosion values ~10 µm/yr 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 <0.5 µm/yr 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.

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. 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 four to five 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. 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. There are other indirect effects of such as the formation of non-siderite scale. If acetic acid (HAc, where Ac=CH₃COO) is present in the aqueous media, 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. 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. 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. Increase in un-dissociated HAc increases the corrosion rate of carbon steel as it provides a reservoir of H+ ions over and above that determined by the solution. Further work in the field also suggested that HAc is particularly harmful in its un-dissociated state. 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.

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, the control over the latter is difficult as it is dependent on the crude oil composition and hydrodynamic conditions.

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 >10times 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.

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 (MEA) 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 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%. 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. 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. Based on literature, ^{[Sun et al, 2009]} developed an expression relating iron carbonate solubility

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 un-protective scale is usually obtained even at very high supersaturation. 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. 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 a rule-of-thumb criteria for corrosion of carbon steels. The rules of thumb suggest that at >2bar corrosion is likely, implying that corrosion rate may be >1mm/y; whereas at <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.

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 SO_x, NO_x 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, 1998]} and ^{[Mishra et al, 1992]} have reported two opposite effects concerning H₂S. While ^{[Videm et al, 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, 1992]} attributed this effect to the formation of iron sulphide film that apparently was more protective than iron carbonate. It is generally accepted that corrosion in a mixed sweet-sour system is CO₂ dominated if pCO₂/pH₂S>500-1000.

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 catalyse 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 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 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 concentration, as all the data obtained at very different conditions follow the same trend.

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; pCO₂=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.

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, 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 sulphate (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. 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. When inhibitors are required, it is important to assess the compatibility of inhibitors and the chromium-rich surface films grown on Cr-containing steels. 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.

References

Ayello F, Evans K, Thodla R and Sridhar N, 2010: 'Effect of impurities on corrosion of steel in supercritical CO₂'. Corrosion 2010, paper no 10193 (Houston, TX: NACE, 2010).

Choi Y-S and Nesic S, 2010: 'Effect of impurities on the corrosion behaviour of carbon steel in supercritical CO₂-water environments'. Corrosion 2010, paper no 10196 (Houston, TX: NACE, 2010).

De Visser E, Hendriks C, Barrio M, Molnvik M J, de Koeijer G, Liljemark S and le Gallo Y, 2008: 'Dynamics CO₂ quality recommendations'. International Journal of Greenhouse Gas Control, vol.2, pp.478-484.

Mishra B, Olson D L, Al-Hassan S and Salama M M, 1992: 'Physical characteristics of iron carbonate scale formation in line pipe steels'. Corrosion 92, paper no 13 (Houston, TX: NACE, 1992).

Parker M E, Meyer J P and Meadows S R, 2009: Carbon dioxide enhanced oil recovery-injection operations technologies'. Energy Procedia, Vol1, pp3141-3148.

Propp W A, Carleson T E, Wai C M, Taylor P R, Daehling K W, Huang S and Abdel-Latif M, 1996: 'Corrosion in supercritical fluids'. US Department of Energy Report INEL-96/0180, Washington, USA.

Seiersten M and Kongshuag, 2005: 'Materials selection for capture, compression, transport and injection of CO₂'. Carbon dioxide capture for storage in deep geological formations, Vol 2, Elsevier, UK. ISBN: 0 08 044570 5.

Seiersten M, 2001: 'Material selection for separation, transportation and disposal of CO₂'. Corrosion 2001, NACE paper number 01042.

Sun W, Nesic S and Woollam R C, 2009: 'The effect of temperature and ionic strength on iron carbonate (FeCO₃) solubility limit'. Corrosion Science, Vol 51, pp1273-1276.

Thodla R, Francois A and Sridhar N, 2009: 'Materials performance in supercritical CO₂ environments'. Corrosion 2009, NACE paper number 09255.

Videm K, Kvarekvaal J, Perez T and Fitzsimons G, 1998: 'Surface effects on the electrochemistry of iron and carbon steel electrodes in aqueous CO₂ solutions'. Corrosion 98, paper no 1 (Houston, TX: NACE, 1998).

End of part one.

Part two will be published in a subsequent issue of the Bulletin and will deal with the integrity of metallic and polymeric materials in contact with high pressure CO₂.

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. 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 as a liquid and/ or supercritical phase it is often collectively termed a 'dense phase' fluid.

² Organic acids present in the oil and gas production fields have significant influence on CO₂ corrosion. Acetic acid, an organic acid (and often the major constituent in produced organic acids), has long been used to mimic this in laboratory corrosion tests.