Subscribe to our newsletter to receive the latest news and events from TWI:

Subscribe >
Skip to content

Selection of materials for high pressure CO2 transport

Shiladitya Paul, Richard Shepherd and Paul Woollin

TWI, Granta Park, Cambridge CB21 6AL, UK

Paper presented at Third International Forum on the Transportation of CO2 by Pipeline, Newcastle, June 2012


In previous papers [Paul et al, 2010; 2011], a review was presented of the advances made and technology gaps that remain in understanding materials behaviour in high pressure CO2. It became evident that although there is considerable experience of handling lower pressure gaseous CO2, there are no standard test methods and few experimental data for dense phase CO2, especially in the presence of impurities. As the CO2, either captured from power plants, or obtained in produced fluids from Oil and Gas exploration contain additional compounds, data needs to be generated to understand the behaviour of materials in contact with such impure CO2 streams. New test methods are required to assess: (a) corrosion of pipeline metallic materials and welds, (b) degradation, ageing and decompression behaviour of polymeric seals and liners, and (c) structural integrity and fitness for service. The experimental data generated in (a) and (b) when incorporated in (c) give vital information regarding a pipeline's suitability and CO2 service life.

In this paper the effect of materials behaviour, corrosion in the case of metals and degradation in the case of polymers, when in contact with high pressure CO2 is described. The implications of change in materials behaviour on transport of CO2 for CCS are discussed. This understanding will allow confident new build design or rerating of existing infrastructure to proceed.

1 Introduction

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. 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 (Figure 1). When the CO2 is injected back in a sub-surface location to assist oil and gas recovery the operation not only helps reduce emissions, but also enhances the production of oil and gas.

Figure 1 - Various operations involved in the CCS chain showing the pressure and temperature domains superimposed on the CO2 phase diagram.

Figure 1 - Various operations involved in the CCS chain showing the pressure and temperature domains superimposed on the CO2 phase diagram.

The benefits of CCS have been known for many years, but its potential is yet to be fully realised. This is primarily due to the technology gaps that remain in the CCS chain. Some such gaps in knowledge relate to the long term safe storage of CO2 underground, others to the economics of scaling. On the materials side the major issues include corrosion, degradation and structural integrity of pipeline components.

Issues related to corrosion of carbon steel in wet and dry, low pressure 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 (CRAs) 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 polymeric seals. Corrosion behaviour of welded structures, and in particular whether preferential weld corrosion occurs, in dense phase 'impure' CO2 also needs research. Elastomeric seals (80-90 durometer hardness) are generally recommended for sealing CO2 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. Impurities such as H2S are known to cause significant chemical ageing in some polymers. Very little is known about the permeability and solubility of dense phase 'impure CO2' in polymers, generally, and specifically 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.

Another issue that has come up relates to the testing protocols used, particularly for polymeric materials. Typical test regimes might involve the characterisation of materials by the measurement of mechanical properties (typically dumbbell type specimens) following exposure to the required, supercritical, conditions. While this approach allows for the measurement of permanent change as a result of the exposure it provides no indication of the behaviour in service. Additionally, it is well established that CO2 will dissolve at high concentrations at non-supercritical conditions into polymers, often creating damage in the material when depressurised; the phenomenon known as Rapid Gas Depressurisation - RGD or Explosive Decompression - ED (Figure 2). The testing of exposed material samples in the manner described above requires careful management of the depressurisation cycle to avoid any extraneous damage caused by RGD mechanisms - an artefact of the test method rather than the fluid exposure. Others [Butler et al, 2001] have experimented with observation of the materials in the test environment by means of sapphire windowed pressure vessels; however, while such tests provide an insight to behaviours such as swelling they do not address the issue of changing mechanical properties. A more ideal solution would be the development of an in-situ test protocol, evaluating relevant materials properties; TWI has the capacity for such tests and has begun exploratory research programme in this area.

Figure 2 - Schematic showing the events leading to blistering of polymers when depressurized after being exposed to a high pressure fluid.

Figure 2 - Schematic showing the events leading to blistering of polymers when depressurized after being exposed to a high pressure fluid.

In the following document the technology gaps are further explained and some of the data available in the literature is presented with its implications on transport of CO2 (both pure and containing impurities) for CCS. This understanding will allow better understanding of materials behaviour and hence further confidence in new-build infrastructure and better re-rating of existing ones for transport of CO2-rich fluid.

2 Performance of materials in presence of high pressure CO2

2.1 Corrosion of metallic materials

2.1.1 Effect of material type

The importance of constituents of steel and its microstructure on its CO2 corrosion performance has been widely recognised. In the case of carbon steels, the microstructure seems to have a major effect, although the present understanding is inconclusive and consequently the selection of materials based solely on its microstructure remains difficult.

The difference in corrosion behaviour of low alloy steels is often assigned to the shape and distribution of ferrite and cementite resulting from different heat treatments. A microstructure that facilitates the formation of adherent, protective FeCO3 (siderite) scale is implicated to be beneficial for wet CO2 service. The presence of cementite can help anchor the siderite scale onto the steel surface, but its accumulation in the corrosion product has been seen as the cause of increasing corrosion rate over time of exposure for ferritic-perlitic steels [Crolet et al, 1998]. The mechanism of protection seems to be complex. Although needle-like carbides provide a better anchoring surface for the FeCO3 than large ferrite/grains, internal acidification is likely when a thin layer of hollow Fe3C is in contact with the steel. This internal acidification, if it occurs, prevents further formation of protective FeCO3 scale. Hence, presence of Fe3C can have an opposing effect. Only layers obstructed by FeCO3 directly in contact with the metal can be protective. In spite of some discrepancies, the presence of ferritic-pearlitic microstructure in C-Mn steel is reported, in the vast majority, to be desirable compared to martensite due to its superior performance [Chitwood et al, 1994].

The presence of Cr in steel can offer significantly improved CO2-corrosion resistance by forming a stable oxide [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 [Lopez et al, 2003]. However, [Ikeda et al, 1985] showed that even addition of low concentrations of Cr decreases the corrosion rate. Their study suggests that the corrosion rate is almost negligible once 10% Cr is added. However, if low chromium alloy steel is selected, it is worth noting that even though the influence of steel microstructure seems of less importance than for carbon steels, it is recommended to avoid a ferritic-pearlitic microstructure (unlike C-Mn Steels). 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 8-10wt% in conjunction with various microalloying constituents may be essential to achieve satisfactory corrosion performance. This is illustrated in Table 1.

Table 1 Corrosion rate of chromium alloyed steels in CO2-containing water. Test temperature and pressure were 55°C and 13.8bar, respectively and the test were carried out for 7 days (Yanateva, 1954)

%Cr 2.25 5.0 9.0 12.0
Corrosion rate,
mm y-1
1.5 1.17 0.04 0.02

2.1.2 Temperature and pressure

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 high acidity (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].

At room temperature, the process of precipitation is very slow and an unprotective scale is usually obtained even at very high supersaturation. At higher temperatures (>80°C), precipitation is likely to proceed rapidly; often forming dense and protective scales even at low supersaturation thus decreasing corrosion rates [Kermani and Morshed, 2003; Nesic, 2007]. At intermediate temperatures 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 some 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 (i.e. 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 (e.g. high pH), an increase in pCO2 leads to higher supersaturation, which in turn accelerates scale formation. This can lead to lower corrosion rates as observed by [Sun and Nesic 2006].

At very high total pressure, the gas phase-solution phase equilibrium 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).

2.1.3 Effect of impurities

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, has not been extensively studied at high pressures. However, formation of acidic aqueous solutions when these gases are dissolved in water is well known. This might have an impact on the corrosion rate as the sulphates and nitrates of Fe are much more soluble than 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. A selection of data from the literature on 13%Cr steel is presented in Table 2. These specimens were loaded to 100% of yield strength and tested following NACE TM0177 for 720 hours. The table shows that it is not only the concentration of H2S that is important, but also important are the salt content, acidity (pH) and other gases at a given temperature.

Table 2 Stress corrison cracking results with tensile 13% Cr specimens [Asahi et al, 1997]

Chlorides, mg l-1CO2, barH2S, barpHObservations
7200 50 0.02 2.9 no cracks
55800 50 0.02 2.7 cracks
68000 45 0.10 3.3 no cracks
1000 45 0.10 3.0 no cracks

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. [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 disappear 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 were conducted by [Brown et al (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 concentration, as all the data obtained at very different conditions follow the same trend.

Experiments by [Makarenko et al (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; 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 [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; Dugstad et al, 2011]. 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 X65 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 acidifies the surface (decreases the pH) and accelerates the corrosion reaction. [Dugstad et al (2011)] also observed a two-fold increase in corrosion rate of X65 carbon steel by the addition of 200ppm O2 in the CO2 stream at 10°C.

2.2 Polymeric materials

2.2.1 Introduction

Many polymeric materials when exposed to CO2 undergo expansion or swelling depending on the diffusion kinetics of CO2 in the polymer. The diffusion kinetics of high pressure CO2 in polymeric materials depends on the ratio of the diffusion velocity to the relaxation velocity of the polymeric chain. If the diffusion velocity is low compared to the relaxation of the polymers the transport behaviour can be explained using Fick's law of diffusion at time independent boundary conditions. This case applies to temperatures above Tg (the glass transition temperature) in the so-called 'rubbery state'. This state exists in elastomeric seal materials. If the diffusion velocity is high compared to the mobility of the polymer chains, strong swelling in the presence of compressed carbon dioxide can occur.

2.2.2 Ageing

CO2 at high pressure has the ability to diffuse and dissolve in polymeric materials. The initial sorption of CO2 into polymers results in its swelling which changes its mechanical and physical properties. The most important effect during the sorption is the reduction in its Tg, often called the plasticisation. Supercritical CO2 has a strong plasticising effect. CO2 concentrations of 8-10 wt% depress the glass transition temperature of common glassy polymers from the 8-100°C range to below room temperature [Berens et al, 1992].

This ability of high pressure CO2 is often exploited for processing polymers. At conditions above the critical point, CO2 has proven to be a good supercritical fluid solvent for a variety of polymers and co-polymers due to its low viscosity and low surface tension. It is possible to dissolve low molecular weight, slightly polar polymers, such as polystyrene or telechelic polyisobutylene, with molecular weights below 1000 in supercritical CO2. It has also been shown that it is possible to dissolve poly(tetrafluoroethylene-co-hexafluoropropylene) with 19 mol % hexafluoropropylene in CO2 at temperatures in excess of 175°C and pressures near 1000bar [Tuminello et al, 1995].

Supercritical CO2 is a slightly polar solvent which means that its ability to dissolve polymers is temperature dependent (since polar interactions roughly scale with inverse temperature). The interchange energy, a combined effect of segment-segment, segment-CO2, and CO2-CO2 interactions, can be adjusted by varying the temperature over wide ranges. Although CO2 exhibits the temperature-dependent characteristics of a polar solvent, it is only weakly polar which means that it cannot dissolve very polar or hydrogen-bonded polymers, such as poly(acrylic acid), even to 300°C and 2750 bar [Rindfleisch et al, 1996]. CO2 can readily distinguish differences in polymer architecture which means that polymer free volume plays a role in determining solubility. The stiffer the main chain, the more difficult it is to dissolve the polymer in supercritical CO2. The solubility of a polymer or a copolymer in CO2 can be increased if the polymer is at least partially fluorinated. For example, PE (polyethylene) does not dissolve in CO2 even at 270°C and 1750bar, whereas totally fluorinated ethylene-propylene copolymer (TFE-HFP19) does dissolve in CO2 at temperatures >190°C and pressures <1000 bar. In contrast, partially fluorinated ethylene-propylene copolymer (VDF-HFP22) remains dissolved in CO2 at temperatures as low as 100°C and pressures less than 1000bar [Rindfleisch et al, 1996].

While such high temperatures (and perhaps pressures) are less likely to be encountered in CCS transport scenarios the longer term exposures leave uncertainty with respect to their cumulative effects on polymers, be it ageing, swelling with associated plasticisation or some other effect (Table 3). Plasticisers also influence the permeability of CO2 in the polymer. One such example is given in Table 4. The increase in the plasticiser (Di(2-ethylhexyl)-phthalate) content in polyvinyl chloride (PVC) results in notable decrease in permeability at 27°C.

Table 3 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

At more practical Oil & Gas production conditions recent work at TWI has suggested the presence of impurities (specifically H2S) in an otherwise 'pure' CO2 gas feed might modify the permeation and ageing behaviour of an elastomer, on the other hand the same material demonstrated similar (pro rata) permeation rates for conditions above and below the supercritical threshold.

The inclusion of corrosion inhibitors in a transport system can have further implications for the ageing of polymers, the effects are understood in general terms, however, there is little work involving supercritical CO2.

2.2.3 Rapid gas depressurisation (RGD)

Elastomers (as seals) are widely used to contain high pressure gases. These can suffer from decompression damage (e.g. rupture, explosion) when the contained gas is depressurised. Many factors contribute to a rapid decompression event including mechanical behaviour, gas permeation, materials variability, volumetric expansion, hardness and defect size and its distribution. RGD occurs because large amounts of gas can dissolve in an elastomer (rubber) under pressure; for example an unconstrained block of nitrile rubber exposed to compressed air at 5000psi until saturated will release an amount of air approximately 14 times the volume of the rubber when the external pressure is removed. The gas (air in this example) has dissolved slowly in the rubber over an extended period and cannot diffuse out instantaneously when the pressure is removed. The rapidly expanding gas therefore forms bubbles at points of weakness in the material's structure forming bubbles or blisters, tearing the material from within. A common analogy is that of a diver suffering from the 'bends' when rising too rapidly from deep water. Here Nitrogen that has dissolved in the bloodstream and nervous system comes out of solution as bubbles with painful and sometimes fatal results. In another example it is the same process as occurs as when opening a lemonade or cola bottle where CO2 has been forcibly dissolved in the liquid comes out of solution and rises to the surface as bubbles.

Dense phase CO2 is highly invasive and is capable of dissolving polymeric materials. CO2 not only dissolves in crude oil but in many hydrocarbon-based materials. Once CO2 has invaded the material, pressure release results in its supersaturation. This supersaturation results in the nucleation and growth of internal gas bubbles which can then form surface blisters and eventually lead to failure (Figure 2). The effect is aggravated if the decompression rate of the gas through the elastomer is faster compared to the diffusion rate. Gases that dissolve readily in elastomers are likely to cause problems. Gases with low solubility, such as nitrogen, rarely cause a problem.

Table 4 CO2 permeability coefficient in plasticizer-containing PVC and mixtures with other polymers [Pal et al, 1992].

Composition in wt.%Permeability coefficient
10-13 x cm3 cm/cm2s Pa
PVCGraft copolymerNBRPlasticiser (Di(2-ethylhexyl)-phthalate)Additives
59.5 - - 32.7 7.8 120.8
69.8 - - 20.9 9.3 63.2
53.6 8.5 - 29.8 8.1 73.1
17.9 59.2 - 12.7 10.2 52.1
53.6 - 10.0 29.4 7.0 66.0
19.8 28.2 33.3 12.3 6.4 60.1

Silicone elastomers, with high gas permeability, suffer far less than other elastomers. The use of Teflon, Nylon and stiffer elastomers (80-90 durometer) is often recommended where appropriate [Parker et al, 2009]. There are reports suggesting that elastomeric materials (fluorocarbon, nitrile and silicone) are weakened when saturated with CO2 at 40bar pressure, however, the effect is much less pronounced for N80 (nitrile rubber of Shore hardness 80) [Davies et al, 1999]. However, in some North Sea operations involving high salinity water and 0.5mol% CO2 at modest pressures (17bar), nitrile rubber seals used in non-return valves were found to have shrunk 10% in service due to loss of phthalate plasticiser. While the use of phthalates has been reduced generally due to health and safety concerns the same phenomenon might be relevant to other additives in elastomeric compounds. Table 5 describes some of the many variables that influence the RGD resistance of an elastomer.

Table 5 Factors which have the greatest influence on the RGD resistance of sealing elastomers

RGD damage increased by;Comment
High gas pressure Particularly >100bar
High gas concentration Gas solubility varies; CO2 is more soluble in elastomers than CH4
High decompression rate Rates above ~1bar/min are cause for concern
Low gas diffusion rate Diffusion coefficient (D) dependent on gas, elastomer type and temperature
Temperature It affects the mechanical properties
Poor constraint Elastomers with low constraint (no back-ups, low groove fill) can allow blisters to form

It is not possible to provide a straightforward summary of what makes an elastomer 'RGD resistant' in fact with elastomers there is not really such a material; in reality seals are best ranked by their relative resistance. For thermoplastics things are a little more straightforward; as their modulus increases so does their resistance to fracturing as a result of RGD.

3 Implication of the materials behaviour on performance of components in service

3.1 Metallic pipelines, reactors, pumps and infrastructure

3.1.1 Corrosion and SSC Integrity of welded joints

A structure is as good as its weakest link. The weakest link usually comes in the form of a weld or joint. Welds are particularly vulnerable as variability in their properties will arise by changing welding consumables and conditions. In cases where a matching consumable is not available a consumable which is cathodic to the parent should be chosen. This results in a smaller cathodic area thus minimising the anodic current density. Even if a matching consumable is used the HAZ may have very different microstructure from the parent and this can often lead to preferential HAZ or weld metal corrosion.

In addition to these issues, the cracking behaviour of welds in presence of impurities such as H2S is also important. The ISO15156 standard provides guidelines regarding the sulphide stress cracking (SSC) behaviour of metallic materials (both carbon steels and corrosion resistant alloys (CRAs)). This standard should be consulted before selection of materials for use in environments where SSC is likely.

3.1.2 Scale formation in service environments

The formation of a protective, stable carbonate scale has been linked to reduced corrosion rates in CO2-containing solutions. The stability of this layer is dependent on the solution chemistry such as the presence of dissolved salts, compounds affecting the acidity/alkalinity, corrosion inhibitors etc.

The solution acidity 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 the change in acidity/alkalinity that relate to scaling conditions are equally important. High alkalinity results in decreased solubility, increased precipitation and higher scaling tendency of iron carbonate. For example, an increase in the acidity from pH4 to pH5 causes a five-fold reduction in the solubility of iron carbonate; for an increase in the acidity from pH5 to pH6, this reduction is around 100 times [Kermani and Morshed, 2003]. A high alkalinity 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 pH6 may result in very little alteration of corrosion rates as relatively poor, un-protective 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 change in acidity/alkalinity such as the formation of non-siderite scale. If acetic acid (HAc, where Ac = CH3COO) is present in the aqueous media2, increase in alkalinity 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 CO2-containing fluid (e.g. produced fluids in oil and gas production) 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. An 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 pH [Kermani and Morshed, 2003]. Further work in the field also suggested that HAc is particularly harmful in its undissociated 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.

3.1.3 Use of corrosion inhibitors

Experience related to inhibition of CO2 corrosion has been limited to oil and gas exploration. Effective corrosion inhibition in this industry sector has been traditionally accomplished 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 (e.g. ethylene glycol) and alcohols (e.g. methanol) are often added (sometimes >50wt%) to prevent hydrate formation at low temperatures. 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 absence of the alcohol the presence of 1wt% water in similar conditions gave a corrosion rate >10times. Glycols and amines, often used in CO2 capture, have an effect on the hydrate formation and corrosion rate. At lower CO2 pressures, a 50/50 blend of water/glycol is reported to result in a 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 (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 (i.e. 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.

3.2 Polymeric seals, liners and bi-material structures

In service, the combined effect of temperature, pressure, moisture and impurities in the stream can have a serious impact on the integrity of the polymers. Impurities such as SOx, NOx can react with polymers to give a complex variety of compounds. SOx can cause sulphonation, photoxidation and in the presence of water produce strong acids which can catalyse hydrolysis. Similar reactions can also be caused by NOx. Hydrolysis of polymers containing hydrolysis-sensitive has been studied widely. Acetals form parent acid or aldehyde group, esters and amides form corresponding alcohols or amines. Hydrolysis results in depolymerisation and release of the hydrolysed monomers from the polymer. This results in either leaching of small molecules if the functional groups are attached to the side of the backbone chain. However, if the functional group forms the backbone of the polymer this will result in the breakdown of the polymer and hence its integrity.

Polymers on their own are rarely used as structural components. The soft polymers such as elastomers are used as seals and often thermoplastic and thermoset materials are used as liners where the polymer acts as a corrosion barrier and the metallic outer layer provides the mechanical strength. Often composite structures are used in construction materials for CO2 injection wells to exploit the properties of polymers, metals and ceramics (Table 6). When such composite pipelines are used, the annular environment is of importance as the build-up of corrosive environment in the annulus may result in the loss of overall integrity of the polymer-lined structure. The annular environment is controlled by the diffusivity of various molecules in the polymeric layer. In a multi-molecular system, the higher diffusivity of one type of molecules can result in higher concentrations of the molecules in the annular space. Although the molecules may not be corrosive in the concentrations found in the mixture, their concentrations in the annular space may reach corrosive levels. These issues are often observed in polymer-lined systems.

Table 6 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

4 Summary, conclusions and future outlook

The current state of knowledge regarding the behaviour of materials in contact with CO2 has been presented in this paper. It is clear that the property requirements for the various components needed for the safe transport of CO2 cannot be met by use of carbon steel alone unless the CO2 stream is cleaned. The use of CRAs such as 316L, 22%Cr, 25%Cr steel to avoid corrosion in non-scaling conditions is unlikely to be financially viable in the near future. Of course, cladding of such materials on a carbon steel carrier could provide an engineering solution. However, considering the economics and knowing that carbon steel is required for its low permeability, high strength and toughness, and polymeric materials are required for their flexibility, sealing behaviour and high corrosion resistance a combination of the properties of carbon steel and polymeric materials to achieve the desired performance might be useful. An engineering solution using a polymer-lined carbon steel may be sought. This is already in use in the oil and gas industry where the use of a polymer-lined steel pipe exploits the advantages of both its constituents giving an economic solution to problems involving transport of corrosive fluids. The use of polymers with very low CO2 permeability as a liner material should be sought for CCS applications.

Even if a composite pipeline is used for transport of CO2, such a structure would be as strong as its weakest link. In most cases the weakest link comes in the form of a weld or a joint. Careful choice of weld consumable and parameters is essential to ensure optimum performance. The structural integrity of welds is another major concern for CO2 pipelines. This needs to be addressed in conjunction with the materials corrosion behavior. The application of stress in a corrosive CO2-containing environment offers its own challenges. Further work needs to be performed to gain confidence in terms of materials performance in such service conditions.

5 References

Asahi H, Hara T and Sakamoto S, 1997: 'Corrosion properties and application limit of sour resistant 13Cr steel tubing with improved CO2 corrosion resistance'. EUROCORR 97, Vol. 1, Trondheim, Norway, 22-25 September, 1997.

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).

Berens A R, Huvard G S, Korsmeyer R W and Kunig F W, 1992: 'Application of compressed carbon dioxide in the incorporation of additives into polymers'. Journal of Applied Polymer Science, Vol 46, pp231-242.

Brown B, Lee K-L, Nesic S, 2003: 'Corrosion in multiphase flow containing small amounts of H2S'. Corrosion 2003, paper no 03341 (Houston, TX: NACE, 2003).

Butler R, Daview C M and Cooper A I, 2001: 'Emulsion templating using high internal phase supercritical fluid emulsions'. Advanced Materials, Vol 13, pp1459-1463.

Chitwood G, Coyle W and Hilts R, 1994: 'A case history analysis of using plain carbon alloy steel for completion equipment in CO2 service. Corrosion 1994, paper no 20 (Houston, TX: NACE, 1994).

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).

Chokshi K, Sun W and Nesic S, 2005: 'Iron carbonate film growth and the effect of inhibition in CO2 corrosion of mild steel'. Corrosion 2005, paper no. 285 (Houston, TX: NACE International, 2005).

Crolet J L, Thevenot N and Nesic S, 1998: 'The role of conductive corrosion products in the protectiveness of corrosion layers'. Corrosion, Vol 54, pp194-203.

Davies O M, Arnold J C and Sulley S, 1999: 'The mechanical properties of elastomers in high-pressure CO2'. Journal of Materials Science, Vol 34, pp417-422.

Dugstad A, Hemmer H and Seiersten M, 2000: 'Effect of steel microstructure upon corrosion rate and protective iron carbonate film formation'. Corrosion 2000, paper no 23 (Houston, TX: NACE, 2000).

Dugstad A, Morland B and Clausen S, 2011: 'Transport of dense phase CO2 in C-steel pipelines - when is corrosion an issue?'. Corrosion 2011, paper no 70 (Houston, TX: NACE, 2011).

Fang H, Nesic S, Brown B and Wang S, 2006: 'General CO2 corrosion in high salinity brines'. Corrosion 2009, paper no. 06372 (Houston, TX: NACE International, 2006).

Gunaltun Y M and Larrey D, 2000: 'Correlation of cases of top of the line corrosion with calculated water condensation rates'. Corrosion 2000, paper no 71 (Houston, TX: NACE, 2000).

Hesjevik S M, Olsen S and Seiersten M, 2003: 'Corrosion at high CO2 pressure'. Corrosion 2003, NACE paper number 03345.

Ikeda A., Ueda M and Mukai S, 1985: 'Influence of Environmental Factors on Corrosion in CO2 Source Well'. Advances in CO2 Corrosion, Vol 2, pp1-22.

Kermani M B and Morshed A, 2003: 'Carbon dioxide corrosion in oil and gas production- A Compendium'. Corrosion, Vol 59, pp659-683.

Lopez D A, Perez T and Simison S N, 2003: 'The influence of microstructure and chemical composition of carbon and low alloy steels in CO2 corrosion- A state-of-the-art appraisal'. Materials and Design, Vol 24, pp561-575.

Makarenko V D, Shatilo S P, Gumerskii K K and Belyaev, 2000: 'Effect of oxygen and hydrogen sulphide on carbon dioxide corrosion of welded structures of oil and gas installations'. Chemical and Petroleum Engineering, Vol 36, pp125-130.

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).

Nesic S, 2007: 'Key issues related to modelling of internal corrosion of oil and gas pipelines- a review'. Corrosion Science, Vol 49, pp4308-4338.

Nyborg R, 2009: 'Guidelines for prediction of CO2 corrosion in oil and gas production systems'. Institute for Energy Technology Report IFE/KR/E-2009/003, Kjeller, Norway. ISBN 978-82-7017-792-9.

Pal S N, Ramani A V and Subramanian N, 1992: Gas permeability studies on poly(vinly chloride) based polymer blends intended for medical applications'. Journal of Applied Polymer Science, Vol 46, pp 981-990.

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

Paul S, Shepherd R, Bahrami A and Woollin W, 2010: 'Material selection for supercritical CO2 transport'. Proceeding of the International Forum on Transportation of CO2 by Pipelines, Newcastle, 1-2 July 2010.

Paul S, Shepherd R and Woollin W, 2011: 'Material selection for supercritical CO2 transport'. Proceeding of the International Forum on Transportation of CO2 by Pipelines, Newcastle, 22-23 June 2011.

Rindfleisch F, DiNoia T P and McHugh M A, 1996: 'Solubility of polymers and copolymers in supercritical CO2'. Journal of Physical Chemistry, Vol 100, pp15581-15587.

Sun W and Nesic S, 2006: 'Basics revisited: kinetics of iron carbonate scale precipitation in CO2 corrosion'. Corrosion 2006, paper no. 06365 (Houston, TX: NACE International, 2006).

Tanateva O K, 1954: Bulletin of the academy of science of the USSR (English Translation). Division of Chemical Sciences, pp 977-978.

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

Tuminello W H, Dee G T and McHugh M A, 1995: 'Dissolving perfluropolymers in supercritical carbon dioxide'. Macromolecules, Vol 28, pp1506-1510.

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).

Wang S, 2009: 'Effect of oxygen on CO2 corrosion of mild steel'. MS thesis. Ohio University, USA.

WRI, 2008: 'CCS Guidelines: Guidelines for Carbon Dioxide Capture, Transport, and Storage'. World Resources Institute Report. Forbes S, Verma P, Curry T E, Friedman S J and Wade S, (eds). WRI, Washington DC, USA. ISBN 978 1 569 73701 9


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 a 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 [WRI, 2008]. 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. This is quite important for pipeline transport as it implies lower drag. From the cost standpoint, supercritical transport allows for substantially high 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 in supercritical phase it is often collectively termed a 'dense phase' fluid.

2Organic 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.

For more information please email: