The economic growth and increasing population have influenced energy demand, causing the latter’s cumulative growth, specifically in terms of the use of fossil fuels as a means to supply this demand. This has had repercussion on the global average greenhouse gas concentrations, having CO2 as the principal component . The biggest challenge in this context is reduction of CO2 emissions into the atmosphere, with the alternative use of diverse energy sources, such as natural gas, ethanol, nuclear energy, etc. .
To reduce the CO2 level in the atmosphere, CO2 capture and storage has been planned and used, this CO2 being stored, mostly, in depleted oil and gas reservoirs; however, some other places have also been considered, such as saline aquifers and coal seams. Some examples of these projects are RECOPOL (coal seam in Poland), Allison Unit (enhanced coal bed methane in Mexico), Selipner (gas field in Norway), Salah gas (project launched by British Petrochemicals and Statoil in Algeria), Ketzin field (enhanced gas recovery in Germany) and some others . According to the Intergovernmental Panel on Climate Change (IPCC) (2007), to have success in CO2 storage, capacity, injectivity and confinement are required; therefore, well stability is really important, and due to some leakage, a path could be created through the well. Hence, to guarantee the wellbore integrity, some authors have established a lifetime of 1000 years [4, 5, 6, 7]. CO2 is injected in the supercritical condition (>31 °C and 7.38 MPa and stored deeper than 800 m)  and reacts with the steel and cement, bringing about damages. When these wells are not designed for injecting CO2 , cement carbonation, microannulus opening and casing corrosion may possibly occur . The objective of this work is to present a general review of the effect of CO2 corrosion in different kinds of steels used as casing, aiming to know the best options to guarantee the casing stability.
Mechanism of CO2 Corrosion
Relation Between Corrosion and Well Integrity
When well stability is talked about, an important topic is corrosion (of either steel or cement). However, in this paper, the focus is on steel corrosion. It is important to mention that every completion in wells requires metallic components (wellhead, Christmas tree, tubing, casing, packer, etc.), which – in most of the cases (not always) – are made of some form of steel that have metallic alloy elements, i.e. chromium .
A CO2 injector well can suffer corrosion in every component, from the wellhead to the down-hole completion components and, therefore, to achieve large success in the CO2 storage project, the wells must bear the highest impact of corrosion ; thus, to know how to resist corrosion, it is necessary to know how it attacks.
CO2is stable, inert and non-corrosive as a gas; however, when it is in the presence of water (either in the aqueous or vapour CO2 phase), dissolution occurs, with subsequent hydration, forming H2CO3 (carbonic acid), which is the principal agent attacking steels ; the principal corrosion products are FeCO3 (iron carbonate) and Fe3C (iron carbide)  but, to understand this mechanism better, analysing how it proceeds step by step is required.
Chemical Reaction of CO2 and H2O
Following Table 1, first the CO2 is hydrated by dissolving in water, forming carbonic acid (H2CO3), which is a weak acid because the CO2 is partly dissociated in water. As carbonic acid is diprotic, it dissociates in two steps, which is considered the main source of acidity. The resulting pH is a function of the CO2 partial pressure. In the first dissociation of carbonic acid, the bicarbonate is obtained (HCO3), which, later on, dissociates into carbonate (CO3) [6, 8].
Reaction of CO2 and H2O.
|Carbon dioxide hydration|
|Carbonic acid dissociation|
|Bicarbonate anion dissociation|
Chemical Interaction of Fe with Environment
Knowing how CO2 reacts in the presence of water, we can see that Fe also reacts with its environment (Table 2). Initially, Fe reacts with carbonic acid, yielding ferrous bicarbonate (Fe(HCO3)2); after this, the precipitation of iron carbonate occurs, in two ways. First, when the concentrations of Fe2+ and CO23– ions reach the maximum solubility limit, they combine forming iron carbonate (FeCO3), with a consequent increase in pH . Second, when the ferrous bicarbonate dissociates, it forms FeCO3 + CO2 + H2O; this water could react with the resultant carbon dioxide, yielding, again, carbonic acid and, in this way, it could result in a cycle of corrosion.
Reaction of Fe with the environment.
|Iron–carbonic acid reaction|
|Iron carbonate precipitation|
The case when CO2 and water are present has been explained, but, normally, water can have different kinds of ions, such as Cl–, Na+, Ca+, SO21– , etc., which can affect the equilibrium of CO2 and the resulting pH . On the other hand, the presence of FeCO3 could lead to a reduction in the corrosion rate because it is formed on the steel surface . Moreover, this protective film is dependent on low temperatures and high supersaturation of Fe2+ and CO23– ; however, this protective film could grow without having any protective property, but, when it does have the property, it could reduce the corrosion rate between 5 and 100 times . Adversely, even when the iron carbonate is precipitated, if it is not compacted on the surface, it cannot prevent the corrosion . Therefore, some analyses have been performed, showing that at low temperatures, the FeCO3 film gets dissolved continuously and the corrosion rate increases . The precipitation kinetics of FeS is almost two orders of magnitude faster than that of FeCO3 at the same conditions ; moreover, FeCO3 was formed after 60 days, and even when there was a reduction in corrosion rate, there was still corrosion . In addition, as shown in Figure 1, it is noted that the electrochemical dissociation of iron leads to surface corrosion.
Finally, although the Fe2+ ion could react later to form the protective film, this could lead to study the corrosion rate and rate of formation of protective film to know whether FeCO3 is having a positive or negative effect, because as mentioned earlier [11, 12, 13], there is still corrosion on steel.
Different Kinds of Steels
CO2 can affect the different materials in CO2 injector wells. Therefore, the metallurgical selection (as well as the type of cement) plays an important role  because the casing steel and other parts of the well can be subject to corrosion when they are exposed to CO2 or formation fluids (or both) (Figure 2). This corrosion can be controlled by using corrosion-resistant alloys (CRAs) . Furthermore, if a CRA is improperly selected, it can lead to mistakes in the future, affecting the performance; hence, taking care of the specific properties of the steels is required because a group of CRAs can be resistant at one temperature; however, this does not guarantee that the CRAs will work with the same performance in a different environment .
Casing and tubing play an important role in wells; so, ensuring their integrity is essential. Therefore, the American Petroleum Institute (API) has standardised some grades of steels, which are differentiated by groups, content of chemical compounds, manufacturing processes and mechanical properties , giving the API steel grade; different names are obtained, qualified by a number that represents the minimum yield strength and a letter chosen arbitrarily, without meaning. Therefore, they have been divided into four groups, categorised by resistance to sulphide stress cracking and working pressure :
- ― Group 1: H-40, J-55, K-55, N-80, R-95;
- ― Group 2: M-65, L-80, C-90, C-95, T-95, C-110;
- ― Group 3: P-110;
- ― Group 4: Q-125.
Furthermore, they can be divided by product specification level (PSL):
- ― PSL-1: Common application casing (H-40, J-55, K-55, M-65, N-80, R-95);
- ― PSL-2: Corrosion-resistant casing (L-80, C-90, T-95, C-110);
- ― PSL-3: Deep well casing (P-110, Q-125).
However, each carbon API steel has the following specific characteristics:
- ― H40: It is an API steel that is not generally used as tubing, due to its yield strength and the saving in terms of cost is minimum compared to J55 ,
- ― J55: This kind of steel is used for most wells if it meets the design criteria. Moreover, when subjected to a CO2 environment, it is recommended that it is normalised and tempered, as it is used for maximum 9000 ft and 4000 psi in land wells .
- ― N80: It should be either normalised or normalised and tempered . Furthermore, it shows susceptibility to H2S, and it is recommended for sweet wells .
- ― L80: Tempered at 620 °C, it has 9Cr and 13Cr steels, being anticorrosive in a CO2 environment; these types should be used at partial pressure of H2S <1.5 psi ,
- ― T95: It is divided into two types, the first one being used in sour facilities .
- ― C110: This C-steel has maximum minimum yield strength. If necessary, the product can be cold-rotated, straightened and subsequently stress-relieved at temperatures between 30 °C and 55 °C below the final specified tempering temperature, or hot-rotated and straightened at temperatures not >165 °C .
- ― P110: This type is restricted to quench-and-tempered heat treatment and is used in deep and sweet wells with high pressures. Even though it has more yielding strength, it is cheaper than C90 and T95 .
- ― Q125: Gag-press straightening or hot-rotating straightening can be performed for straightening, but the temperature at the end of the rotary straightening process should not be <400 °C. However, if this method cannot be used, the product can also be cold-rotated and straightened, but the stress relief must be performed at 510 °C (950 °F) after straightening .
Required chemical composition .
|Chemical composition in mass fraction (%)|
Required mechanical properties .
|Yield strength (MPa)||Minimum tensile strength|
Onoyama et al.  investigated the corrosion resistance of three different compositions of duplex stainless steel. They evaluated the first two in National Association of Corrosion Engineers (NACE) solution at 80 °C for 100 h to get the effect, in percentage, of different compositions of the alloying elements in the steel, finding that it is desirable to reduce the Si percentage (<0.5%), leading to the amount of Ni becoming 10% and increasing the resistance; moreover, Mo and N improve the steel and, Sn and Sb have to be correctly added, neither in excess or nor in lower amount, with the best values being 0.05% Sn and 0.15% Sb. On the other hand, duplex steel was tested in 2.8 × 10–2 mol/L NaCl solution saturated with CO2 and N2 at 260 °C for 100 h at 0.10 and 0.05 MPa, obtaining the maximum value around 8.5 × 10–3 mm/yr at 0.10 MPa of pressure and around 3 × 10-3 mm/yr at 0.05 MPa of pressure.
Kimura et al.  studied the effect of CO2 corrosion in 13Cr steel, modifying the chemical composition of Cu, Ni and Mo, at 3 MPa and 180 °C, inside an autoclave with 20% of NaCl solution saturated with CO2 gas, for 7 days, evaluating the weight loss rate. When there was no addition of Cu, Ni and Mo, the corrosion rate was 1.71 mm/yr, but when these elements were part of the chemical composition, the corrosion rate was <0.3 mm/yr. Moreover, with the increase in Mo content at the same Ni percentage, the corrosion rate decreased. On the other hand, the addition of Cu did not affect the corrosion rate and- the effect of Ni-Cu was not clear.
Another study was carried out by Leth-Olsen , which compared carbon-steel, 13Cr and super 13Cr (S13Cr) in a potassium solution with CO2(g) in the liquid and vapour phases, finding an excellent performance of S13Cr, with an average of 0.01 mm/yr, compared to 13Cr, which had a maximum value of 0.7 mm/yr and 0.3 mm/yr (in the liquid phase). Furthermore, the values of maximum corrosion were noted when the dummies were exposed in the liquid phase, the rates of corrosion in the vapour phase being 0.2 mm/yr for carbon-steel and 0.05 mm/yr for 13Cr; no corrosion was seen in S13Cr.
In 2008, the erosion-corrosion of 22Cr steel was analysed, compared with that of an X65 pipeline under the same conditions. This experiment was evaluated using sand grains under three special conditions. First, by varying the temperature from 20 to 70 °C at a sand concentration of 200 ppm and a CO2 flow of 20 m/s, a constant corrosion rate of around 5 mm/yr was obtained for 22Cr, while X65 showed an increase from 12.25 to 43.5 mm/yr. Second, the solid particle concentration was varied from 30 to 200 ppm, with a temperature of 20 °C and flow velocity of 20 m/s; although having the same tendency, the corrosion rate for 22Cr increased from 0.1 to 2.4 mm/yr approximately, while for X65, it changed from 9 to 12 mm/yr. The last was the variation of velocity from 7 to 20 m/s, maintaining the temperature at 20 °C and concentration of sand particles at 100 ppm; the corrosion rate in 22Cr increased from 0.2 to 0.8 mm/yr, while for X65, it varied from 2.4 to 5.9 mm/yr approximately . Then, it is important to note that an important parameter is considered in this study, namely, the solid particles.
Xu et al.  simulated the 3Cr steel used in the well casing in the Huizhou oilfield, with the same formation water composition to get the effect of CO2 corrosion at different temperatures (45, 65, 85 and 105 °C), measuring every structure in a CO2 environment, comparing the result in terms of temperature and CO2 partial pressure (0.5 and 0.2 MPa). They concluded that by increasing the temperature and pressure, it is possible to gain higher corrosion rates. They observed a corrosion rate of 4.5 mm/yr at CO2 partial pressure of 0.5 MPa and 100 °C; the highest value obtained at CO2 partial pressure of 0.2 MPa was 1.14 mm/yr at 65 °C and approximately 1 mm/yr at 105 °C.
Group 1 (J-55, K-55, N-80)
Cui et al.  evaluated the CO2 corrosion at supercritical conditions (80 °C and 8.274 MPa) in J55, N80 and P110, at different water cuts (30, 50, 70, 90 and 100%), obtaining an increase in corrosion rate with higher water cut amount. Furthermore, N80 and J55 showed similar behaviour (7 and 4 mm/yr) and, at the same time, were better than P110 (9 mm/yr).
Furthermore, Lin et al.  compared the three steels mentioned herein at ion concentrations (g/l) of 19.0 Cl–, 1.14 SO24– , 0.6 HCO–3 , 1.05 Mg+2 , 0.39 Ca+2 , 11.99 Na+ and 0.12 CO23 . First, the pressures (6.89 and 10.34 MPa) were varied at 90 °C; the following values were obtained for the corrosion rate of N80, P110 and J55 steels: 1.752 mm/yr, 2.403 mm/yr, 1.854 mm/yr, 0.922 mm/yr, 1.054 mm/yr and 1.105 mm/yr, respectively. Furthermore, when the pressure was maintained constant (between 1.38 and 2.07 MPa CO2 partial pressure), the corrosion peak was at 100 °C and, after that, it was lower, the best steels being N80 followed by J55.
Some studies have been carried out to compare J-55 and N-80. One on these studies was by Li et al. , who analysed the effect of temperature at 5 MPa of partial pressure and varied the partial pressure at 80 °C over a period of 72 h. Furthermore, these two kinds of steel were compared with carbon steel P110: when pressure is varied, the best result was obtained using J55; however, on varying the temperature, sometimes, the best result was obtained using N80.
When this group of steels is talked about, another important steel item referred to is K55. A study was carried out by Elramady , in which a piece was subjected in formation water with CO2 at 40 psi (0.276 MPa) at ambient temperature, obtaining a rate varying from 0.4 to 0.74 mm/yr. On the other hand, Pehlke  used brine, CO2, H2S and N at 1000 kPa and 170 °C, obtaining a corrosion rate between 0.188 and 0.243 mm/yr for K55 steel.
Furthermore, when corrosion by CO2 is studied, there are other acids that can affect the well apart from the carbonic acid. Jingen et al.  analysed the effect of the ratio of CO2 partial pressure to H2S partial pressure (10, 100, 200 and 400 MPa) in formation water, for N80 steel, at 90 °C and pCO2 equal to 0.4 MPa, having a flow rate of 1.7 m/s; they found that when H2S is not present, the corrosion rate is 1.689 mm/yr, while the ratio is 10; the rate is 0.172 mm/yr, changing to 0.789, 0.621 and 0.511 mm/yr for the subsequent ratios. Additionally, another work studied N80 steel at the same temperature, but at 4 MPa in the present of acetic acid with CO2 in brine. A value of 0.55 mm/yr was obtained in the absence of the acid, but when solid particle concentration was increased to 1000, 3000 and 5000 ppm, the corrosion rate was 1.25, 3.55 and 4.95 mm/yr approximately .
Group 2 (L-80, T-95, C-110)
In this group, one of the most commonly used steels is L80. One of the studies on L80 was by Choi et al. , where the temperature was set at 65 and 90 °C and the CO2 pressures used were 4 MPa (gaseous phase) and 8 and 12 MPa (supercritical phase), in a saline solution of 25% HCl; at 65 °C, the corrosion rate was 8.7, 9.9 and 11 mm/yr, respectively, while at 90 °C, the corrosion rate was 6.1, 3.4 and 4.8 mm/yr, respectively. A similar study was done by Lopes et al. , which analysed the steel at 15 and 30 MPa in brine at 50 °C, obtaining 3.534 mm/yr at 15 MPa after 7 days, but 0.375 mm/yr after 30 days and 2.774 mm/yr at 30 MPa after 7 days.
The corrosion process could be affected by other factors, such as sulphur and water. Qiu et al.  studied corrosion at three temperatures – 60, 90 and 150 °C – and 0.1 MPa of H2S partial pressure and 0.5 MPa of CO2 partial pressure, varying the sulphur content (2 and 4%) and the water content (30 and 70%); the results are shown in Table 5. When the chromium composition of this steel is varied, the corrosion rate changes too, and an example of this is the work by da Silva , which used three different CO2 partial pressures (0.1, 0.3 and 0.65 MPa) at 20 °C with 2, 3 and 5% of NaCl for 72 h, having 0.82% of Cr in twocoupons of L-80 steel (Table 6).
Corrosion rates .
|T (°C)||PH2S (MPa)||PCO2 (MPa)||Cl– (g/l)||S (%)||H2O (%)||Rate (mm/yr)|
Corrosion rates .
|P (bar)||NaCl (%)||Rate (mm/yr)|
Two other steels in this group are T95 and C110, which were investigated by Elgaddafi , where they varied the H2S concentration (0, 10, 50 and 150 ppm) at 38 °C and 41.37 MPa; for T95, the CO2 corrosion rate was 15, 20, 17 and 17.5 mm/yr, while for C110, the values were 13, 14.5 and 9 mm/yr (there was no test for 150 ppm of H2S).
Groups 3 and 4 (P-110, Q-125)
The last two groups contain only two steels, which are used for deep well casing. Regarding the studies on P110, the first corresponds to analysis at 100 and 160 °C with a pressure of 4 MPa in a brine solution for 120 h, obtaining a marked contrast in corrosion rate, with values of 6.1843 and 0.8754 mm/yr . Similarly, Guan  – at 90 °C and 4 MPa – obtained a corrosion rate around 0.8261 mm/yr; at 110 °C with the same pressure, the rate was 0.2489 mm/yr. On the other hand, if the pressure was varied (0.1, 2, 4 and 6 MPa), maintaining the same temperature (100 °C) for 168 h, the results were 0.64, 0.76, 0.91 and 0.83 mm/yr, respectively .
The other steel is Q125. This steel was studied in a CO2 environment, in a brine solution simulated from the Jinlin Oil Field at 1 MPa and 30 °C and a flow of 1 m/s having a corrosion rate of 1.012 mm/yr . Furthermore, varying the temperature (30, 60, 90 and 120 °C) and keeping the pressure at 2 MPa, using formation water from an oilfield, the values obtained were 0.9, 2.8, 3.6 and 2.4 mm/yr . Giving continuity to the investigation from Elgaddafi , increasing the H2S concentration, the corrosion rates were approximately 3.2, 9.5, 10 and 10 mm/yr.
Analysis of CO2 Corrosion Studies
In this section, the corrosion rates in different kinds of API steels obtained by different studies are analysed. The principal objective was gathering not only the corrosion rate but also data on the chemical composition of chromium, nickel and molybdenum, pressure, temperature, duration of experiment, the phase of CO2 and the kind of steel. Every detail was collected and summarised in the Appendix.
Dependency of Corrosion Rates on the Test Time
The different values of corrosion rates indicate that corrosion could be dependent on the test time. Hence, these values were plotted against the days on linear (Figure 3) and semi-log (Figure 4) scales to get better information. There is a clear tendency versus the time in the graphs; in Figure 4, four regions were identified:
- ― From 0 to 3 days, which could be fast growth in corrosion rate, which could be produced by the formation of FeCO3 film.
- ― From 3 to 25 days, in which there is a continuous reduction of the corrosion rate.
- ― From 25 to 45 days, stabilisation of the corrosion rates is initiated, with observation of exponentially reducing rates.
- ― From 45 days onwards, the rates of corrosion are stabilised; there is a plateau, with a corrosion rate of 0.008 mm/yr; however, this value is only an approximation.
With the already-identified four zones of the corrosion mechanism, the tendency was modelled, yielding two curves; the first equation shows a slightly better fit in the initial region, and the second equation is the best simplified tendency approximation along time (blue dotted curve).
|(1): Better curve fit|
|(2): The best simplified curve approximation|
Stabilised Corrosion Rates
To analyse the long-term corrosion rates, these have to be in their plateau; it means, they have to be stabilised. Therefore, every rate with a test time below 45 days was stabilised by the mean of the tendency in Eq. (2) (because it is simpler and well fitted). Furthermore, they were separated by the CO2 phase (vapour and supercritical). Then, to conclude the results observed in both graphs (Figures 5 and 6), it is necessary to refer to the NACE corrosion category, which defines the corrosion rate as low if the value is <0.025 mm/yr, moderate if it ranges between 0.025 and 0.15 mm/yr and high if the value is from 0.16 to 0.25 mm/yr. Thus, the steels could be classified as in Table 7, and in general, the corrosion rate is lower in the supercritical condition, which is the phase of CO2 when it is injected, and higher in the vapour when it goes through the cement paste.
Classification of corrosion rates by steels.
|Category||Steels in CO2 vapour phase||Steels in CO2 supercritical phase|
|P110, 13Cr, Q125, 3Cr, N80, J55, 1Cr, K55||P110, N80, J55, 13Cr, 22Cr|
|Moderate||–||T95, C110, Q125 and L80|
Effect of Chemical Composition of Steels
Addition of chemicals to form steel alloys permit better response against corrosion, especially when chromium is added (it forms stainless steel) and, furthermore, the quantity of nickel and molybdenum could help to prevent CO2 corrosion. The effect of these elements when they are added to steels was analysed (Figures 7–9). There is a clear effect of chromium as a corrosion-protective element. Only its presence in steel reduces corrosion significantly, and at a percentage >20%, it presents a plateau but has a very low corrosion rate. When nickel is added, the rate reduces faster, helping the chromium as a protective element; however, the molybdenum has no significant effect, showing the same tendency as when it is not added. This is in the supercritical condition, because when the vapour phase is observed, the effect is not as high as in the supercritical condition.
Effect of Pressure and Temperature
Studying the effect of these two factors is difficult, because the idea is to analyse by varying one of them and maintaining the other one constant; to observe the effect, however, it was decided to graphically represent them as separate parameters (Figures 10 and 11). Then, varying the pressure (>7.38 MPa is supercritical condition), the lowest corrosion rates are found in the supercritical conditions, and as the pressure becomes higher, lower rates are obtained. However, when the temperature is evaluated, it is difficult to get a tendency probably because different values of pressure could be studied at one temperature.
It is known that different factors could affect the corrosion rates. First, the time of tests has to be considered because a test spreading over 3 days should not be used for determining awell’s stability in CO2–rich conditions, because, as earlier mentioned, for a warranty of stability for >100 years, the corrosion rates must be the lowest as possible. On the other hand, the wall thickness is a factor to be considered in the front side corrosion rates, because the walls could be as thick as 12 mm to >25 mm. Thus, a corrosion rate of 0.06 mm/yr could corrode half the thickness of a wall of 12 mm in 100 years; hence, warrantying the lowest corrosion rates is extremely important and required.
Alternatively, having a steel with high yield strength, such as C110, T95 or P110, is not a warranty for having good corrosion protection, but the chemical elements can help. Furthermore, ensuring good corrosion protection during the injection of CO2 can have the highest effect on the life of the casing and tubing along the well, because, besides the corrosion, the steel can be affected by erosion due to the flow of CO2 along the tubing. Additionally, if the well presents good stability along its injection path, the next important section has to be the cement paste stability, which will be the wall between the casing and the stored CO2. Furthermore, the only steel that presented a relatively worse behaviour was L80, but in the vapour phase of CO2. Finally, by ensuring a corrosion rate around 0.01 mm/yr, in 1000 years, it will corrode 10 mm; but for this to happen, the CO2 has to be in contact with the casing. It means an injectivity spanning 1000 years or breaking through the cement paste after storing.
First, thanks are due to the Pontifical Catholic University of Rio Grande do Sul (PUCRS) because without the university, this work could not have been completed. Furthermore, we thank CAPES and Petrobras, for the award of scholarships, which let us work at PUCRS.
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|Steel||CO2 phase P||(MPa)||T (°C)||(mm/Rate yr)||Reference||(Time days)||C||Cr||Ni||Mo|