Volume 18 Preprint 81
Corrosion Inhibition of Steel in Dense Supercritical CO2 with Sulfurous Acid Impurity
Meng Ma, Yong Xiang, Chen Li, Jiangyun Wang and Laibin Zhang
Keywords: CCS, supercritical CO2, inhibitor, soluble, acid gas impurity
Corrosion inhibition of steel in dense supercritical CO2 with impurities is a newly generated issue concerned with carbon capture and storage (CCS). Based on the experiment results in the current work, the issue of steel corrosion inhibition in dense supercritical CO2 environments with sulfurous acid impurity was investigated and discussed. The experiment results indicated that the Clariant inhibitor 793, 794 and imidazoline-based inhibitor K1 did not show much inhibition effect. It seems like that the diffusion ability of inhibitors in supercritical CO2 was weak or the inhibitors were not soluble in supercritical CO2 phase, so it might result in that the steel sample surface was not covered by the inhibitors. Supercritical CO2 soluble inhibitor is urgently needed in order to effectively reduce the corrosion rate of steel in dense supercritical CO2 environments with kinds of acid gas impurities for CCS purpose.
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Corrosion Inhibition of Steel in Dense Supercritical CO2 with
Sulfurous Acid Impurity
Meng Ma1,2, Yong Xiang1,3,*, Chen Li1,3, Jiangyun Wang4, Laibin Zhang1
of Mechanical and Transportation Engineering, China University of Petroleum,
Beijing, 102249 P.R. China, firstname.lastname@example.org
2Technology Inspection Center of Shengli Oilfield Branch, SINOPEC Corp., Dongying,
257000 P.R. China
3Beijing Key Laboratory of Process Fluid Filtration and Separation, China University of
Petroleum, Beijing 102249 P.R. China
4College of Chemical Engineering, China University of Petroleum, Beijing 102249, P.R. China
Corrosion inhibition of steel in dense supercritical CO2 with impurities is a newly generated
issue concerned with carbon capture and storage (CCS). Based on the experiment results in
the current work, the issue of steel corrosion inhibition in dense supercritical CO2
environments with sulfurous acid impurity was investigated and discussed. The experiment
results indicated that the Clariant inhibitor 793, 794 and imidazoline-based inhibitor K1 did
not show much inhibition effect. It seems like that the diffusion ability of inhibitors in
supercritical CO2 was weak or the inhibitors were not soluble in supercritical CO2 phase, so
it might result in that the steel sample surface was not covered by the inhibitors.
Supercritical CO2 soluble inhibitor is urgently needed in order to effectively reduce the
corrosion rate of steel in dense supercritical CO2 environments with kinds of acid gas
impurities for CCS purpose.
Keywords: CCS, supercritical CO2, inhibitor, soluble, acid gas impurity.
Corrosion of steel in dense supercritical CO2 is one of the hottest research topics in
corrosion science research society due to the continuously increasing attentions of human
beings to the global climate change and carbon capture and storage (CCS), and the latter is
supposed to be the most effective way to address the global climate change problem. It has
been confirmed that when the dense supercritical CO2 is transported in the pipeline mixed
with acid gas impurites (SOx, NOx, H2S, HCl) and H2O, the corrosion rate of pipeline steel
will greatly increase due to the formation of strong acids [1-4], which can provide a bunch
of H+ ions to participate in the cathodic reaction of corrosion process. It was reported that 2
ppmw of HCl contamination in supercritical CO2 can cause a decrease of pH to less than 1.5
. SOx and NOx can also form sulfuric acid and nitric acid, which can also decrease the pH
of the condensates dramatically. The synergistic effect of these acid impurities on the pH
and corrosion is more notable and complex, and their corrosion mechanisms are not clear.
If water can be easily and economically removed, then the problem can be solved
immediately, because many experimental study results [6-10] and the field experiences of
CO2 pipeline transport in USA  and China Shengli Oilfield have shown that, when CO2
was water free or low moisture content, the corrosion rates of inner pipeline steel were zero
or relatively low. If dehydration and the other impurity purification processes are low cost,
any research issues related to the inner corrosion of CO2 pipeline make no sense. The fact
is that the related corrosion research is in the ascendant, and the dehydration process is
not cheap [12, 13]. High cost is the main reason for the restriction of CCS developed in
Using corrosion resistant alloys (CRAs) might be another choice to address this corrosion
problem. However, the huge investment of the pipeline construction should be the barrier
to choose this way, especially for the large-scale scenario of CCS in the future. Also, the
suitable CRAs for supercritical CO2 transport with acid gas impurities have not been
properly selected yet.
Employing Inhibitors to control CO2 corrosion in the oil and gas industry has long history.
The performance of kinds of inhibitor in the CO2-saturated solution has been widely
studied [14-18]. However, these studies were usually under low CO2 partial conditions.
Imidazoline-based inhibitors are the mostly used inhibitors in oil and gas field to control
the CO2 corrosion. When these inhibitors are used to dense supercritical CO2 environments,
the performance of these inhibitors might be unreliable and inefficient . When the water
soluble or volatile inhibitors are used in dense supercritical CO2 environments, the solubility
and diffusion coefficients of the inhibitors might have great difference with the cases when
they are in the liquid or gas phase. Whether these inhibitors can reach the steel surface and
form the stable film to protect the substrate metal is questionable when these inhibitors are
placed in dense supercritical CO2 phase. Whether there is an inhibitor that can withstand
the attack of kinds of acid gas impurities in dense supercritical CO2 phase is also
Currently, there are few open literatures devoted on this issue. The performance of several
inhibitors in supercritical CO2-saturated solution was tested by Zhang et al., while the
performance of inhibitors in water-saturated supercritical CO2 was not addressed .
Morks et al. investigated the impacts of Mn-Mg based zinc phosphate and vanadate used as
the corrosion inhibition method in dense supercritical CO2 for the CCS purpose . The
high inhibition efficiency was achieved when the pH was at 4, while the experiment results
also indicated that the inhibition efficiency was pretty low when pH of the solution was
further lowered to the region of 1-3.
In the present work, three inhibitors were tested in dense supercritical CO2 environment
with sulfurous acid impurity, including Clariant inhibitor 793, 794 and imidazoline-based
inhibitor K1. Sulfurous acid was added as the possible impurity in the CCS CO2 pipeline,
simulating the situation with SO2 and H2O impurities. The weight-loss method was used to
evaluate the inhibition efficiency of the inhibitors. Scanning electron microscopy (SEM),
spectroscopy were employed to investigate the surface morphology, chemical and the
phase compositions of the corroded samples, respectively. The results were discussed and
the research needs were also pointed out for the further investigation.
Materials and methods
Test samples were machined from API 5L X65 pipeline steel. The elemental composition of
the used steel was listed in Table 1. The sample used for weight-loss method had a size of
50×25×3 mm, while the sample used for SEM/EDS, XRD and Raman had a size of 10×10×1
mm. Corrosion inhibitor experiments were performed in a 7.5 L hastelloy autoclave (Cortest,
USA). The Clariant inhibitor 793 and 794 are the inhibitor that Clariant Corporation
specially developed for the inhibition of internal pipeline corrosion of CCS which may
contain SO2 impurity. For the business secret, the compositions of the inhibitors are not
listed in this paper.
Before each test, the samples were polished with silicon carbide (SiC) paper progressively
up to 600 grit, cleaned with isopropyl alcohol (C3H8O) in an ultrasonic bath, dried, and
weighed using an electronic balance with a precision of 0.01 mg. Four samples were placed
inside the autoclave for each test and three samples were for the weight-loss method. N2
was pumped into the autoclave for 2 h to remove the oxygen in the autoclave before each
test. Then, 187.5 ml sulfurous acid (containing 6.0% H2SO3 by weight) and 100 ppm (0.75
ml) or 400 ppmv (3.0 ml) inhibitor were added into the autoclave bottom. Once the
autoclave was sealed, temperature was adjusted. Finally, high pressure CO2 was added into
the autoclave with a gas booster pump to the desired working pressure. Details of the
experimental conditions are given in Table 2.
The weight-loss method was used to calculate the average corrosion rate for three samples
in each test, which were exposed simultaneously to the corrosion environments. After each
test, the samples were cleaned using the Clarke solution (20 g Sb2O3 and 50 g SnCl2 and
concentrated hydrochloric acid to make 1000 ml) , rinsed with de-ionized water, dried,
and weighed by the electronic balance. The average corrosion rate can be calculated by the
following equation :
CR 8.76 104
where, CR is the corrosion rate, mm/year (mm/y); Δm is the weight loss of the sample, g; ρ
is the density of the specimen, g/cm3; S is the area of the sample, cm2; t is the immersion
Table 1: Elemental composition of the API 5L X65 steel (wt%)
The inhibition efficiency was calculated by applying the following formula :
where η is the inhibition efficiency, Wu and Wi are the average weight loss of test samples
after immersed in dense supercritical CO2 without and with inhibitor, respectively. The
morphology and compositions of the corroded small samples were analyzed with SEM/EDS,
XRD, and Raman techniques.
Table 2: Test matrix for the corrosion inhibitor experiments
Results and discussion
The weight-loss results for different test conditions were illustrated in Figure 1. The case
with 400 ppmv inhibitor 794 had an inhibition efficiency of 13.1%, while the case with 400
ppmv inhibitor K1 had an inhibition efficiency of 5.0%, which can also be ignored
considering the system error of the experiments. The cases with 100 and 400 ppmv
inhibitor 793 immersed for 24 h had higher corrosion rates compared with the blank test.
For the 2 h test with 100 ppmv inhibitor 793, the corrosion rate was higher than all cases
immersed for 24 h, even for the case with higher inhibitor concentration. It has been
confirmed by Xiang et al.  that the corrosion rate of carbon steel in supercritical CO2
with SO2 impurity decreased with the immersion time, especially for the initial few hours.
The accumulation of corrosion product scales acting as the barrier between aggressive
media and the base metal.
It can be concluded that all the three inhibitors tested have no obvious corrosion inhibition
effect in dense supercritical CO2 with sulfurous acid impurity. The most possible reason for
this result is that the inhibitors did not reach the inhibitor surface enough to block
Figure 1: Weight-loss results for different test conditions.
The surface morphology SEM images of corroded samples were shown in Figure 2. Many
flower shaped corrosion products were found on the corroded sample surface for all the
cases exposed for 24 h. In the flower shaped corrosion products, there were many strip
shaped corrosion products piled up in a very regular arrangement, which have also been
found in tests by other researchers [2, 4]. For the case exposed for 2 h, there were many
cracks on the sample surface, which was similar with the surface morphology of the X70
steel sample corroded in dense supercritical CO2/SO2/O2/H2O with a relative humidity of 50%
immersed for 120 h . It seems like that the inhibitors had no obvious impact on the
surface morphology of the corroded samples, which might indirectly indicate that the
corrosion inhibition effect of these inhibitors were weak in dense supercritical CO2 with
sulfurous acid impurity.
Figure 2: Surface morphology of corroded samples for different test conditions. (a) Blank
test, 24 h; (b) 100 ppmv inhibitor 793, 2 h; (c) 100 ppmv inhibitor 793, 24 h; (d) 400 ppmv
inhibitor 793, 24 h; (e) 400 ppmv inhibitor 794, 24 h.
The elemental compositions of marked regions A to E based on the EDS detection results
were shown in Table 3. For all the cases, Fe, S, and O were detected as the main elemental
compositions of the corrosion products. Element carbon was detected for most of the cases,
while Si was only found in region B, which came from the original steel composition.
Table 3: Elemental compositions of marked regions (mol%).
The surface morphology of corroded samples after removal of scales for the case with 400
ppmv inhibitor 794 exposed for 24 h was illustrated in Figure 3. It can be observed from
the SEM image that the surface of the sample was uneven, which might indicate the
occurrence possibility of further localized corrosion. The occurrence of localized corrosion
of carbon steel in supercritical CO2 with SO2, O2 and H2O impurities has been confirmed by
many studies [6, 25, 26].
Figure 3. Surface morphology of corroded samples after removal of product scales (400
ppmv inhibitor 794, 24 h).
XRD and Raman analysis
The XRD spectra of the blank test sample were shown in Figure 4. Rozenite (FeSO4.4H2O),
ferrous sulfite hydrate (FeSO3.3H2O), and pyrrhotite (Fe7S8) were detected as the main
composition of the corrosion products. Rozenite and ferrous sulfite were the common
corrosion products when SO2 and O2 exist in wet supercritical CO2 [2, 4], while pyrrhotite
(Fe7S8) was seldom found in the corrosion product in that environment. It has to be
mentioned that oxygen was not present in the current study for all the tests. Under
anaerobic condition, SO2 might change into sulphur or sulphide through several steps as
SO2 SO3 S 2O 4 S 4O 6 S 2O3 S S5 S 4 S 3 S 2 S
The similar case was also found by Ruhl and Kranzmann that the inner part of the
FeSO3.xH2O and FeSO4.xH2O corrosion product scales might have changed into iron sulfide
, for the inner part of the product scales might be under anaerobic condition due to the
blocking effect of scales to oxygen.
Figure 4: XRD spectra of corroded sample for the blank test.
The Raman spectra of the corroded sample exposed in supercritical CO2 with sulfurous acid
impurity and 100 ppmv inhibitor 793 exposed for 24 h were illustrated in Figure 5. The
peak at 219.5, 280, and 388.5 cm-1 should indicate the existence of pyrrhotite . The
results of these Raman spectra were unable to show the existence of iron sulfate and sulfite
in the corrosion products. The Raman spectra also revealed no information of possible
residual inhibitor 793 on the corroded sample surface.
It has to be mentioned that the traditional CO2 corrosion product siderite (FeCO3) was not
found in the current tests. The simple reason is that if siderite forms, it will be dissolved by
the sulfurous acid.
Figure 5: Raman spectra of the corroded sample exposed in supercritical CO2 with sulfurous
acid impurity and 100 ppmv inhibitor 793 for 24 h.
All the three inhibitors tested in the current study were verified that they had no notable
corrosion inhibition effect on the X65 steel in dense supercritical CO2 with sulfurous acid
According to the experimental data by Bamberger et al. , the solubility of H2O in
supercritical CO2 is 3400 mol ppm under the experimental conditions of the present study.
Since 187.5 mL sulfurous acid was added into the autoclave for each test, only a small part
of water (2.3 g) coming from the sulfurous acid dissolved in dense supercritical CO2, the
left water formed a separated condensed phase, which contained the dissolved CO2 and
sulfurous acid, and also contained the dissolved inhibitor. The test results possibly
indicated that inhibitors were mostly dissolved in the condensed phase, rather than in the
supercritical CO2 phase. If partition coefficient of inhibitor is defined as the ratio of
concentration of inhibitor in supercritical CO2 phase and in the condensed liquid phase, the
partition coefficient should be small.
Another issue that has to be discussed here is the diffusion coefficient of the inhibitor in
the supercritical CO2 phase. Like the rate controlling step concept, if the diffusion process
becomes to be the barrier of the inhibitor reaching the steel sample surface, it can also
make the inhibitor lose the corrosion inhibition effect due to insufficient inhibitor on the
steel surface. The phase of CO2 in the pipeline may also change into liquid phase, so the
solubility and diffusion coefficient of the inhibitors should also be notable in liquid CO2.
It has been mentioned by Sim et al. that there is no typical common inhibitor to protect
steel at low pH, and it is not yet known that such an inhibitor may exist which can function
in competition with carbonate scale formation in supercritical conditions . It is also not
sure that whether there is an inhibitor that can withstand the attack of kinds of acid gas
impurities, such as SOx, NOx, HCl, and H2S. The synergistic effect of these acid gas
impurities on and corrosion process is complex.
More researches are needed to be done by the inhibitor scientists and engineers. The need
of synthesis and selecting effective inhibitors to inhibit the internal pipeline corrosion of
transported dense supercritical CO2 with kinds of acid gas impurities is urgent. If this way
does not work effectively, removing water or using the CRAs as the pipeline materials
should be reconsidered seriously.
Three possible inhibitors that might be used in dense supercritical CO2 with sulfurous acid
impurity to inhibit the corrosion of pipeline steel were tested for different immersion time
and concentration conditions. The following conclusions can be given:
The inhibition effects of these inhibitors were all weak. The case with 400 ppmv
inhibitor 794 had an inhibition efficiency of 13.1%, while the case with 400 ppmv
inhibitor K1 had an inhibition efficiency of 5.0%, which can also be ignored
considering the system error of the experiments.
Iron sulfate, sulfite and sulfide were found as the main composition of the corrosion
products. When O2 is absent in SO2 containing environment, iron sulfide may form
through several steps.
Supercritical CO2 soluble inhibitor is needed, and it also should have the ability to
protect the carbon steel under dense supercritical CO2 environments with kinds of
acid gas impurities. If this does not work effectivly, removing water or using the
CRAs as the pipeline materials should be reconsidered as the corrosion control
strategy of supercritical CO2 pipeline in CCS senario.
This work received financial support by Science Foundation of China University of Petroleum,
Beijing, China (No. 2462014YJRC043 and 2462015YQ0402).
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