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Research Article

Corrosion Investigation of Pipeline Steel in Hydrogen Sulfide Containing Solutions

Saeid Kakooei, Hossein Taheri, Mokhtar Che Ismail and Abolghasem Dolati

The hydrogen-induced cracking (HIC) behavior of X70 pipeline steel was studied by means of Linear Polarization Resistance (LPR), hydrogen permeation tests, weight loss and Scanning Electron Microscopy (SEM). In this study, the dissolved H2S was created by chemical reactions in solution. The specimens were immersed into synthetic sea water saturated with H2S. The experimental results showed that the increase of exposure time and H2S concentration leads to an increase of the hydrogen content in X70 steel, which plays a key role in the initiation and propagation of HIC.

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Saeid Kakooei, Hossein Taheri, Mokhtar Che Ismail and Abolghasem Dolati, 2012. Corrosion Investigation of Pipeline Steel in Hydrogen Sulfide Containing Solutions. Journal of Applied Sciences, 12: 2454-2458.

DOI: 10.3923/jas.2012.2454.2458

Received: September 01, 2012; Accepted: November 01, 2012; Published: January 02, 2013


Several scientific articles have been discussed about Hydrogen Induced Cracking (HIC) of carbon steel pipe (Venegas et al., 2005; Kittel et al., 2008; Asmara and Ismail, 2011). Numerous researchers approved a correlation between HIC and hydrogen concentration (C0). HIC will happen when hydrogen concentration (C0) on metal surfaces exceeds the thresh hold hydrogen concentration (Cth). Cth will increase when material strength increase. C0 depend on different parameter such as H2S partial pressure, pH and composition while Cth is known to be dependent on separation and inclusions in the matrix (Elboujdaini et al., 2003; Shehata et al., 2008).

So far, a lot of work has been done to investigate the corrosion phenomena such as HIC and SCC of X70 pipeline steel. Dong et al. (2009) explained oxide and oxysulfide inclusions in X70 steel are more unfavorable than nitride inclusions in HIC. They found that the hydrogen trap density estimated at room temperature is pretty high that can lead to X70 steel become sensitive to HIC. Arzola et al. (2006) reported the corrosion behavior of X70 pipeline steel exposed in several H2S-containing solutions that indicated the presence of H2S in a NaCl solution decreased the impedance of steel, compared to a NaCl solution free of H2S. They also showed corrosion rate values increased in turbulent flow conditions.

The influence of different H2S concentration on Hydrogen induced cracking in X70 pipeline steel under various temperatures were investigated in this work.


The specimens used in this study were made of X70 pipeline steel with elemental composition as shown in Table 1. The X70 specimen was connected to copper wire and covered with epoxy resin with an exposed area of 1 cm2. The specimens were polished up to 800 grit silicon carbide paper, rinsed with deionised water and degreased in acetone.

Table 1: Elemental composition of X70 steel

Fig. 1: Schematic representation of the experimental test cell: 1: Platinum counter electrode, 2: Temperature probe, 3: Reference electrode, 4: Chemical inlet, 5: Sample holder (working electrode) 6: Gas outlet, 4: Luggin capillary

Table 2: Different concentration of chemicals for test matrix

Experiments were conducted at atmospheric pressure in a glass cell (Fig. 1). A typical three-electrode setup was used with a Saturated Calomel Electrode (SCE) as the reference electrode, a platinum counter electrode and X70 steel specimens as the working electrodes.

Corrosion rates (CR) in weight loss experiment were measured by using following Eq. 7:


where, CR is corrosion rate (mpy), ΔW is the weight loss (mg), D is specimen density (g cm-3), A is specimen exposure surface (in2) and T is exposure time (h).

Na2S.9H2O was chosen as test material to replace H2S because of the toxicity of H2S. Brain solution was 3% NaCl solution. Different concentrations of H2S containing solution were made as shown in Table 2.


The potentiodynamic polarization curves for X70 carbon steel in solutions containing different H2S concentration at 25 and 50°C are shown in Fig. 2 and 3. As it can be seen cathodic curve (hydrogen evolution reaction) was accelerated by increasing H2S concentration while anodic curves showed similar current densities. This anodic curve is related to dissolution of iron.

Fig. 2(a-d): Cyclic polarization curves of X70 carbon steel sample in 3% NaCl solution containing different H2S concentration (C1, C2, C3 and C4) in different exposure times (a) 24, (b) 48, (c) 72 and (d) 96 h at 25°C

Fig. 3(a-d): Cyclic polarization curves of X70 carbon steel sample in 3% NaCl solution containing different H2S concentration (C1, C2, C3 and C4) in different exposure times, (a) 24, (b) 48, (c) 72 and (d) 96 h at 50°C

Fig. 4: The 3D column chart of corrosion rate vs. different H2S concentration (C1, C2, C3 and C4) in different exposure time at 25°C

The change in corrosion values can be explained by growth mechanisms of iron sulfide film. Iron sulfide layer has a thickness limitation. When film grows to critical values, it will be break up. So, when the corrosion rates are minimum, the iron sulfide thickness is the best values and electrons and ferrous ions will transfer through the iron sulfide film.

The mechanism of the effect of hydrogen sulfide on carbon steel is defined by the formation of hydrogen atoms that caused the formation of a molecular surface complex (Fe H-S-H) which is cathodic polarization. Then, some of the hydrogen atoms will diffuse, whereas, other may recombine (Elboujdaini et al., 2003):





Figure 4 and 5 show corrosion rate in different H2S concentration. Changes in corrosion rate are due to iron sulfide film role in surface passivation. Whenever, this protective layer detaches from surface, corrosion rate will increase.

Fig. 5: 3D column chart of corrosion rate vs. different H2S concentration (C1, C2, C3 and C4) in different exposure time at 50°C

Fig. 6: SEM image of corrosion product on sample surface

Fig. 7: EDX analysis of corrosion product

A cover of the black corrosion film was detected on all specimen’s surfaces after exposure in the test solution. Figure 6 illustrates an SEM image specimen after exposure 96 h in 25°C in sour environment.

Fig. 8: SEM image of HIC on sample surface

Table 3: Permeable hydrogen concentration

Cracks in the FeS film show that this layer is not a stable layer for surface passivation and it cannot protect steel surface from further corrosion.

According to Fig. 7, EDX analysis shows high sulfur content in corrosion product that is due to FeS film in sample surface.

Figure 8 shows an SEM image of sample surface exposure 96 h in 25°C in sour environment. HIC is clear in this image.

Table 3 shows the permeable hydrogen concentration. It can be considered as amount of hydrogen that penetrate into the steel and cause HIC. In first step hydrogen attaches the steel by adsorption onto the water to steel interface and then by being absorbed into the steel as hydrogen. The amount of hydrogen penetration depends on the corrosion rate of the steel surface and the concentration of anions such as HS- that reduce the tendency to produce hydrogen gas and promotes the hydrogen (Ho) to enter the steel (Tung et al., 2001). By increasing the temperature, hydrogen concentration increases.


Very thin sulfide film, possibly mackinawite, was formed rapidly on the steel electrode in all experiments with different concentration of H2S.

By increasing the temperature, hydrogen concentration increased. So, corrosion rate increased. HIC was detected in sample surfaces after hydrogen penetration.


Facilities and funding for this study were provided by Kish University, Iran. Also, authors would like to thank Universiti Teknologi PETRONAS for supporting the research work.

Arzola, S., J. Mendoza-Flores, R. Duran-Romero and J. Genesca, 2006. Electrochemical behavior of API X70 steel in hydrogen sulfide-containing solutions. Corrosion, Vol. 62.

Asmara, Y.P. and M.C. Ismail, 2011. Study combinations effects of HAc in H2S/CO2 corrosion. J. Applied Sci., 11: 1821-1826.

Dong, C.F., X.G. Li, Z.Y. Liu and Y.R. Zhang, 2009. Hydrogen-induced cracking and healing behaviour of X70 steel. J. Alloys Compd., 484: 966-972.
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Elboujdaini, M., R.W. Revie and C. Derushie, 2003. Effects of Metallurgical Parameters and non-metallic inclusions on behavior for oil and gas industry steels on hydrogen induced cracking. Corrosion.

Kittel, J., J. Martin, T. Cassagne and C. Bosch, 2008. Hydrogen induced cracking (HIC)-laboratory testing assessment of low alloy steel linepipe. Corrosion.

Shehata, M.T., M. Elboujdaini and R.W. Revie, 2008. Initiation of Stress Corrosion Cracking and Hydrogen-Induced Cracking in Oil and Gas Line-Pipe Steels. In: Safety, Reliability and Risks Associated with Water, Oil and Gas Pipelines, Pluvinage, G. and MH. Elwany (Eds.). Springer, USA., pp: 115-129.

Tung, N., P. Hung and H.D. Tienet, 2001. Study of corrosion control effect of H2S scavengers in multiphase systems. Proceedings of the SPE International Symposium on Oilfield Chemistry, February 13-16, 2001, Houston, Texas, USA -.

Venegas, V., F. Caleyo, J.L. Gonzalez, T. Baudin, J.M. Hallen and R. Penelle, 2005. EBSD study of hydrogen-induced cracking in API-5L-X46 pipeline steel. Scr. Mater., 52: 147-152.
CrossRef  |  

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