Stress Corrosion Cracking of Pipeline Steels

Term paper for the course of

CORROSION AND ENVIRONMENTAL DEGRADATION OF MATERIALS

IIT KHARAGPUR

METALLURGICAL AND MATERIALS ENGINEERING

Introduction

Stress corrosion cracking has been attributed to many engineering failures, some of which have resulted in loss of life and others in significant economic losses. Corrosion and stress corrosion mechanisms are the most frequent causes of pipelines disasters, they cause from 15% to 20% of failures of gas pipelines. Stress corrosion cracking is a dangerous, often discussed mechanism, probably the most complicated from the point of view of prevention and safety.

Especially complex mechanisms including combinations of mechanical fatigue and corrosion are the main features of SCC. Numerous factors affect the process: fracture resistance of a material, its composition, microstructure and inhomogeneity, quality of the surface affecting the initiation period, service conditions (global and local stresses), quality of insulation etc. Natural barriers against the fracture process are reduced or destroyed by the corrosion. The process significantly differs from those of mechanical fatigue in the air as well as surface corrosion. The main reasons why stress corrosion cracking is complicated can be summarized as follows:

SCC damage cannot be detected by usual internal inspection methods indicating changes of walls thickness.

Cracks, creating usually networks, are very thin. Pipelines pressure fluctuations, destroying surface oxide films, accelerate the SCC

process, particularly in basic environments. Various SCC mechanisms can occur in environments of different acidity including

diluted ground solutions (preferably transgranual SCCTGSCC), in a big range of potentials including cathodic polarization.

Mechanism

There are two forms of SCC penetrating from the external surface of buried pipelines. One is intergranular SCC (IGSCC) and is usually called the “high pH SCC” or “classical SCC”. The other is transgranular SCC (TGSCC), and is designated “near-neutral pH SCC” or “low pH SCC” or “non-classical SCC”.

Intergranular stress corrosion cracking of high pressure gas pipelines occurs most commonly as a result of hoop (circumferential) stresses due to internal operating pressures and results in longitudinally orientated cracks. Stress corrosion testing of pipelines, usually on long test pieces, is most commonly performed in the axial direction of the pipe. The primary corrosion mitigation of the external surface of high pressure steel gas pipelines is protective coatings with secondary protection usually by cathodic protection. Adhesion and resistance to cathodic disbondment of the coating is critical for its integrity and grit blasting is an important process in achieving this adhesion.

High pH SCC and near-neutral pH SCC of pipelines

There are many similarities between the two forms of pipeline SCC. Cracks of both forms usually occur on the outside surface in colonies, mostly oriented longitudinally along the pipe, primarily at the bottom of the pipeline. These cracks coalescence to form long shallow flaws, that can lead to ruptures. The fracture surfaces are usually covered with black magnetite film or an iron carbonate film. However, there are many differences between the two forms of pipeline SCC. High pH SCC, engendered by concentrated bicarbonate or carbonate-bicarbonate solutions associated with pH of 9, has usually an intergranular morphology, and the cracks are sharp, with little lateral corrosion. Near-neutral pH SCC, engendered by dilute ground water with a relatively low pH of around 6.5, has a trangranular, qua quasi-cleavage crack morphology with very little branching. The transgranular cracks are generally wide with appreciable lateral corrosion of the crack sides. Moreover, the near-neutral pH SCC occurs over a wider potential range than high pH SCC which has only narrow width of no more than 100 mV.

SCC requires the simultaneous action of the following three factors: potent environment at the pipe surface susceptible pipe material stress

If any of these can be eliminated or reduced, then SCC can be prevented.

Environmental conditions

SCC failures have been mostly associated with high electrical resistivity tape coatings. The composition of the groundwater solution depends on the amount of cathodic protection current reaching the pipe surface. The ground water is not be changed if the coating does not allow the cathodic protection current to pass through, or if there is high electrical resistances within the soil or the solution in the crevice between the pipeline surface and the coating, or if there is no significant cathodic protection current reaching the exposed

Figure 1: Example of SCC on gas pipeline in acid environment.

Figure 2: Potential-pH diagram showing the regimes for IGSCC and TGSCC at 24◦C in solutions containing different amounts of CO32−

,HCO−3 and CO2 to achieve different pH values

surfaces. The natural ground water solution has a pH from 6 to 7 resulting from the equilibrium between HCO3

- and CO32−. This solution can cause TGSCC.

However, a substantial cathodic current at the pipeline surface causes hydroxyl ions to be generated and accumulated, and the pH increases according to reaction:O2 + 2H2O + 4e = 4OH− The solution chemistry also relates to the conversion of bicarbonate to carbonate ions. With time, the solution becomes concentrated and the concentration of carbonate is high, which leads to the tendency for the solution to passivate the steel surface, and IGSCC can occur.

There is a difference of the polarization curve measured in the high pH solution and the near-neutral solution. In the high pH solution, the curve exhibits an active-passive transition over a certain potential range as illustrated in Fig. 3 from the work of Parkins. This transition has been shown to be associated with IGSCC of ferritic steels in various environments. In contrast, the near-neutral pH environments do not promote passivation and do not exhibit an active-passive transition (Fig. 4).

Metallurgical conditions

Asahi showed that, for a range of pipeline steels from X52 to X80 grades, thermomechanical controlled processing or quenched and tempered steels with fine-grained bainitic structures, or acicular ferrite, uniform microstructures, were more resistant to IGSCC than controlled rolled steels with ferrite-pearlite structures. It is well established that the mill scaled surfaces on pipeline steels are more susceptible to SCC than polished surfaces.

Figure 3: Potentiodynamic polarization curves showing the potential range for IGSCC in concentrated carbonate bicarbonate solution at 90◦C.

Figure 4 :Fast and slow sweep rate polarization curves at 24◦C for a line pipe steel in simulated ground water saturated with CO2, pH=5.8.

Figure 5: SCC in zones with different microstructure in heat affected zone of X60 steel pre-strained to 1% plastic

deformation.

Moreover, if appropriately applied, grit blasting leaves the pipe surface in a state of compression that is beneficial in at least delaying, if not preventing, the incidence of SCC in a variety of system.

Mechanical conditions

In order to propagate for SCC cracks, there must be an appropriate stress at the crack tip. Beavers found that pressure fluctuations may be necessary for cracks to occur not only with near-neutral pH SCC but also with high pH SCC. Parkins showed that cyclic loading significantly decreased the threshold stress for IGSCC below that associated with a static load.

The effect of surface roughness, from grit blasting, on the intergranular stress corrosion cracking resistance of X70 gas pipelines was investigated using slow strain rate testing in carbonate/bicarbonate solution at 75 °C.

Time to failure ratios decreased with increasing surface roughness indicating reduced stress corrosion cracking resistance. The reduced resistance to cracking with increasing roughness would be predominantly associated with stress concentration effects related to the surface roughness resulting from the grit blasting. Crack concentration decreased with increasing roughness, which is likely to be associated with the

concentration of surface damage from the grit blasting using varying sized grit. The stress concentration factors associated with the roughened surfaces may be similar to corrosion pits, where Beavers et al. stated that 0.25 mm wide pits, 0.65 μm deep, had a stress concentration of approximately 2.1.

Discussion

The reduced resistance to stress corrosion cracking with increasing surface roughness was likely to be associated with the stress concentration effect of the grit blasted surfaces. Surface structural inhomogeneities, either different microstructure zones in the steel or sulphide and other inclusions were priority initiation sites of microcracks.

Both stress concentration and compressive residual stresses from grit blasting are likely to contribute to stress corrosion cracking behaviour. As formed pipe surfaces, with no grit

Figure 6: Effect of roughness, Ra, on time to failure for all grit blasted samples. Note the surface roughness is not relevant to the as formed

samples.

blasting, resulted in some of the lowest time to failure ratios and hence some of the lowest resistances to stress corrosion cracking. These also showed some of the deepest cracks.

References

Peter Kentish, Stress corrosion cracking of gas pipelines – Effect of surface roughness, orientations and flattening, Corrosion Science, Volume 49, Issue 6, June 2007, Pages 2521–2533.

I. Černý, V. Linhart, An evaluation of the resistance of pipeline steels to initiation and early growth of stress corrosion cracks, Engineering Fracture Mechanics, Volume 71, Issues 4–6, March–April 2004, Pages 913–921.

B.W. Pan, X. Peng, W.Y. Chu , Y.J. Su, L.J. Qiao, Stress corrosion cracking of API X-60 pipeline in a soil containing water, Materials Science and Engineering: A, Volume 434, Issues 1–2, 25 October 2006, Pages 76–81.

M.A. Arafin, J.A. Szpunar, A new understanding of intergranular stress corrosion cracking resistance of pipeline steel through grain boundary character and crystallographic texture studies, Corrosion Science, Volume 51, Issue 1, January 2009, Pages 119–128.