Although intergranular stress corrosion cracking (IGSCC) of high-pressure gas pipelines has been known for more than 20 years, a transgranular form (TGSCC) was detected more recently. Instances of TGSCC have been associated with dilute solutions with pH values in the region of 6.5 because of the presence of carbon dioxide (CO 2 ). Such pH values indicate relatively little, if any, cathodic current reaches the pipe surface, since hydroxyl ions would be generated and pH would increase to values in the region of 10 if current did reach the pipe surface. Slow strain rate testing (SSRT) of pipeline steel specimens in dilute solutions of pH in the region of 6.5 suggested dissolution and hydrogen (H) ingress into the steel are involved in the crack growth mechanism. The initiation of TGSCC in specimens subjected to cyclic loading and maximum stresses approximating those of an operating line was facilitated by pitting. The geometry of the pits allowed the localized generation of solutions of lower pH than that of the bulk solution outside the pits, thereby facilitating dissolution and H discharge.
Over the past several years, investigations have been carried out into the rate of crack growth in pipeline steels in simulated, near-neutral pH, groundwater environment (NS4 solution). Pre-cracked specimens were subject to constant amplitude loading under various frequencies, maximum loads and /{-ratios (minimum/maximum load). Test times varied from about 20 to 400 days. Transgranular crack features, similar to those found in service, have been observed. The extent of crack growth was monitored using either electrical potential drop or detailed metaliographic examinations at two laboratories. The resulting crack growth rates from both labs are consistent with a superposition model based on a summation of fatigue (Paris Law) and static (SCC) crack growth rates. Differences between the results at the two laboratories are discussed.
Hydrostatic testing is one method to confirm the integrity of pipelines containing colonies of stress-corrosion cracks. Although this technique is widely used, a concern of the pipeline industry is the potential for ductile tearing damage of subcritical flaws in pipes with cracks in the base metal and in the welds. The objectives of the current study were to determine the amount of ductile tearing and crack tip blunting that may occur at the crack tips of flaws that survive a hydrotest and to evaluate the influence of metallurgy on the extent of ductile tearing. In this research, stress-corrosion cracks (SCC) were grown in a near-neutral-pH environment in compact tension (CT) specimens made from two heats of X-65 line-pipe steel and one heat of X-52 line-pipe steel with an electric resistance weld (ERW). Simulated hydrostatic tests were performed on these specimens at loads that corresponded to hoop stresses at and above the specified minimum yield strength (SMYS) of the pipe steel, resulting in applied J-integral values near and above J(Q). Some specimens ruptured; some did not fail. Crack tip blunting and the extent of tearing were evaluated. Based on curve fits of the data collected from the CT specimens, the CorLAS™ software was utilized to predict the maximum amount of tearing for cracks of varying flaw dimensions and hydrostatic pressures.
The objective of the work described in this paper was to establish the temperature and potential dependence for propagation of high-pH stress corrosion cracking (SCC) in field environments encountered on TransCanada PipeLine’s system in western Canada. Potentiodynamic and potentiostatic polarization techniques were used to identify the electrochemical potential range for performing SCC tests in the simulated field electrolytes. A slow strain rate technique was used for the SCC assessment. A standard 1N Na2CO3 – 1N NaHCO3 solution was included in the test program as a control. The more dilute simulated field electrolyte was a less potent cracking environment than the 1N Na2CO3 – 1N NaHCO3 solution in that the potential range for cracking was narrower and the maximum cracking velocity was lower at a given temperature. The center of the potential range for cracking with the simulated field electrolyte was consistently more negative than with the 1N Na2CO3 – 1N NaHCO3 solution. This may increase the likelihood that the pipe-to-soil potential of a cathodically protected pipeline lies in the cracking range.
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