Hydrogen induced cracking (HIC) has been implicated in failures around the world of several sour gas linepipes. Since 1984, Shell Canada Limited's specifications for sour gas linepipes have included mandatory testing to demonstrate adequate resistance to HIC.
A laboratory and field research programme has identified an appropriate laboratory testing medium with acceptance criteria which can be used in 3 qualification test for purchasing linepipe. The laboratory environment results in a surface concentration of hydrogen atoms (CHO) diffusing into the test specimen which is comparable with the highest measured internal surface concentration of hydrogen atoms in operating linepipes, CHO = 14 μmol (hydrogen)/cm3 (steel). Quantification of relative HIC susceptibility in the laboratory test is through calculation of crack thickness (CTR) and crack length (CLR) ratios. Acceptance values for these two ratios ensure minimal tendency for both throughwall cracking and blister formation in the linepipe material. These values are CTR ≤ 1.5%. and CLR ≤ 5%.
Additional work has determined the relative HIC Susceptibilities of existing (bought prior to 1984) linepipes and assessed their suitability for continued service. Values of CHO in operating linepipes and laboratory specimens exposed to sour brines have been measured continuously to determine the effects of time and corrosion inhibitors. Threshold concentrations of hydrogen atoms (CHth) required to initiate HIC have been determined for several steels. HIC can only occur if CHO exceeds CHth. Linepipes bought prior to 1984 may have CHth values as low as 2 μmol/cm3. A HIC-resistant linepipe had a CHth value greater than 26 μmol/cm3.
This paper presents and interprets the results of the research programme and suggests guidelines for developing HIC resistance requirements.
Numerous failures of sour gas linepipes have occurred around the world as a direct or indirect effect of hydrogen induced cracking (HIC) or stepwise cracking (SWC)(l,2,3). Effort has been expended by steel linepipe manufacturers, users and other consulting and research organizations (i) to develop an understanding of the mechanisms involved, (ii) to define a laboratory test method which Could identify and quantify material susceptibility to HIC and (iii) to produce steels with improved resistance to HIC.
Considerable progress has been made in all three of the above endeavours. It is now common practice for companies producing sour natural gas to specify linepipe materials which have undergone additional refining, microal1oying and possibly heat-treating steps to develop superior resistance to HIC. In addition to chemistry limitations, restrictions may be placed on the mechanical aspects of steel and pipe-making. For example the use of continuous casting rather than ingot casting in some instances.
A HIC test method has been approved by the National Association of Corrosion Engineers (NACE). The NACE test method TM-02-B4(4) and variations thereof are often specified in purchase specification requirements as a quality control check. Although this test method defines the manner in which relative susceptibility to HIC can be quantified, it does not specify limits of acceptable damage For actual service. This is the responsibility of the sour gas producer and this pipe fabricator.