Materials Performance

DEC 2014

Materials Performance is the world's most widely circulated magazine dedicated to corrosion prevention and control. MP provides information about the latest corrosion control technologies and practical applications for every industry and environment.

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62 DECEMBER 2014 MATERIALS PERFORMANCE NACE INTERNATIONAL: VOL. 53, NO. 12 MATERIALS SELECTION & DESIGN described by ANSI/NACE MR0175/IS O 15156. When H 2 S is present in the CO 2 stream, the rapid, catastrophic nature of SSC makes consideration essential during supercritical CO 2 pipeline design. In contrast, HIC is often a much slower and less catastrophic cracking mechanism, which also requires some consideration. McIntyre 6 presented over 25 case histories from the Middle East of HIC in pipelines and piping covering years of service. He reported HIC crack growth rates ranging from 0.0 to 0.036 in/y (0.9 mm/y) with one exception where failure occurred in 10 days (~4 in/y [102 mm/y]). This premature fail ure was in the highest H 2 S partial pressure (84 kPa) and lowest pH (3.7) of all the cases reported. In laboratory studies, the crack initia tion rate and growth rates are typically much faster than in actual service for vari ous reasons, such as only onesided charg ing in ser vice compared to multisided charging in laboratory specimens (NACE standard test method TM0284). 7 Also, com pared to small laboratory samples, there are much larger volumes of metal in a pipe line where hydrogen can accumulate before crack initiation. Gonzalez, et al. 8 found a crack growth rate of ~0.09 in/d (2.3 mm/d) in test samples exposed to a solution satu rated with H 2 S. This rate was before crack linkage, which is an important factor in the risk of HIC. Many companies detect HIC early in the process of crack advance but prior to linkage and allow the pipeline or vessel to operate under some limitations until linkage occurs and the component becomes unsafe to operate. Cayard, et al. 9 reported the crack length ratio (% CLR) for two steels, from which the crack growth rate can be approximated. For four days of exposure (the required tim e fram e for HIC t esting p er NAC E TM0284), the crack growth rate was essen tially zero for one steel and 0.18 in/d (4.6 mm/d) for another. After 30 days the rates were 0.05 and 0.07 in/d (1.3 and 1.8 mm/d), respectively. Thus, it can be seen that the crack growth rate from HIC is quite variable and with few exceptions, is relatively slow, espe cially when there is an incubation period of hours or days before achieving sufficient hydrogen absorption to initiate cracks. Discussion and Conclusions Although currently there are no regula tory requirements to design and construct supercritical CO 2 pipelines to resist SSC and HIC if th e y c ont ain s om e H 2 S , it appears prudent as a minimum safeguard to mitigate the risk of SSC. However, the risk of HIC is more difficult to assess in these systems. The corrosion rate from supercritical CO 2 when a free water phase is present can be faster than HIC crack growth rates, and hydrates can form so quickly that HIC is not likely. Moreover, if the presence of a water phase is due to short duration upsets, the dry supercritical CO 2 entering the pipeline can be expected to remove any liquid water, thereby drying the pipeline and eliminating the free water phase necessary for HIC to proceed. The frequency and duration of upsets that permit water to be present in the pipe line must be considered in the decision to require HIC resistance. At the expected low pH of water in contact with supercritical CO 2 , the hydrogen absorption and perme ation could be significant. (TM0284 tests in Solution A represent a similar pH [~2.7]; however, the test solution only contains H 2 S—no CO 2 .) While it is less aggressive than H 2 S in enhancing the absorption of hydrogen in steels, CO 2 still contributes hydrogen to the total amount diffusing into the steel. In addition, since hydrogen is trapped in pipeline steels with little egress after the water is removed, periodic upsets will cause hydrogen to accumulate at traps, and potentially lead to HIC crack initiation at a later time. Therefore, until hydrogen permeation studies can be made using supercritical CO 2 with H 2 S and these results are coupled with HIC tests in the same environment, it is impossible to be confi dent that HIC is not a potential threat for supercritical CO 2 pipelines. Until labora tory testing has been performed to estab lish the level of risk for HIC in supercritical CO 2 , it is prudent to require these pipeline steels to be HIC resistant. References 1 ANSI/NACE MR0175/ISO 15156, "Petroleum and natural gas industries—Materials for use in H 2 Scontaining environments in oil and gas production" (Houston, TX: NACE Inter national, 2009). 2 A S M E B 3 1 . 4 , " P i p e li n e Tra n sp o r t a t i o n Systems for Liquids and Slurries" (New York, NY: ASME International, 2012). 3 DNV RP J202, "Design And Operation of CO 2 Pipeline" (Høvik, Norway : DNV, 2010). 4 E. Dendy Sloan, C.A. Koh, Clathrate Hydrates of Natural Gases, 3rd ed. (Boca Raton, FL: CRC Press, 2008). 5 Y. Choi , S. Nes ˘ic´, "Corrosion Behavior of Carbon Steel in Supercritical CO 2 —Water Environments," CORROSION 2009, paper no. 09256 (Houston, TX: NACE, 2009). 6 D.R. McIntyre, "StepWise Cracking Growth Rates from Service Incidents," Proc. 8th Mid dle East Corrosion Conference, held May 1820, 1998 (Houston, TX: NACE, 1998), pp. 594604. 7 ANSI/NACE TM02842011, "Evaluation of Pipeline and Pressure Vessel Steels for Resis t a n c e t o Hyd r o g e n In d u c e d C ra c k i n g " (Houston, TX: NACE, 2011). 8 J. G o n z a l e s R . R a m i r e z , J. M . H a l l e n , R .A. Guzman , "HydrogenInduced Crack Growth Rate in Steel Plates Exposed to Sour Environments," Corrosion 53 (1997): p. 935. 9 M. Cayard, C. Joia, P. Bezerra, F. Assuncao, "Fracture Toughness and Mechanical Prop erties of CMn Steels Exposed To Wet H 2 S Environments," CORROSION/99, paper no. 384 (Houston, TX: NACE, 1999). BRUCE CRAIG, FNACE, is the subject matter expert at Stress Engineering Services, 13800 Westfair East Dr., Bldg. 3, Houston, TX 77041, e-mail: He has been involved with the evaluation of corrosive oil and gas wells and the transportation of these corrosive fluids for projects ranging from Mobile Bay to the deep water Gulf of Mexico, Asia, and the Middle East for more than 30 years. In addition he has consulted on many projects around the world, including modeling corrosion from CO 2 in wet gas flow lines and pipelines. He has consulted on numerous CO 2 pipelines used to transport supercritical CO 2 and is an expert in sulfide stress cracking. He has a Ph.D. in metallurgical engineering and has published more than 90 papers and seven books. A member of NACE International for 30 years, Craig is a Senior Research Fellow at the Institute for Corrosion and Multiphase Flow, Ohio University.

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