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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61 NACE INTERNATIONAL: VOL. 53, NO. 12 MATERIALS PERFORMANCE DECEMBER 2014 DNV RP J202 3 states, "Pipelines with fluids containing hydrogen sulfide shall be evaluated for sour service according to ISO 15156." Stri ctly sp eakin g, AN SI/NAC E MR0175/ISO 15156 does not apply to super critical CO 2 pipelines or facilities since that standard is specific to oil and gas develop ment. Operating and Upset Conditions in Supercritical CO 2 Typical sources of CO 2 for enhanced oil recover y come from tail gas of f of gas plants, w hile C C S projects are largely aimed at sources from coalfired power plants and cement plants. In some cases, actual CO 2 reservoirs are produced in loca tions such as Jackson Dome, Mississippi, and the Four Corners area of Colorado. The CO 2 can contain a variety of impurities depending on its source, including meth ane (CH 4 ), hydrogen gas (H 2 ), nitrogen gas (N 2 ), H 2 S, nitrogen oxides (NO x ), and sulfur oxides (SO x ). The critical pressure for pure CO 2 is 1,088 psi (7.5 MPa) and the critical temper ature is 88 °F (31 °C). However, it is com mon for CO 2 pipelines in the United States to operate at 2,220 psi (15.3 MPa) and ~100 °F (38 °C). The design and operation of supercriti cal CO 2 pipelines requires consideration of several important mechanisms beyond the common hydraulic and mechanical proper ties. These are water content of the f luid ( from a corrosion and hydrate perspective) and the risk of running ductile fractures. While the latter factor is very important to the design of supercritical CO 2 pipelines, it is not addressed in this article. It is well known that supercritical CO 2 is not corrosive unless a free liquid water phase is present in the pipeline. This can occur for various reasons, such as hydrotest water that remains in the pipeline and upset of the dehydration system. Assuming liquid water is present, there is a risk of hydrate formation. While it is beyond the scope of this article, it is important to con sider the likely phases present in CO 2 rich systems during operation and shut downs to determine whether the systems would contain free liquid water. For example, if hydrates form in preference to liquid water, then corrosion—and thus HIC—might not be a significant problem. The phases that will form under normal pipeline operating conditions and for upsets can be modeled using the CSMGem program. 4 According to Sloan, 4 if the temperature of the CO 2 pipe line is 6.5 °F lower than the temperature calculated by CSMGem for hydrate forma tion (or even lower than 6.5 °F), it can be assumed that hydrates form immediately. If hydrates form but no liquid water is pres ent, then corrosion will not occur and HIC is unlikely. Once pipeline conditions are estab lished and water is not a normal constitu ent, the risk of HIC is limited by the fre quency and duration of upsets that produce liquid water and the timeofwetness on the pipe walls. If possible, timeofwetness should be limited, since the longterm pres ence of water will cause corrosion and the risk that hydrates will form, which could hamper operations. It can only be specu lated that timeofwetness is likely to be restricted to a few days or even weeks, and not months. Risk of SSC and HIC in Supercritical CO 2 There are no studies or data regarding the potential for HIC of line pipe or plate steel when exposed to supercritical CO 2 that contains H 2 S. It is uncertain at this time whether HIC or SSC would even occur under these conditions, and whether or not the H 2 S cracking thresholds used for gas and oil ser vice would be the same for supercritical CO 2 . Just as for corrosion in gaseous CO 2 , the risk of HIC in supercritical CO 2 will depend on the presence of liquid water. The pH of free water under supercritical CO 2 condi tions can be quite low. Choi and Nes ˘ic ´ 5 found that the pH would be ~3.0 to 3.2 under supercritical conditions. Figure 1 shows the relationship between CO 2 pressure, temper ature, and the resulting pH from their work. These investigators found corrosion rates of 18 to 20 mm/y (710 to 788 mpy) in the liquid water phase. In the presence of liquid water, SSC of steel pipelines is a risk FIGURE 1 Effect of temperature and CO 2 pressure on pH of water in supercritical CO 2 .

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