Corrosion behavior of American Petroleum Institute (API) 5L grade B and X52 steels in 3% sodium chloride in distilled water was studied under CO2 and HzS gas mixtures (varying from 7 (483) to 72 (496) psi (kPa), and from 0.0017 (12) to 0.0060 (41) psi (Pa), respectively) at 100 °F (38 °C). Corrosion rates were determined through a coupon weight loss technique for both steels. In general, as CO2 partial pressure was augmented, corrosion rates increased for a given H2S partial pressure regardless of the type of steel. Nonetheless, as HzS partial pressure was increased (for a given CO2 partial pressure), corrosion rates varied differently according to the type of steel tested. For API 5L grade B, with incremental H2S levels, corrosion rates reached a maximum to then decrease, whereas for API 5L grade X52, corrosions rates kept increasing with HzS partial pressure. In many cases, corrosion rates for both steels were similar under the same conditions. However, in some instances (at 0.0017 psi (12 Pa) of H2S) API 5LX52 steel suffered from blistering and crack formation as that observed in Hydrogen Induced Cracking (HIC) of heavily deformed steel as revealed by surface and metallographic examination of the samples after testing. In such cases, where rates differed between the two steels, API 5LX52 exhibited larger corrosion rates (above 8 mpy (0.20 ram/y)) with no blistering for a given set of conditions. In addition to the mechanical and metallurgical (inclusions, plastic deformation, etc.) differences of a heavily deformed steel, the only effect attributable to variation in the presence or absence of blisters for API 5LX52 (when compared to 5LB steel) was the compaction and the competitive effects at which scales composed of Fe-S and Fe-C-O formed during corrosion,
One of the greatest inconveniences which the oil and gas industry faces, is the large capital investment devoted to control corrosion related issues caused by the aggressiveness of the fluids handled, as in the case of transmission and distribution of natural gas pipelines. Such fluids contain in many instances, contaminants (e.g., CO2 and small amounts of HzS) which in presence of free water, constitute a potential risk of failure. Water arises either by condensation along the stream or by sluggish separation processes during gas processing. The combination of these factors are of most importance to operators since a variety of damages have been attributed to corrosion related phenomena (e.g., pitting, stress corrosion and hydrogen induced cracking). For this reason, the corrossivity of the gas stream is considered of great importance in determining the concentration limits of such aggressive compounds to control internal corrosion of facilities and mitigation programs according to the operating conditions.
Despite the great effort devoted to study COz corrosion, little work has addressed the effect of CO2 with small amounts of H2S as it is often encountered. Ikeda I studied iron under CO2 solutions at 0.0015 psi (10 Pa) of HzS (at 450 psi (3102 kPa) of total pressure), in the 122-352 °F (50-150 °C) temperature range. His findings suggested that the corrosion rate increased reaching a maximum around 212 °F (100 °C). In the case of H2S partial pressures larger than 0.0015 psi (10 Pa), the corrosion rate increased up to 167 °F (75 °C) and then decreased. This effect was attributed at the competitive kinetics of precipitation of FeS and FeCO3. Videm and Kvarekval 2 found that by adding 0.0065 psi (45 Pa) of H2S to CO2 solutions at 158 °F (70 °C), a protective film is formed. Kvarekval 3 also showed that the corrosion rate of AISI 1010 in CO2 accelerated up to 6 times when 0.015 psi (10 Pa) of HzS was present. Ram
