Honda, Hiroshi (Inpex Corporation) | Sunaba, Toshiyuki (Inpex Corporation) | Tomoe, Yasuyoshi (Inpex Corporation) | Watanabe, Tomoko (Japan Oil, Gas and Metals National Corporation) | Foss, Martin (Institute for Energy Technology)
ABSTRACT Loop testing has been carried out to identify the corrosion for 13Cr SS, modified 13Cr SS and 15Cr SS under 2 MPa CO2 in 20,000 ppm NaCl solution with varying concentrations of H2S and organic acids at a temperature of 40°C. It is found that the corrosion behaviors of the steels strongly depend on H2S and organic acids. The results indicate that the 13 Cr SS corrodes significantly at 2 MPa CO2 conditions with H2S present. The modified 13 Cr SS and 15 Cr SS show very good corrosion resistances under CO2 with different H2S partial pressures from 0 to 0.002 MPa. However, severe pitting and general corrosion are observed under the CO2-H2S environments with 0.01 and 0.02 M acetic/propionic acids for both modified 13 Cr SS and 15 Cr SS. INTRODUCTION High CO2 partial pressure and trace amount of H2S have been predicted in current gas development wells. Moreover, very high concentrations of organic acids and chloride in the formation waters have been forecasted. In order to prevent high risk of corrosion caused by these serious environmental factors, corrosion resistant alloys (CRAs) have been widely used in current gas development wells. It is well know that some expensive CRAs, such as 22Cr duplex stainless steels, show very good corrosion performance in CO2 environment with a trace amount of H2S.1 Because of high cost, application of these alloys becomes limited. The 13Cr SS, which is one of the cheap CRAs, was used as a tubing material in the Minami-Nagaoka gas field.1 After in service about 4 years, unfortunately, severe localized corrosions were observed in the tubing located at the shallow parts of the wells shown in Figure 1. It was assumed that the 13Cr SS lost the ability of repassivation due to the high concentration of acetic acid and low pH caused by high CO2 dissolution at low temperatures.
ABSTRACT Aluminide coatings were applied by halide activated pack cementation to austenitic 304 stainless steel substrates. The evolution of coating microstructure as a function of coating process parameters, e.g., temperature, time, etc., was explored. Stainless steel type 304 was chosen as a model substrate to understand the kinetics of aluminizing and for the potential enhancement in high temperature corrosion resistance. The kinetics of the aluminizing process was studied at different temperatures in the 650 – 850°C range and times in the 1 – 25 h range. At 650°C, the coating consisted of a single layer containing two phases tentatively identified as Al5FeNi (Cr) as the matrix with a dispersed aluminide, Al86Fe14. At 850°C, the coatings initially consist of at least two layers containing three phases [with a preliminary identification as Al86Fe14, AlxFey(Ni,Cr) and Al5Fe Ni(Cr) which transitions to a single layer of possibly AlxFey(Ni,Cr) and intermetallic precipitates of undetermined composition. INTRODUCTION Stainless steels are known to have excellent resistance to attack from corrosive media at both room and elevated temperatures. High temperature corrosion is a potential problem for austenitic stainless steels, e.g., 304, used in chemical processing environments.1 Extension of the operating regime and the life of the base alloy can be achieved by the application of protective coatings. Aluminum-containing coatings form stable protective oxide scales, making aluminum a commonly used coating element and aluminizing a ubiquitous coating process.2,3 In the current study, the halide activated pack cementation process was used to apply aluminum diffusion coatings onto the surface of 304 SS. EXPERIMENTAL PROCEDURE Stainless steel samples were cut into 5 mm thick, 12.5 mm diameter coupons. The samples were then taken through standard metallographic preparation procedures by grinding the surface down to 600 grit using silicon carbide abrasive paper. Packs were prepared by mixing powders of aluminum oxide (“filler”), aluminum (“masteralloy”) and aluminum chloride (“activator”).
Cheng, XingGuo (Southwest Research Institute) | Desai, Sapna (Southwest Research Institute) | Gutierrez, Gloria (Southwest Research Institute) | Wellinghoff, Stephen (Southwest Research Institute) | Rossini, Gorge (Southwest Research Institute) | Bredbenner, Todd (Southwest Research Institute) | Yu, Hui (Southwest Research Institute)
Sagara, Masayuki (Sumitomo Metal Industries, LTD) | Nishimura, Akiko (Sumitomo Metal Industries, LTD) | Ueyama, Masaki (Sumitomo Metal Industries, LTD) | Amaya, Hisashi (Sumitomo Metal Industries, LTD) | Ueda, Masakatsu (Sumitomo Metal Industries, LTD) | Kudo, Takeo (Sumitomo Metal Industries, LTD)
ABSTRACT It is very profitable to apply CRA’s (corrosion resistant alloys) to sour environment. Molybdenum has been utilized to enhance the corrosion resistance of conventional alloys. A Mo-less CRA has been newly developed for relatively milder sour conditions considering “fitness for purpose” and saving the cost of the alloy. Copper is used as an alternative corrosion resistant element instead of Mo. Alloying Cu made the new material keep corrosion resistance in a sour environment and saved the cost of material. Evaluating by SSRT and long term C-ring test, the new CRA showed no cracks at elevated temperatures in the combined Cl-, pH and sour conditions. In addition, both pitting and crevice corrosion did not occur in these conditions. To discuss corrosion resistance of the material, the surface film was analyzed after the corrosion test. The stability of the surface film was discussed by estimating an E-pH diagram, solubility of corrosion products, and surface analysis results. INTRODUCTION In recent years, world oil and gas demand has been huge and growing. The increasing demand for oil and gas can lead the target of developing well with high pressure / high temperature（HPHT） or a high concentration of hydrogen sulfide. Corrosion resistant alloys (CRAs) have been used in exploration and production fields which contain high pressure, high temperature and significant amounts of hydrogen sulfide, carbon dioxide and chloride ion.1-3 The strength of material (or wall thickness) and corrosion resistance are required for oil country tubular goods (OCTG) for HPHT wells containing hydrogen sulfide.4-6 From the point of view of saving costs, a CRA that is fit for its purpose can be useful for developing relatively milder sour wells. Up to now, alloying molybdenum was necessary for nickel alloys but that could lead to raising the cost of material as well as alloying nickel.