Journal articles: 'High Pressure High Temperature Corrosion'

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Lasebikan, B. A., A. R. Akisanya, and W. F. Deans. "Autoclave design for high pressure-high temperature corrosion studies." Journal of Engineering, Design and Technology 13, no. 4 (October 5, 2015): 539–55. http://dx.doi.org/10.1108/jedt-08-2013-0057.

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Purpose – The purpose of this paper is to develop an autoclave that can be used to assess corrosion behaviour of suitable material in high-pressure–high-temperature (HPHT) environments. Many new discoveries of oil and gas field are in HPHT environments. The development of such fields requires appropriate selection of materials that are able to withstand not just the service loads but also corrosive production fluids in the HPHT environment. Design/methodology/approach – The exposure of material samples to elevated pressure and temperature is usually done using an autoclave. The suitability of an existing autoclave for HPHT corrosion studies is provided together with suggestions on necessary design modifications. An alternative design of the autoclave is proposed based on functionality requirements and life cycle cost assessment. Findings – It is concluded that the existing autoclave was unsuitable for HPHT corrosion tests, and modifications were very expensive to implement and/or not foolproof. A new autoclave was designed, manufactured, tested and successfully used to study the effect of aqueous solution on the corrosion of a pipe subject to a combination of axial tension, internal pressure and elevated temperature. Research limitations/implications – The maximum design pressure of 15 MPa is more than sufficient for high-pressure corrosion studies in aqueous solution where partial pressure of the dissolved gas is one of the main controlling parameters. However, the design pressure is only suitable for corrosion studies in a seawater environment of up to 1,500 m water depth. Originality/value – A new design of autoclave together with all the necessary piping, assembly and control system is proposed for HPHT corrosion studies. The autoclave can be used as standalone or integrated with a mechanical testing machine and thus enables corrosion studies under a wide range of loading.

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Kobayashi, Kenji, Tomohiko Omura, Atsushi Souma, Taro Ohe, Hisashi Amaya, and Masakatsu Ueda. "Environmental Cracking Susceptibility of Low-Alloy Steels Under a High H2S Pressure and High-Temperature Sour Environment." Corrosion 74, no. 5 (November 30, 2017): 509–19. http://dx.doi.org/10.5006/2669.

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Environmental cracking (EC) susceptibility of low-alloy steels with a specified minimum yield strength of 655 MPa (95 ksi) and 758 MPa (110 ksi) manufactured by quenching and tempering heat treatments was investigated in high H2S partial pressures (more than 1.0 MPa) using four-point bend tests in autoclaves. The H2S partial pressures and testing temperatures varied from 1.0 MPa to 10 MPa and 24°C to 150°C, respectively. Materials of grades 95 ksi and 110 ksi containing high Cr and Mo showed no macrocracking under all tested conditions. Localized corrosion occurred at several locations after exposure for 1 month under high H2S pressure and high-temperature conditions. It was concluded that the localized corrosion did not form macrocracking even after long-term (3 months) immersion tests. On the other hand, 110 ksi grade material containing low Cr and Mo suffered from sulfide stress cracking at low temperatures (below 66°C) and at an H2S pressure of 1.0 MPa. The material also showed EC at an H2S pressure of 10 MPa and temperature from 107°C to 150°C. The difference of EC susceptibility among the materials is discussed based on corrosion reactions, hydrogen absorption, and morphologies of the corrosion products on the steel surface.

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Liu, Shaohu, Liu Yuanliang, Zhong Hong, Zou Jiayan, and Yang Dong. "Experimental study on corrosion resistance of coiled tubing welds in high temperature and pressure environment." PLOS ONE 16, no. 1 (January 22, 2021): e0244237. http://dx.doi.org/10.1371/journal.pone.0244237.

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Coiled tubing (CT) has been widely used for oil and gas exploitation, however corrosion of CT under high pressure and high temperature (HPHT) environment was often reported, also corrosion induced failures of CT welds were often observed to occur during service. Corrosion related behaviors of CT welds are not clear. Therefore, a study of the corrosion resistance of CT welds under HPHT environment is carried out. In order to efficiently evaluate the corrosion resistance of welds, some test samples were obtained by linear cutting out of a CT110 in service on the site. The water samples from gas field were used as the test reagent to simulate the actual corrosive medium. Based on the results of weight loss test under HPHT corrosive environment and tensile test under room conditions, the corrosion sensitivities of the welding seam and base material under various temperatures and partial pressures of CO2 as well as the mechanical properties of the corroded CT were compared and evaluated quantitatively, the corrosion morphologies and material products of the test samples were analyzed by scanning electron microscope (SEM). The test results showed that the corrosion rates of the welding seam in a HPHT caldron were 1.7, 2.0 and 1.2 times of the base metal’s when the total pressure is 4MPa, and the temperature is 30°C, 60°C and 90°C, respectively. The corrosion rates of the welding seam is 2.0, 2.1 and 2.0 times of the base metal’s when the partial pressure of CO2 is 0.1MPa, 0.2MPa and 0.3MPa, respectively. The yield strength of the weld seam after corrosion test was found to be reduced by 4.8% (the yield strength of the base metal was reduced by 4.0%) and its tensile strength was reduced by 8.2% (the base metal was reduced by 7.1%). This indicates that CT weld seam is more susceptible to corrosion than CT base material under service condition.

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Slemnik, Mojca. "Impact of High Temperature and Pressure to Steel Passivation in CO2 Atmosphere." Acta Chimica Slovenica 68, no. 2 (June 15, 2021): 447–57. http://dx.doi.org/10.17344/acsi.2020.6590.

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The corrosion behaviour of AISI 347 in 0.1 M sulfuric acid at temperatures 50 and 75 °C and pressures up to 300 bar in a CO2 atmosphere was studied by surface analysis and electrochemical methods. Corrosion reactions in which CO2 is present accelerate the formation of a protective FeCO3 layer, but the success of such a passivation depends on the saturation concentration and the corresponding temperature. Significantly better results compared to untreated steels were obtained at lower temperatures by increasing the pressure. To explain the differences in corrosion rates between samples, the activation energy for the layer dissolution was also discussed. It can be assumed that the compressibility of the CO2 at different pressures has an influence on the formation of the protective iron carbonate layer and its properties and thus to on the corrosion behaviour.

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Kritzer, P., N. Boukis, and E. Dinjus. "Corrosion of Alloy 625 in High-Temperature, High-Pressure Sulfate Solutions." CORROSION 54, no. 9 (September 1998): 689–99. http://dx.doi.org/10.5006/1.3284888.

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Xu, Peng, Zhengwu Tao, and Zhihong Wang. "Corrosion-resistant systems of formate packer fluid for G3/N80/TP110SS pipes at high temperature, high pressure and high H 2 S/CO 2 ratios." Royal Society Open Science 5, no. 7 (July 2018): 180405. http://dx.doi.org/10.1098/rsos.180405.

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A series of corrosion problems caused by high-temperature, high-pressure and high-acid gas environments has been an issue in oil and gas production for a long time. During the development of a high-acid gas field, the petroleum pipe is subjected to many aspects of corrosion, and the corrosion mechanism is complicated by the condition of the coexistence of H 2 S/CO 2 . Based on the study of the corrosion problem associated with the formate packer fluid in Southwest China, three kinds of steels were studied for corrosion prevention in the alloy G3/N80 steel/TP110SS steel. The study shows that the corrosion rate of the formate packer fluid is low, but corrosion is severe in environments characterized by high temperatures, high pressures and high-acid gas contents. Based on the consideration of cost and the difficulty of realization, an anti-corrosion system was constructed based on the existing packer fluid, mainly through the introduction of a variety of anti-corrosion additives. Through the selection of various additives and corrosion experiments, a corrosion protection system of formate packer fluid was developed. Corrosion tests show that the corrosion rate of the system must be less than 0.076 mm yr −1 to achieve the purpose of corrosion protection. The formate packer fluid with corrosion protection can meet the needs of the current application.

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Ijiri, Masataka, Takayuki Ogi, and Toshihiko Yoshimura. "High-temperature corrosion behavior of high-temperature and high-pressure cavitation processed Cr–Mo steel surface." Heliyon 6, no. 8 (August 2020): e04698. http://dx.doi.org/10.1016/j.heliyon.2020.e04698.

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Lu, Hao Sheng, and Peng Fei Yan. "Effect of Pressure and Temperature of Solution Treatment on the Microstructure and Corrosion Resistance of AZ91D Alloy." Applied Mechanics and Materials 628 (September 2014): 111–14. http://dx.doi.org/10.4028/www.scientific.net/amm.628.111.

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As-cast AZ91D magnesium alloy was solid dissolved at atmospheric temperature under different pressures (room pressure、2、3、4、5 and 6 Gpa) and under high-pressure (6 Gpa) at different temperatures (atmospheric temperature, 200, 400, 600, 800 and 1000 °C). The microstructures of the products were characterized by optical microscope and their corrosion resistance was investigated. The results show that increasing the solution pressure at atmospheric temperature has no obvious effect on the microstructure of AZ91D, but decreases the corrosion resistance. Increasing the solution temperature under the high-pressure can obviously improve the microstructure of the alloy, and markedly increases the corrosion resistance, especially over 400 °C.

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Wan, Li Ping, Ying Feng Meng, Gao Li, and Hua Zhou. "Corrosion Behavior of Drilling Pipe Steels for High Sour Gas Field." Advanced Materials Research 415-417 (December 2011): 2292–97. http://dx.doi.org/10.4028/www.scientific.net/amr.415-417.2292.

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A polymer drilling fluid containing high content of hydrogen sulfide was used as the corrosive medium to investigate the effects of temperature, flow velocity, pH value and partial pressure ratio of CO2/ H2S on the corrosion behavior of high strength drill pipe steel S135 and G105. The morphology and composition of the corrosion products were analyzed as well. It was found that the average corrosion rate of the two types of steel increased with increasing temperature of the corrosive medium, with the corrosion rate to decrease slightly within 60°C-80°C and keep almost unchanged above 120°C. At the same time, the corrosion rate of the drill pipe steels had little to do with the flow rate but increased with decreasing pH value of the corrosive medium. Moreover, the partial pressure ratio of CO2/ H2S had a slight effect on the corrosion behavior of the drill pipe steel. However, the two types of drill pipe steel showed a larger corrosion rate in gas phase than in liquid phase corrosive medium, which was contrary to what were observed in gas and liquid phases corrosion tests of conventional acidic drilling fluids. In addition, it was confirmed by sulfide stress corrosion test that the drill pipe steel of a higher strength had smaller critical stress, and the resistance of the drill pipe to stress attack was ranked as G105(C)＞G105(D)＞S135(B)＞S135(A). It was anticipated that the present research results could be used to guide the selection of materials for drilling pipe steels used in natural gas field of high acidity.

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Mustafa, Abdel Hafiz, Bamban Ariwahjoedi, and M. C. Ismail. "Corrosion Behavior of X52 Steel in High Pressure CO₂ Environment." Advanced Materials Research 686 (April 2013): 234–43. http://dx.doi.org/10.4028/www.scientific.net/amr.686.234.

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Research in high pressure CO2 environment is important in oil and gas industry due to potential development of high pressure CO2 gas fields. Current understanding limits the use of carbon steel pipeline material in this high pressure CO2 environment due to excessive corrosion rates predicted by corrosion prediction software. The aim of this work is to elucidate the corrosion behavior of X52 steel in high pressure CO2 environment. Electrochemical methods of linear polarization resistance (LPR), electrochemical impedance spectroscopy (EIS) and potentiodynamic polarization techniques were employed to study the CO2 corrosion mechanism at high pressures of 10-60 bar at ambient temperature. Surface morphology and chemical composition of corrosion film was studied by using scanning electron microscopy (SEM) and X-ray diffraction (XRD). The results obtained showed that the corrosion rates at high pressures were significantly influenced by CO2 pressure. However FeCO3 and F3C were the main component of the corrosion product film.

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Wang, Ping, Zhan Qu, and Jian Bing Zhang. "Research on Carbon Dioxide Corrosion of Cement Stones of Oil Well Casings under High Temperature and High Pressure." Advanced Materials Research 413 (December 2011): 24–28. http://dx.doi.org/10.4028/www.scientific.net/amr.413.24.

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The effect of CO2 on seal capacity of cement mantle causes casing corrosion and reduces the life of oil well. The corrosion proof of cement system is studied to improve the integrity and seal properties of the cement stone under acidic medium. The CO2 corrosion test of 5 blocks cement under high temperature and high pressure was conducted. Compressive strength, permeability and corrosion depth were measured and morphology after corrosion was observed by scanning electron microscope. A density cement slurry formulations was selected by analyzing the experimental data. It not only has excellent corrosion resistance, but also has properties of anti-gas breakthrough, reduction of free water and stability. It can meet cementing requirement of different well depth conditions.

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Hong, T., and W. P. Jepson. "Corrosion inhibitor studies in large flow loop at high temperature and high pressure." Corrosion Science 43, no. 10 (October 2001): 1839–49. http://dx.doi.org/10.1016/s0010-938x(01)00002-6.

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13

Kuroda, T., F. Matsuda, and K. Bunno. "Stress corrosion cracking of duplex stainless steel in high‐temperature/high‐pressure water." Welding International 9, no. 10 (January 1995): 788–96. http://dx.doi.org/10.1080/09507119509548896.

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Zebardast, H. R., S. Rogak, and E. Asselin. "Electrochemical detection of corrosion product fouling in high temperature and high pressure solution." Electrochimica Acta 100 (June 2013): 101–9. http://dx.doi.org/10.1016/j.electacta.2013.03.108.

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Zhang, Ye Qin, Li Chun Qi, and Yi Sheng Huang. "Anticorrosion Property of TC27 Titanium Alloys and Application Evaluation in Tubing." Materials Science Forum 1035 (June 22, 2021): 615–23. http://dx.doi.org/10.4028/www.scientific.net/msf.1035.615.

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In view of the combined effect of the load and the corrosive environment on the downhole tubing and the need for the selection of downhole tubing materials, the study on the pitting corrosion, crevice corrosion, erosion corrosion, high temperature and high pressure simulation of corrosion, galvanic corrosion, resistance to sulfide stress corrosion cracking SSC, resistance to hydrogen induced cracking, stress corrosion cracking test under simulated working conditions for TC27 titanium alloy was carried out. Furthermore, the corrosion performance was evaluated by the test results and evaluation standards such as GB/T 18590-2001, SY/T 7394-2017, GB/T 15748-2013. The results show that TC27 have excellent resistance to pitting corrosion, crevice corrosion and erosion corrosion under the corrosive environment of NaCl and H2S. The alloy also has excellent corrosion resistance and crack resistance under high-intensity environments such as high temperature and high pressure, and has good overall performance, which can effectively meet the needs of anti-corrosion performance of downhole tubing materials in different corrosive environments.

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Ziegler, Robert. "Technology Focus: High-Pressure/High-Temperature (March 2021)." Journal of Petroleum Technology 73, no. 03 (March 1, 2021): 55. http://dx.doi.org/10.2118/0321-0055-jpt.

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For the past several months, the rig count in North America has been slowly but steadily improving and some pockets of deepwater operations are finally showing some activity, especially in Central and South America and Africa, where interesting discoveries continue. Arctic operations also are picking up, though not in North America, where a new administration in the US is bringing some uncertainty to upstream operations. Looking at leasing activity in 2020, however, the operators on federal land seem to have built up a backlog, so the immediate consequences of recent executive action seem not to be significant, though they do set an important precedent. More significant seems to be the opposition to pipelines, which are the most-efficient and safest way to transport any form of bulk material, be it gas, liquid, or slurry. Even if the most-stretched targets of an energy transition become reality, the need for pipeline transport will remain, and even increase, if the gas transported is biogas and hydrogen, where much larger volumes must be transported for the same calorific value of natural gas. In my tenure as a reviewer for JPT, I had refrained from a materials-focused special simply because high-pressure/high-temperature (HP/HT) conferences and sessions seem to be dominated by them and I wanted to demonstrate a wider spectrum of the challenges of HP/HT operations. With the energy transition leading to the possibility of free hydrogen being introduced into the energy system outside of established chemical feedstock installations (which are all low-pressure), this is a good time to remind our industry (and the outside world) that vast experience exists in the oil and gas industry on the interaction of hydrogen and metal (at very high pressures), a challenge that is still not completely understood and that is still a large cause of pressure-vessel failures (e.g., in refineries). Also, if carbon dioxide is intended to be captured and contained in metal vessels, another set of metallurgical challenges emerges. This Technology Focus looks at two papers from Asia, where these challenges were discovered and mitigated, and one paper from Gulf of Mexico deepwater operations. Many learnings can be taken from these papers, and extremely costly and safety-critical failures and loss of containment can be avoided. Addressing technical risk, thorough and detailed front-end engineering is a cost-effective and cost-saving activity, and this applies especially for front-end corrosion engineering and testing, as we have seen from several megaprojects in the past where this was not done to the extent finally understood to have been required. So, I invite you all to understand and embrace the fact that sound and competent engineering, as well as communicating learnings across functions and industries, is the key enabler for future success in our stressed industry, and to use our engineering brainpower and imagination to bring those HP/HT projects currently deemed too expensive to develop within the realm of the current oil-price environment.

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17

Touryan, L. A., and L. W. Hobbs. "In situ high-temperature corrosion with the environmental SEM." Proceedings, annual meeting, Electron Microscopy Society of America 51 (August 1, 1993): 788–89. http://dx.doi.org/10.1017/s0424820100149775.

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Electron microscopy has greatly aided in understanding the microstructure and morphological development of corrosion scales formed by high temperature oxidation and sulfidation of metals. However, this knowledge has been limited by the fact that the microstructure and morphological features could only be studied after corrosion had occurred. The recent development of the environmental scanning electron microscope (ESEM) permits actual in-situ observation of the evolution of high temperature corrosion scales at the scale-gas interface, allowing for a better understanding of the detailed mechanisms of scale growth. The objective of this study is to investigate the evolution of oxidation and sulfidation scales on various metals and alloys.R.A. Rapp and associates adapted a conventional SEM for oxidation studies by developing a stage that could be heated in excess of 1000 C. Because of the vacuum restrictions of the SEM, a gas pipe directed at the surface of the samples was utilized in order to increase the local oxygen partial pressure, and this resulted in low (0.2 Torr) but sufficient pressures for oxidation.

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Fan, Zhou, Jing Wen Fu, Xiao Ying Yang, and Xiao Gang Hu. "Experimental Study on Corrosion Resistance of GFRP in High Temperature and High Pressure Acid Environment." Materials Science Forum 847 (March 2016): 466–71. http://dx.doi.org/10.4028/www.scientific.net/msf.847.466.

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In this paper, the corrosion tests of glass fiber reinforced polymer (GFRP) in high temperature and high pressure acid environment were carried out. The surface morphology and glass transition temperature were observed by means of scanning electron microscopy (SEM), differential scanning calorimetry (DSC), and the mechanical property of GFRP was tested. The results indicated that after being exposed to acid corrosion environment, the structure and organization of GFRP changed, and a variety of defects produced on the surface and interior of GFRP, bending strength and tensile strength of GFRP decreased. The surface analysis also proved that there were some etch pits occurred on the GFRP pipes. Furthermore, their barcol hardness became poor.

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Meadowcroft, D. B. "High temperature corrosion in gases with low oxygen partial pressure." Materials and Corrosion/Werkstoffe und Korrosion 38, no. 9 (September 1987): 516–20. http://dx.doi.org/10.1002/maco.19870380909.

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Chen, Guang Hui. "Effect of High-Pressure Solution Temperature on Corrosion Resistance of AM60 Magnesium Alloy." Advanced Materials Research 580 (October 2012): 560–63. http://dx.doi.org/10.4028/www.scientific.net/amr.580.560.

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As-cast AM60 magnesium alloy was solid dissolved under a high-pressure of 4 Gpa at different temperatures. The microstructure of the products was observed by optical microscope and the corrosion resistance of the products was investigated. The results show that increasing temperature during solution treatment promotes the dissolution into α-Mg matrix of β-Mg17Al12 in the alloy and improves the corrosion resistance of AM60 alloy, especially for over 400 °C.

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Wang, Bin, Dong Mei Zhou, and Jiang Hu Bai. "Corrosion Behavior of TP95S Anti-Sulfur Casing Steel in High Temperature High Pressure H₂S/CO₂ Environment." Advanced Materials Research 335-336 (September 2011): 506–10. http://dx.doi.org/10.4028/www.scientific.net/amr.335-336.506.

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The anti-corrosion performance of Tiangang TP95S casing steel was studied by high temperature autoclaves simulating the high-temperature and high-pressure H2S/CO2 environment. The experimental results show that the corrosion rates increase with the rising of temperature which is from 40°C to 80°C under the dynamic and static conditions of the simulated environments; the dynamic corrosion rates are between 1.7294 and 1.8601mm/a and the corrosion rates are 0.4264～1.2715mm/a under the static conditions, both of which belong to a serious corrosion category; the dynamic corrosion samples have had the localized corrosion at 40°C, but the local corrosion of the static corrosion specimens appeared at 80°C; the corrosion product of TP95S steel takes FeS as the core in the case of static corrosion at 40°C.

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Fang, Xiao Jun, Li Liu, Zhi Gang Yang, and Yong Qiang Zhang. "Corrosion Behavior of P110S Oil Pipe in Simulated Working Condition." Materials Science Forum 944 (January 2019): 815–20. http://dx.doi.org/10.4028/www.scientific.net/msf.944.815.

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The corrosion resistance of P110S steel in CO2 and H2S coexistence corrosion environment under different temperature and PCO2/PH2S was investigated by high temperature and high pressure (HTHP) reaction kettle combined with SEM, EDS and XRD analysis methods. The stress corrosion cracking (SCC) resistance of P110S steel was studied under loading pressure of 682.2MPa (758MPa×90%) in simulated conditions after 720 hours test. The results show that the P110S steel has serious corrosion in the range of simulative temperature and H2S partial pressure. With the increase of temperature, the corrosion rate decreases first and then increases. With the increase of H2S partial pressure, the corrosion rate increases first and then decreases. The P110S steel has the highest corrosion rate when the temperature is 50 °C and H2S partial pressure is 0.1%. After the anti-SCC test, the specimens did not fracture, and cracks perpendicular to the tensile stress were not found on the surface. That is, P110S has good SCC resistance in the corrosive environment.

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Ijiri, Masataka, Daichi Shimonishi, Syunpei Tani, Norihiro Okada, Masato Yamamoto, Daisuke Nakagawa, Kumiko Tanaka, and Toshihiko Yoshimura. "Improvement of corrosion resistance of magnesium alloy by high-temperature high-pressure cavitation treatment." International Journal of Lightweight Materials and Manufacture 2, no. 3 (September 2019): 255–60. http://dx.doi.org/10.1016/j.ijlmm.2019.02.001.

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Gorbaty, Yu E., and G. V. Bondarenko. "High‐pressure high‐temperature Raman cell for corrosive liquids." Review of Scientific Instruments 66, no. 8 (August 1995): 4347–49. http://dx.doi.org/10.1063/1.1145326.

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Grzesik, Z., and S. Mrowec. "High Temperature Corrosion of Metallic Materials in Composed Oxidizing Environments." High Temperature Materials and Processes 31, no. 4-5 (October 30, 2012): 539–51. http://dx.doi.org/10.1515/htmp-2012-0091.

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AbstractBasing on actual theoretical approach and experimental results, the mechanism of sulphide formation beneath the oxide scale grown on metals in SO2-O2 atmospheres has been described. It has been shown that in spite of much lower sulphur partial pressure in the oxidizing atmosphere than the dissociation pressure of the sulphide to be formed, the sulphidation process takes place beneath the oxide scale. This, at the first sight, unexpected behavior results from the fact that sulphur is diffusing inwards through the primary oxide scale in the molecular form, i.e. SO2 molecules. Reaching thus metal-scale interface, where the oxygen partial pressure is very low, virtually equal to the dissociation pressure of the oxide forming the scale, SO2 ⇔ O2 + ½S2 equilibrium is shifted to the right, as a result of which the partial pressure of sulphur vapor dramatically increases, reaching the value several orders of magnitude higher than that needed for sulphide formation.Analogous situation is observed during oxidation of chromium steels in CO2-O2 atmospheres. In this case, namely, carburisation process is observed beneath the oxide scale, in spite of the fact that carbon activity in this environment is several order of magnitude lower than that required for chromium carbide formation. This again unexpected situation becomes understandable if one assumes – like in the case of metal oxidation in SO2 containing atmosphere – that carbon is transported through the oxide scale in the form of CO2 molecules.The final conclusion is, that the explanation of the mechanism of sulphide formation beneath the oxide scale on metals and of carburization beneath the oxide scales on steels constitutes the important step forward, leading to the better understanding of high temperature corrosion mechanisms of metallic materials, observed in multicomponent agresive gases.

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Park, Seonghwan, Cheolmin Ahn, and Eunkyung Lee. "Evaluation of Corrosion Behavior on Crept AlSi10MnMg (AA365) Alloy Produced by High-Pressure Die-Casting (HPDC)." Applied Sciences 11, no. 13 (July 5, 2021): 6227. http://dx.doi.org/10.3390/app11136227.

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High-pressure die-cast AlSi10MnMg (AA365) alloys have been used as a material for automotive components exposed to high temperature and corrosive environments. This work determines the correlation of corrosion resistance with the intermetallic compounds and micro-voids of crept AA365 alloys under temperatures ranging from 373 K to 573 K with various applied stresses. The results showed that crept AA365 alloy at 473 K possessed a large amount of the intermetallic phases, compared with crept AA365 alloys at 373 K and 573 K due to the non-equilibrium solute atoms in Al matrix. By contrast, crept AA365 alloy at 573 K contained the lowest number of intermetallic precipitates owing to the remelting of the phases. With regard to the corrosion behavior, the corrosion potentials showed −687.0, −684.0, and −673.0 mVSCE of crept AA365 alloys at 373 K, 473 K, and 573 K, respectively, which means the corrosion occurred slowly on the crept AA365 alloy at 573 K, rather than at 373 K, 473 K. The value of the corrosion current density (Icorr) in the crept HPDC AA365 alloy at 473 K has the highest corrosion current density of 13.3 × 10−6 Acm−2, compared with others. It can be inferred that the high amount of intermetallic compounds gave rise to severe corrosion and led to the harmful micro-galvanic corrosion of crept AA365 alloy, rather than the micro-voids.

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Dou, Yihua, Zhen Li, Jiarui Cheng, and Yafei Zhang. "Experimental Study on Corrosion Performance of Oil Tubing Steel in HPHT Flowing Media Containing O2 and CO2." Materials 13, no. 22 (November 18, 2020): 5214. http://dx.doi.org/10.3390/ma13225214.

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The high pressure and high temperature (HPHT) flow solution containing various gases and Cl− ions is one of the corrosive environments in the use of oilfield tubing and casing. The changing external environment and complex reaction processes are the main factors restricting research into this type of corrosion. To study the corrosion mechanism in the coexistence of O2 and CO2 in a flowing medium, a HPHT flow experiment was used to simulate the corrosion process of N80 steel in a complex downhole environment. After the test, the material corrosion rate, surface morphology, micromorphology, and corrosion product composition were tested. Results showed that corrosion of tubing material in a coexisting environment was significantly affected by temperature and gas concentration. The addition of O2 changes the structure of the original CO2 corrosion product and the corrosion process, thereby affecting the corrosion law, especially at high temperatures. Meanwhile, the flowing boundary layer and temperature changed the gas concentration near the wall, which changed the corrosion priority and intermediate products on the metal surface. These high temperature corrosion conclusions can provide references for the anticorrosion construction work of downhole pipe strings.

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Jiang, Peng, and Cheng Ye. "Recession of Environmental Barrier Coatings under High-Temperature Water Vapour Conditions: A Theoretical Model." Materials 13, no. 20 (October 10, 2020): 4494. http://dx.doi.org/10.3390/ma13204494.

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Rare-earth disilicates are the major material used on the top layer of environmental barrier coating (EBC) systems. Although rare-earth disilicates are highly resistant to water vapour, corrosion due to water vapour at high temperature is still one of the main reasons of failure of EBC systems. In this study, a corrosion model of ytterbium disilicates in water vapour at high temperature was derived, based on the gas diffusion theory. Using this theoretical model, we studied the evolution rule of the corroded area on the top layer of the EBC under gas flow at high temperature. The influence of the various parameters of the external gas on the corrosion process and the corrosion kinetics curve were also discussed. The theoretical model shows that the increase in gas temperature, gas flow velocity, water partial pressure, and total gas pressure accelerate coating corrosion. Among these factors, the influence of total gas pressure on the corrosion process is relatively weak, and the effect of the continuous increase of the gas velocity on the corrosion process is limited. The shape of the corrosion kinetics curve is either a straight or parabolic, and it was determined by a combination of external gas parameters.

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Shi, Qing Hao, Bing Ying Wang, and Bin Zhao. "Effect of CO₂ on Anti-Corrosion Property of a Polyurea Coating Modified with Organosilicone." Materials Science Forum 789 (April 2014): 466–70. http://dx.doi.org/10.4028/www.scientific.net/msf.789.466.

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The corrosion mechanism of organic silicon modified polyurea composite coating under different CO2 partial pressures was studied using high-temperature autoclave, combined with scanning electron microscopy (SEM), adhesion tests and electrochemical impedance spectroscopy (EIS) technology. The experimental results showed that: there was no corrosion product formed on the surface of coating sample after high-temperature high-pressure corrosion test, and with the increasing of CO2 partial pressure, the coating adhesion and impedance values decline increases. Moreover CO2 partial pressure increases accelerated the failure process of polyurea composite coating system.

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Lee, Sang Ll, Moon Hee Lee, Jin Kyung Lee, Joon Hyun Lee, and Yu Sik Kong. "High Temperature Corrosion Behaviors of Carbon Steels by A Pressurized Water." Advanced Materials Research 26-28 (October 2007): 1063–66. http://dx.doi.org/10.4028/www.scientific.net/amr.26-28.1063.

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The long-term corrosion resistances for the carbon steels have been investigated under high temperature pressurized water atmosphere, in the conjunction with the analysis of nondestructive properties by the ultrasonic wave. The corrosion test for carbon steels was carried out at the temperature of 200 °C under a water pressure of 10 MPa. The corrosion test cycles for carbon steels were changed up to 65 weeks. The mechanical properties of carbon steel suffered from the corrosion cycle were investigated by a tensile test, attaching an acoustic emission sensor on the test sample. The tensile strength of carbon steels greatly decreased beyond the corrosion cycle of 35 weeks, accompanying the increase of weight loss by the creation of corrosion damages. The attenuation coefficient of carbon steels by the ultrasonic wave increased with the increase of corrosion cycles.

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Cui, Chengchao, Shuzhong Wang, Jianqiao Yang, Baoquan Zhang, Zhuohang Jiang, Dong Wang, and Jianna Li. "Effects of temperature on oxidation behaviours of 35CrMo in high temperature flue gas environment." E3S Web of Conferences 83 (2019): 01006. http://dx.doi.org/10.1051/e3sconf/20198301006.

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The pipelines made by alloy 35CrMo are widely used in the process of flue gas injection. Therefore, corrosion behaviours of alloy 35CrMo have been investigated at varied temperatures, namely 120 °C, 150 °C, 200 °C and 250 °C, with same experimental pressure of 9 MPa and flus gas environment. Scanning electron microscopy was employed to examine the morphologies and microstructures of the oxide films. The results indicated that moderate temperature stands an essential role in the reaction mechanism and aggressive effects. In addition to increase in the diffusion rate of both alloy ions and corrosive gas, temperature can also reform the morphology of oxides by resulting in larger oxide particles and thicker oxide films, plus the transmission from needle-like oxides to spherical oxides.

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Xu, Na, Jun Bo Shi, Yong De Li, Wei Min Guo, Xiao Feng Wu, Shu Xin Han, Qi Shan Zang, and Zhi Wen Hu. "Failure Analysis of Water-Wall Tubes in the High-Pressure Boiler." Advanced Materials Research 912-914 (April 2014): 456–59. http://dx.doi.org/10.4028/www.scientific.net/amr.912-914.456.

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In this case study, the corrosion failure analysis of high-pressure boiler water-wall tubes in a power plant was investigated by means of the chemical analysis, metallographic examination and scanning electron microscope (SEM) observation. Energy dispersive spectroscopy (EDS) was used to examine the changes of test materials and corrosion products. Based on the failure process of the boiler water-wall tubes and the experimental results, a conclusion was drawn that the failure of water-wall tubes was mainly caused by pitting corrosion. Sulfide and chloride attack was the major cause of localized pitting corrosion on the inner surface, and the outer surface damage was mainly due to the synergism of high temperature sulfide corrosion and flue gas erosion.

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Gilewicz-Wolter, Jolanta. "High-temperature corrosion of iron in sulfur dioxide at low pressure." Oxidation of Metals 46, no. 1-2 (August 1996): 129–45. http://dx.doi.org/10.1007/bf01046887.

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Kim, Weon Ju, Seok Min Kang, and Ji Yeon Park. "Corrosion Behavior of Si₃N₄ Ceramics under High-Temperature and High-Pressure Water Condition." Advanced Materials Research 26-28 (October 2007): 259–62. http://dx.doi.org/10.4028/www.scientific.net/amr.26-28.259.

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Silicon nitride (Si3N4) ceramics have been considered for various components of nuclear power plants such as mechanical seal of reactor coolant pump (RCP), guide roller for control rod drive mechanism (CRDM), and seal support, etc. Corrosion behavior of Si3N4 ceramics in high-temperature and high-pressure water must be elucidated before they can be considered for components of nuclear power plants. In this study, the corrosion behaviors of Si3N4 ceramics at hydrothermal condition (300°C, 9.0 MPa) were investigated in pure water. The grain-boundary phase was preferentially corroded and the corrosion reaction was controlled by the diffusion of the reactive species and/or products through the corroded layer. Results of this study imply that the variation of sintering aids and/or the control (e.g., crystallization) of the grain-boundary phase are necessary to increase the corrosion resistance of Si3N4 ceramics in high-temperature water.

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HAN, En-Hou, Jianqiu WANG, Xinqiang WU, and Wei KE. "CORROSION MECHANISMS OF STAINLESS STEEL AND NICKEL BASE ALLOYS IN HIGH TEMPERATURE HIGH PRESSURE WATER." ACTA METALLURGICA SINICA 46, no. 11 (January 5, 2011): 1379–90. http://dx.doi.org/10.3724/sp.j.1037.2010.01379.

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SAKAKIBARA, Mizuo, Toshiaki SAITO, Hideaki ITOH, Yasusuke INOUE, and Yasuo OTOGURO. "Corrosion Behavior of Austenitic Heat Resisting Steels in High Temperature and High Pressure Steam Environment." Tetsu-to-Hagane 74, no. 5 (1988): 879–86. http://dx.doi.org/10.2355/tetsutohagane1955.74.5_879.

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Tachibana, Shinya, Akihiro Yabuki, Masanobu Matsumura, and Kazuo Marugame. "Corrosion of Carbon Steel in Flowing Pure Water under High Temperature and High Pressure Conditions." Zairyo-to-Kankyo 49, no. 7 (2000): 431–36. http://dx.doi.org/10.3323/jcorr1991.49.431.

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NISHIKAWA, Akinobu, and Hidemasa NONAKA. "A Corrosion Protection Method for Preventing Corrosion Due to Inner-Jumping Current in High-Temperature, High-Pressure Water Pipelines." Journal of the Society of Materials Science, Japan 51, no. 11 (2002): 1210–17. http://dx.doi.org/10.2472/jsms.51.1210.

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Götzlaff, W., G. Schönherr, and H. Uchtmann. "High pressure, high temperature reaction vessel for extremely corrosive media." High Pressure Research 5, no. 1-6 (April 1990): 903–5. http://dx.doi.org/10.1080/08957959008246294.

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40

Jia, Hu, Yao–Xi Hu, Shan–Jie Zhao, and Jin–Zhou Zhao. "The Feasibility for Potassium-Based Phosphate Brines To Serve as High-Density Solid-Free Well-Completion Fluids in High-Temperature/High-Pressure Formations." SPE Journal 24, no. 05 (November 8, 2018): 2033–46. http://dx.doi.org/10.2118/194008-pa.

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Summary Many oil and gas resources in deep–sea environments worldwide are often located in high–temperature/high–pressure (HT/HP) and low–permeability reservoirs. The reservoir–pressure coefficient usually exceeds 1.6, with formation temperature greater than 180°C. Challenges are faced for well drilling and completion in these HT/HP reservoirs. A solid–free well–completion fluid with safety density greater than 1.8 g/cm3 and excellent thermal endurance is strongly needed in the industry. Because of high cost and/or corrosion and toxicity problems, the application of available solid–free well–completion fluids such as cesium formate brines, bromine brines, and zinc brines is limited in some cases. In this paper, novel potassium–based phosphate well–completion fluids were developed. Results show that the fluid can reach the maximum density of 1.815 g/cm3 at room temperature, which makes a breakthrough on the density limit of normal potassium–based phosphate brine. The corrosion rate of N80 steel after the interaction with the target phosphate brine at a high temperature of 180°C is approximately 0.1853 mm/a, and the regained–permeability recovery of the treated sand core can reach up to 86.51%. Scanning–electron–microscope (SEM) pictures also support the corrosion–evaluation results. The phosphate brine shows favorable compatibility with the formation water. The biological toxicity–determination result reveals that it is only slightly toxic and is environmentally acceptable. In addition, phosphate brine is highly effective in inhibiting the performance of clay minerals. The cost of phosphate brine is approximately 44 to 66% less than that of conventional cesium formate, bromine brine, and zinc brine. This study suggests that the phosphate brine can serve as an alternative high–density solid–free well–completion fluid during well drilling and completion in HT/HP reservoirs.

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Wang, Bin, Jun Ling Zhang, Jiang Hu Bai, Dong Mei Zhou, Li Yang, and Kun Shen. "Corrosion Behavior of BG80S Anti-Sulfur Oil Tube Steel in High Temperature High Pressure H₂S/CO₂Environment." Applied Mechanics and Materials 151 (January 2012): 23–27. http://dx.doi.org/10.4028/www.scientific.net/amm.151.23.

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The four-point bending method and weight loss method were used to study respectively the stress corrosion cracking behavior and weightlessness corrosion situation of the baosteel BG80S steel in the simulated field environments. The experimental results shown that BG80S won't occur to stress corrosion cracking when the maximum loading stress is 85% Rt0.5 ; the corrosion rates increase with the rising of temperature which is from 40°C to 80°C under the dynamic and static conditions of the simulated environments; the dynamic corrosion rates are between 1.5558 and 1.7523mm/a and the corrosion rates are 0.4827～1.4078mm/a under the static conditions, both of which belong to a serious corrosion category; the form of corrosion is uniform corrosion under the dynamic conditions; because the corrosion products exist micro defects under the static conditions of 80°C, the experimental samples have had the localized corrosion.

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42

Roy, Tapan. "High-Temperature Oxidation of 310 Stainless Steel." Proceedings, annual meeting, Electron Microscopy Society of America 43 (August 1985): 272–73. http://dx.doi.org/10.1017/s0424820100118278.

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Austenitic stainless steels find application in heat exchangers, furnace parts, exhaust systems and other such high temperature applications because of their good corrosion resistance at elevated temperatures. This is believed to be because of a passive film of α-Cr2O3 that forms on the surface. Silicon is usually added to afford better scaling resistance. The steel under investigation (AISI # 31000) has minor alloying additions of manganese, silicon and titanium in addition to chromium(25 wt%) and nickel(20 wt%).Annealed and polished 3 mm discs as well as bulk specimens were oxidized at temperatures between 700°C and 900°C in dry oxygen at low pressure. Kinetic studies were performed using a CAHN 1000 microbalance. The 3 mm discs were back-thinned for TEM studies while the bulk specimens were used for SEM observations.

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Zhi, Zhang, Xiao Yu Zhou, De Zhi Zeng, Ji Yin Zhang, and Tai He Shi. "Evaluation on Chloride Cracking of S135 High-Strength Drill Pipe." Advanced Materials Research 430-432 (January 2012): 636–39. http://dx.doi.org/10.4028/www.scientific.net/amr.430-432.636.

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During the process of deep drilling with high temperature and high pressure, downhole drilling tools might be exposed to various corrosive mediums, such as water/oil-based drilling fluid systems, dissolved oxygen, H2S/CO2, halogen elements (Cl- and Br-), etc. Halogen elements existing in the drilling fluid are ions promoting corrosion of metals. This effect is mainly manifested in the forms of uniform corrosion, pitting corrosion, stress corrosion cracking, etc. of carbon steel. Quality of the drill pipe is determined by the DP body, joint and welding area of the drill pipe. Reasonable friction welding process and proper post weld heat treatment can make the mechanical property of weld joint satisfy related standards. If process of friction welding or post weld heat treatment is improper, the weld joint will be easily damaged and accidents of pricking, breaking, etc will be likely aroused. This paper carries out an evaluation experiment of chloride cracking on the DP body, joints and weld joints of the high-strength drill pipe (S135) and discusses corrosion of the high-strength drill pipe caused by chloride ions.

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Zheng, Shu Qi, Chang Feng Chen, and Li Qiang Chen. "Corrosion Characteristics of 2205 Duplex Stainless Steel in High Temperature and High Pressure Environment Containing H₂S/CO₂." Applied Mechanics and Materials 236-237 (November 2012): 95–98. http://dx.doi.org/10.4028/www.scientific.net/amm.236-237.95.

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The corrosion characteristics of 2205 duplex stainless steel in high- temperature and high-pressure (HT and HP) environments containing H2S/CO2 are investigated in this paper. After corroded 720 hours in the condition of 3.5 MPa H2S, 3.5 MPa CO2, 205°C, 15% NaCl and a sulfide content of 3g/L, one layer of comparably thick corrosion product are formed on the surface of the specimens. The corrosion products, which are relatively porous, lose its protection to the matrix. Lots of pitting are found on the surface of the steel and intercrystalline fracture and transcrystalline fracture are generated in the bottom of the pitting, which indicates its high sensitivity to stress corrosion crack (SSC). Also, the phenomenon of selective corrosion, a priority corrosion of α phase and minor corrosion or non-corrosion of γ phase, is observed after the corrosion process.

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BOCHAROV, Nikolay M. "HIGH TEMPERATURE CORROSION OF THIN SHEET STEEL 08KP IN AIR." Urban construction and architecture 11, no. 2 (December 15, 2021): 48–55. http://dx.doi.org/10.17673/vestnik.2021.02.08.

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The study of the nature of high-temperature corrosion of metals is one of the tasks in substantiating the relevance of the use of corrosion-resistant, heat-resistant coatings and barrier layers obtained on the basis of the natural oxidation process. The article presents the gradation of oxidation of surfaces of 08kp thin-sheet steel at diff erent temperature-time parameters of one cycle “heating-cooling”. To regulate the processing modes and register thermal eff ects, a diff erential thermal analysis device was used. It is shown that the eff ect of elevated temperatures on steel in air at atmospheric pressure triggers an intensive growth of scale, which peels off from the metal base and breaks down. After descaling on the steel surface, in addition to blue tarnishing, in some cases, fi lms of a red tint were found. Based on the data of diff erential thermal analysis, an att empt was made to separate and interpret transformations related directly to steel and to reactions in scale associated with iron oxides.

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Zhao, Jin Sheng, Ying Jun Ju, Mei Rong Tang, and Rong Huan Chen. "Experimental Study on the Corrosion Behavior of Produced Fluid on J55 Steel during CO₂ Flooding." Key Engineering Materials 773 (July 2018): 179–83. http://dx.doi.org/10.4028/www.scientific.net/kem.773.179.

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CO2 flooding has been widely used in oil field development, but the produced fluid is easy to cause corrosion of tubing and casing. In order to determine the corrosion behavior of produced fluid on J55 steel during CO2 flooding, we use the simulated oil well produced fluid as corrosive medium and conduct the corrosion simulation experiment at high temperature and high pressure. The experimental results showed that the crystalline grain size of corrosion film surface is different for the different CO2 partial pressure. When CO2 partial pressure is greater than the critical pressure, the crystalline grain is not oblique six-party crystal structure, and the grains become small and compact, so the corrosion product film should have a good corrosion inhibition. Both static and dynamic corrosion of samples are serious. The research has a theoretical guiding significance on corrosion protection during CO2 flooding.

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SIRAKAWA, Ryuji, Yoshihisa HARADA, Takayuki SUZUKI, Kazumi HIRANO, and Tokuo TERAMOTO. "2730 Water Vapor Corrosion of Melt Growth Composites under Ultra-High Temperature and High Pressure Enviornments." Proceedings of the JSME annual meeting 2006.1 (2006): 189–90. http://dx.doi.org/10.1299/jsmemecjo.2006.1.0_189.

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Yabuki, Akihiro, Hiroyasu Momikura, Masanobu Matsumura, and Kazuo Marugame. "Corrosion of Low Alloyed Steel in Flowing Pure Water under High Temperature and High Pressure Conditions." Zairyo-to-Kankyo 52, no. 1 (2003): 53–57. http://dx.doi.org/10.3323/jcorr1991.52.53.

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Zhang, Zhi, Yushan Zheng, Jing Li, Wanying Liu, Mingqiu Liu, Wenxiang Gao, and Taihe Shi. "Stress corrosion crack evaluation of super 13Cr tubing in high-temperature and high-pressure gas wells." Engineering Failure Analysis 95 (January 2019): 263–72. http://dx.doi.org/10.1016/j.engfailanal.2018.09.030.

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Shen, Yuanyuan, Yaohua Dong, Hengding Li, Qinghong Li, Li Zhang, Lihua Dong, and Yansheng Yin. "Corrosion Resistance of Cu-Ni-Si Alloy Under High-Temperature, High-Pressure H2S and Cl− Environments." Journal of Materials Engineering and Performance 28, no. 2 (January 4, 2019): 1040–48. http://dx.doi.org/10.1007/s11665-018-3663-5.

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Journal articles on the topic 'High Pressure High Temperature Corrosion'

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