A low-cost electro-gen solvent for carbon dioxide sequestration

An innovative concept for one of the lowest-cost carbon dioxide capture methods from power plants and other carbon-dioxide-emitting facilities is provided here. The concept is to use a novel electro-thermo-chemical regeneration approach which will generate a product solution containing hydroxyl ions for absorbing the flue gas CO₂. This may work with existing flue gas desulfurizing equipment to minimize the cost of carbon capture. The process involves the use of low-cost make-up reagents which are capable of providing credits for partial mineralization of CO₂, thus offsetting some of the costs for carbon capture and sequestration. The process presents the possibility of making this a low-cost on-site mineralization with cost offsets.     

Updated CO2/H2S internal corrosion model of natural gas pipelines based on flow field calculations

The ‘A line’ of the Sichuan Natural Gas East Transportation in China was used as the subject of the study, and an existing CO₂/H₂S corrosion model was utilised to predict the uniform corrosion rate. Then, the flow parameters were simulated by computational fluid dynamics based on turbulence theory, and the influence on the corrosion rate of the pipeline was analysed in a detail to more accurately describe the corrosion problems of natural gas pipelines that contain CO₂/H₂S. After that, an updated CO₂/H₂S corrosion model under the influence of flow filed was proposed by modifying the existing CO₂/H₂S corrosion model. The actual condition was calculated by the updated CO₂/H₂S corrosion model. Results show that flow parameters, namely, velocity, turbulent kinetic energy and phase distribution, affect pipeline corrosion. The flow parameters did not change significantly at the small scale changes in the pipeline (5 and 15°) of a broad and smooth flow channel of the large diameter gas transport pipeline. The shape of corrosion often appears in the form of an elliptical sheet. The corrosion location and the corrosion rate calculated by the updated model are consistent with the wall thickness detection data in the site conditions, which verified that the updated CO₂/H₂S corrosion model is valid. The updated CO₂/H₂S corrosion model influenced by the flow field can predict the corrosion distribution and the corrosion rate of the three-dimensional key positions in natural gas pipelines.     

Corrosion of structure materials and their weld joints in the environments of monoethanolamine gas cleaning in ammonia production

It is shown that the main cause of increased corrosion damage in equipment in units of monoethanolamine that remove CO₂ from converter gas exceed the regulation levels of formic acid, as chloride ions are acquired in the equipment during the neutralization of formic acid with caustic containing chlorides, as are distorting hydrodynamic flows in columns due to the corrosion of inner items, which results in the working environment effecting the structural elements. In order to lower the corrosivity of the working environment, it is recommended to control the content of formic acid by keeping it below 0.1 g/l, to neutralize it with caustic containing no chloride ions, and to eliminate the distortion of hydrodynamic flows in the apparatus, thus preventing the impact effects of the environment.     

Which are the right test conditions for the simulation of high temperature alkali corrosion in biomass combustion?

The use of renewable energy sources for the generation of electricity has gained much interest in recent years. Biomass has the potential of being a CO₂ neutral energy source that could provide a significant proportion of the ever‐increasing energy demand. The easiest and most straightforward utilization of the energy content of biomass is direct combustion. The thermal energy of the biomass released in the combustion process is utilized by heating water or steam to produce electricity or heat or both (CHP). Whereas the heat production requires only modest temperatures in the water or steam circuit, producing electricity with high efficiency is not possible without high steam parameters (temperature and pressure). The heat market being quite saturated, the economic potential is in the electricity market. High heat transfer surface temperatures coupled with biomass fired steam generators have resulted, however, in serious corrosion of the heat transfer surfaces, especially in the hottest section of the convection superheaters. The type of corrosion found in biomass boilers is not encountered in fossil fuel fired boilers and the mechanism causing it is not fully understood. The development of new alloys that could withstand these harsh environments would benefit tremendously if the test conditions in the laboratory tests could be chosen so that they adequately resemble the corrosion environment in real boilers. Currently the high corrosion rate is believed to be caused by gaseous KCl that condense on the heat transfer surfaces. While KCl is certainly found in the corroded superheater tubes and probably has an important role in the corrosion reactions with the alloy, the formation of KCl on the cooled surface can also be heterogeneous. In this paper a discussion on the effect of alkali hydroxides, especially KOH, is presented. Biomass fuels have normally a high content of alkali metals and a low content of sulfur and chloride. The excess alkali will produce alkali hydroxides in the combustion environment. Alkali hydroxides then react with CO₂ in the flue gases to form carbonates as the flue gases are cooled. The reaction with CO₂, is however, very temperature dependent. The equilibrium being completely on the K₂CO₃ side with a gas temperature below 700 °C and completely on KOH side with a gas temperature above 900 °C. The hottest superheaters are normally located in the area where the flue gas temperature is 850°C–1000 °C. This makes KOH condensation on the tubes possible and subsequent heterogeneous reactions with HCl, SO₂ and CO₂ in molten phase forming KCl, K₂SO₂ or K₂CO₃. Although KOH is not thermodynamically stable at typical tube surface temperatures, a continuous flux condensing from the flue gases results in a corrosion environment on the tube where its activity has to be taken into account. Therefore it is suggested that KOH, either in gaseous or molten phase should be included in the laboratory test environments used for the testing of alloys for biomass combustion applications.     

Study of corrosion behaviour of A106 carbon steel absorber for CO2 removal in amine promoted hot potassium carbonate solution (Benfield solution)

The CO₂ absorber is one of the largest pressure vessels in ammonia plants, which are suffering from severe corrosion problems worldwide. The aim of the present study is to examine the corrosion behaviour of A106 carbon steel absorber for CO₂ removal in amine promoted hot potassium carbonate solution (Benfield solution). This study simulates CO₂ removal unit in ammonia production process at Abu Qir Fertilizers and Chemical Industries Company (Alexandria, Egypt) and many other plants all over the world. A typical Benfield solution contains hot potassium carbonate K₂CO₃, potassium bicarbonate KHCO₃, diethanol amine (DEA) as a promoter and potassium metavanadate KVO₃ as corrosion inhibitor. The rate of galvanic corrosion of carbon steel absorber/stainless steel pall packings couple in Benfield solution was measured without adding the corrosion inhibitor KVO₃ in order to measure the influence of corrosive solution. The corrosion rate was measured by weight loss technique in relation to different operating parameters such as solution velocity, solution temperature, %K₂CO₃, CO₂ loading, %DEA and the effect of the presence of solution contaminants. In general, increasing solution velocity, solution temperature, %K₂CO₃, CO₂ loading and the presence of solution contaminations increase the corrosion rate. However, the increase in %DEA in solution decreases the corrosion rate. The strong dependence of corrosion rate on both solution and gas velocities indicates the diffusion controlled nature of the corrosion process. In addition, estimation of activation energy revealed a value of 4·8 kcal mol^?1. Surface morphology study depicted the presence of a porous solid film of corrosion products on carbon steel surface. It has been found that the liquid phase diffusion of bicarbonate to the steel solution interface is the rate determining step.     

Abgasseitige Korrosion bei Öl- und Gasfeuerung

Flue gas side corrosion in oil and gas fired heating systems Corrosion of metallic material of heaters of chimneys in contact with flue gas is guided by the amount and composition of condensate occurring on the surface when the temperature of the surface lies below the dew point of the flue gas. The corrosivity of the condensate depends on its content of sulfuric acid which results mainly from the sulfur content of the fuel. In some cases a special corrosivity against stainless steel may arise from a chloride-ion content of the condensate due to pollution of fuel or air by organic chlorine compounds. As a result of experiences with corrosion damages of heaters and chimneys a corrosion test methode for prefabricated stainless steel chimney elements was developed. Acceleration of corrosion is reached by simulation of only those phases in which condensation may occur and by addition of sulfur dioxide to the combustion air.     

Simulation of Fe-Cr-X Alloy Exposed to an Oxyfuel Combustion Atmosphere at 600 °C

In coal-fired power plants using oxyfuel combustion process with carbon capture and sequestration, instead of air, a mixture of oxygen and recirculated flue gas is injected in the boiler. A series of steels were exposed to CO₂-SO₂-Ar-H₂O gas mixtures at 600 °C for 1000 h to compare their high temperature corrosion behavior. During the corrosion process, carburization, decarburization and recrystallization were observed underneath the oxide scale depending on the gas mixture and alloy composition. The conditions that lead to carburization are not yet completely understood, but decarburization can be simulated using thermodynamic and kinetic models. In this work, the results of these simulations are compared with measured values for one of the alloys that displayed a decarburized region. Since the mobility of carbon in the scale is not known, two strategies were adopted: simulation of alloy-atmosphere contact; and estimation of the carbon flux to produce the observed decarburization. The second approach might give an insight on how permeable to carbon the scale is.     

天然气管道环焊缝缺陷部位的腐蚀沉淀机理

为了深入分析天然气管道的“梗阻”现象,采用金相法和能谱仪对靖边某气田典型的有大量沉积物管道进行了焊缝和沉积物结构及成分分析.结果表明,焊缝缺陷处的腐蚀和沉淀机理为管内发生CO₂腐蚀、缝隙腐蚀和H₂S腐蚀,产生了氧化物、氯化物和硫化物等腐蚀产物.随着腐蚀产物的逐渐堆积,其阻隔了管子材料与腐蚀性介质,使得腐蚀速率减慢,沉积物转为以粉尘为主.沉积物堆积到一定高度时,天然气的流向改变,管道顶部的腐蚀变为冲刷腐蚀,腐蚀速率加快,管道壁厚严重减薄,危害管道的正常安全运行.     

The effect of chemical species on the electrochemical reactions and corrosion product layer of carbon steel in CO2 aqueous environment: A review

This study summarizes the chemical effects that can occur during the corrosion process of carbon steel in a CO₂-saturated aqueous environment. Particularly, it focuses more on the results that small chemical contaminations in the environment have on the corrosion process. Underground waters present complex chemistry with several different dissolved ions (chlorides, carbonates) even in high concentrations that impact substantially the corrosion rates of these materials. Moreover, gas impurities present in the gas mixture, such as oxygen in carbon capture and storage applications, constitute a supplementary form of significant contamination in the CO₂-saturated aqueous environment. In particular, the effect on both electrochemical reactions and corrosion product layer is examined for several chemical species that are commonly present either in the gas mixture or in underground waters.     

High-temperature corrosion behaviors of typical nickel alloy coatings in a simulated boiler coal ash/gas environment in the Zhundong region

The high-temperature corrosion behaviors of five nickel alloy coatings used in coal-fired boilers in the Zhundong region (Xinjiang province) were investigated in simulated coal ash and coal-combusted flue gas environment at 650°C for 250 and 500 hr. The samples were analyzed by weight gain experiment, X-ray diffraction test, and scanning electron microscopy technique with energy-dispersive spectroscopy. The results indicated that the corrosion level is in the order of NiCrMo13 ≈ Hastelloy C-276 (276) > NiCrBSi > Inconel 718 (718) > 45CT. The compositions of the corrosion scale in five nickel alloy coatings mainly consist of NiO, Ni₃S₂, and Cr₂O₃. The enrichment of Cr in the corrosion scale in 45CT, 718, and NiCrBSi coatings inhibits the formation of oxide and sulfide on the coating surface. The presence of W and Mo in nickel alloy coatings accelerates the formation of corrosion products, thus weakening the corrosion resistance of NiCrMo13 and 276 in simulated coal ash and coal-combusted flue gas environment.     

Elektrochemische Aspekte der Erosionskorrosion in partikelhaltigen Strömungen

Electrochemical aspects of erosion corrosion in particle containing liquids Flowing, particle containing liquids induce various effects on metal surfaces according to their corrosivity. Electrochemical measurements demonstrate in which way the parameters of erosion corrosion are acting. As corrosion systems eight ferrous materials are chosen which are exposed to a solid containing quencher liquid of a flue gas desulphurization plant.     

The Effect of Temperature and Acid Gas Loading on Corrosion Behavior of API 5L X52 Carbon Steel in Amine Unit

The effect of temperature and H₂S concentration on amine corrosion of API 5L X52 carbon steel in a CO₂-saturated 25 wt.% diethanolamine solution was investigated via electrochemical techniques. It was found that increase in temperature from 25 to 80 °C resulted in severe increase in corrosion rate from 0.88 to 16.24 mpy due to increase in degradation rate of amine. Also, it was concluded that increase in H₂S concentration led to increase in corrosion rate because of formation of more heat stable amine salts. The effect of temperature on corrosion rate was more significant than acid gas loading.     

CO2对H2S／CO2环境中P110钢应力腐蚀的影响研究

采用恒载荷拉伸法、腐蚀电化学测试和断口分析技术等,研究了P110钢在不同H2S／CO2含量的NACE-A溶液中的硫化物应力腐蚀（SSCC）行为．结果表明,在加载初期,P110钢的自腐蚀电位Ecorr）急剧下降,至极小值后缓慢升高,达到稳定值后直至断裂,试样断口呈脆性解理状．当通入CO2量达到17％时,P110钢的自腐蚀...     

Condensed phase corrosion of P91 and DSS 2205 steels at advanced oxygen-fired pressurized fluidized bed combustion plants

To achieve the targets of high energy efficiency and reduced CO₂ emission, advanced oxygen-fired pressurized fluidized bed combustion technology is being developed. The generated flue gas condensates are very corrosive, but very limited information is available to select appropriate alloys for the cost-effective construction and long-term safe operation of flue gas components. Thus, this study investigated the corrosion performance of P91 and DSS 2205 steels in the simulated condensates at 60°C–150°C. The dominant reactions on the two steels were considerable oxide formation and high chemical dissolution of the formed oxides instead of localized pitting. The increase in temperature leads to an exponential increase in the long-term corrosion rates of the steels. Benefited from its high Cr and Mo contents, DSS 2205 steel exhibited much better corrosion resistance, and the formed surface scales consisted of inner Fe-enriched and outer Cr-enriched oxides in which Cr₂O₃ was transformed into Cr(OH)₃ with the increase in temperature. The corrosion products on P91 steel consisted of inner Cr–Fr–Mo oxides and outer Fe-enriched oxides, which were porous and unable to protect the steel.     

Influence of novel cycle concepts on the high‐temperature corrosion of power plants

The aim to reduce CO₂ emissions has triggered the evaluation of new cycle concepts for power plants. CO₂‐capture concepts are also evaluated to add on new and existing power plants. For combined cycle power plants (CCPP), different cycles are investigated such as integrated gasification (IGCC) or oxy‐fuel firing. Besides the difference in combustion compared to a conventional CCPP, the environmental boundary conditions are changed and will affect the oxidation and corrosion life of the materials in the hot‐gas path of the gas turbine and the heat‐recovery steam generator. For the circulating fluidised bed power plants, the biomass co‐firing and the oxy‐fuel firing are also foreseen for CO₂‐emission reduction. The fireside corrosion of the water walls will be influenced by these concepts and the changed fuel. The corrosion risk has been evaluated for two new power plant concepts: combined cycle with exhaust gas recirculation and pulverised coal‐fired boiler with oxy‐fuel firing. Based on this evaluation, the consequences for the testing conditions and the material selection have been discussed in detail.     

Current and future corrosion challenges for a reliable and sustainable development of the chemical,refinery, and petrochemical industries

The chemical, refinery, and petrochemical industries are facing new challenges in order to develop more environment friendly processes and to manufacture “green” products. Corrosion management is an essential element for the development of a sustainable industrial society, including issues such as the selection and development of corrosion resistant materials, coatings, and environment friendly inhibitors. In this paper, some specific challenges will be discussed. In the chemical industry, the replacement of volatile and toxic solvents by green ones such as supercritical water processes, ionic liquid, or the use of carbon dioxide as an alternative solvent, requires specific corrosion management policies. Another issue for the refinery industry concerns new feedstocks such as opportunity crudes containing corrosive naphthenic acids or the transformation of biomass feed into bio‐oils and biomaterials. Synthetic gas is also becoming a crucial intermediate in natural gas, coal or biomass to hydrocarbon liquids (XTL) processes. Other environmental aspects are the limitation of green house gas (GHG) release from the plants by implementation of CO₂ capture processes and the environment friendly management of water including more restrictive steps concerning its disposal. The implementation of advanced inspection and corrosion control management is also a major element of progress for a sustainable development of the chemical, refinery, and petrochemical industries.     

天然气管线钢CO2腐蚀研究进展

天然气管线面临日益严重的CO₂腐蚀问题。针对管线内特定的腐蚀环境,总结了当前CO₂腐蚀在反应机理、影响因素以及腐蚀控制方面的研究进展,最后展望CO₂腐蚀研究今后的发展方向。     

Impedanzspektrometrische Untersuchungen zur Wirkungsweise von Inhibitoren und Tensiden bei der CO2-Korrosion von Stahl unter Erdgasförderbedingungen

AC impedance investigations on the performance of inhibitors and surfactants in CO₂ corrosion of steel under natural gas production conditions Inhibition mechanisms of CO₂, corrosion of low alloy carbon steel (38 Mn 6) were studied under production conditions of sweet natural gas (1 M NaCl + 0.1 M CaCl₂; 1 and 5 bar CO₂; 80°C) in the presence of surface active compounds (inhibitors, surfactants) with AC impedance spectrometry. Based on a pore model an equivalent circuit was developed which explains the action mechanisms of the substances tested. Fatty amines and imidazolines inhibit the interface reaction at the bottom of pores in the corrosion product scale due to adsorption. Nonionic surfactants can impair the effectivity of N-containing inhibitors. 1-Octyne-3-ol acts through formation of polymer films and reduces the porosity of the scale. All substances under investigation influence the morphology of the scale and the kinetic of its formation.     

Carbon dioxide corrosion of oil and gas field equipment

Conditions for carbon dioxide corrosion in oil, gas, and gas-condensate fields are discussed. Corrosion mechanisms in oil, gas, and gas-condensate fields and gas and oil pipelines are compared. Various factors are shown to affect the CO₂ corrosion rate of steel in oil and gas field media.Translated from Zashchita Metallov, Vol. 41, No. 1, 2005, pp. 82–90.Original Russian Text Copyright © 2005 by Moiseeva.     

Prediction models for multiphase-flow-induced corrosion of API X80 steel in CO2/H2S environment

In the offshore oil and gas industry, mainly focusing on the use of rigid or flexible pipes of subsea infrastructure applied to risers or flowlines, one of the greatest difficulties is the interpretation of the combined effects of the various correlated phenomena (hydrodynamic effects of intermittent flow, the effects of corrosivity of the environment in addition to variations in pressure, temperature, and dynamic loading). On the basis of this scenario, defining the degree of severity of each of the correlated system variables becomes of fundamental importance for establishing reliable criteria for selecting materials for subsea application. The established flow pattern directly affects the corrosion rate (or the pipe material mass loss), but the balance of other variables including possible changes in the physical and transported fluid chemical properties may increase the damage up to an order of magnitude, which is a piece of information normally not foreseen in design criteria. Therefore, to improve the understanding of the corrosion study influenced by multiphase flow, a testing loop was designed and assembled at the Corrosion and Protection Laboratory of the Institute for Technological Research, in which API X80 steel coupons were positioned in locations with a 0° and 45° inclinations. Tests were conducted by varying the partial pressure of the gaseous phase containing blends of CO₂ and H₂S with N₂ balance, mixed with the liquid phase containing light oil and heavy oil in water with salinity (NaCl)-simulating oil well conditions with 80% water cut. The main objective of this study is to establish models that can predict the corrosion intensity in conditions close to those obtained experimentally. To achieve results, the multiple regression and Box–Cox transformation methods were applied. These models will make possible damage prediction and optimization of matrix parameters for the multiphase-loop test.