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CO2 capture and storage plays an important part in industrial strategies for the mitigation of greenhouse gas emissions. CO2 post-combustion capture with alkanolamines is well adapted for the treatment of large industrial point sources using combustion of fossil fuels for power generation, like coal or gas fired power plants, or the steel and cement industries. It is also one of the most mature technologies to date, since similar applications are already found in other types of industries like acid gas separation, although not at the same scale. Operation of alkanolamine units for CO2 capture in combustion fumes presents several challenges, among which corrosion control plays a great part. It is the aim of this paper to present a review of current knowledge on this specific aspect. In a first part, lessons learnt from several decades of use of alkanolamines for natural gas separation in the oil and gas industry are discussed. Then, the specificities of CO2 post-combustion capture are presented, and their consequences on corrosion risks are discussed. Corrosion mitigation strategies, and research and development efforts to find new and more efficient solvents are also highlighted. In a last part, concerns about CO2 transport and geological storage are discussed, with recommendations on CO2 quality and concentration of impurities.

Abstract: In H2S containing solutions, the reduction of protons with a buffer effect contributing to the transport of protons at the steel surface, is not sufficient to explain the cathodic polarization curves obtained on 316L stainless steel. An additional electrochemical reaction was observed and was attributed to a direct H2S reduction. A numerical model is presented with these hypotheses and a good agreement is found with the experimental data presented in a previous paper. With this model it is also possible to present the concentration profiles of the different species involved in the cathodic process. [Copyright &y& Elsevier]

Abstract: This paper compares the cathodic reactions occurring on steel in aqueous solution containing dissolved H2S or CO2. In aqueous solutions containing these weak acids, the rate of the cathodic reaction is enhanced in comparison with strong acid solutions at the same pH. In the case of dissolved CO2, this phenomenon is fully explained by a buffer effect, contributing to the transport of proton at the steel surface. In the case of H2S containing solutions, this chemical mechanism is no more sufficient to explain the cathodic polarization curves. An additional electrochemical reaction is clearly observed, with strong links with H2S concentration. [Copyright &y& Elsevier]

Abstract: Hydrogen charging in low alloy steels is a major problem in oil and gas environments containing hydrogen sulfide (H2S). The risk of sulfide stress cracking (SSC) is usually determined from the values of water pH and H2S partial pressure (P H2S). The goal of the present study is to check if hydrogen charging is influenced by other parameters than the sole pH and P H2S, and especially by carbon dioxide (CO2). Experiments engaged the measurement of hydrogen permeation through thin mild steel membranes under potentiometric control. Charging solutions with different H2S concentrations with or without CO2 were used, in order to examine their individual contributions to the charging flux. [Copyright &y& Elsevier]

Acoustic emission {AE) was used for monitoring steel cracking during exposure to wet hydrogen sulfide (H2S) environments. A method for filtering AE data related to hydrogen-induced cracking (HIC) was presented and applied for several case studies. In a series of tests on unstressed sweet service steels, evolution of AE indicated three successive HIC phases. An initial incubation period corresponded to hydrogen entry in the steel, during which no cracking occurred. Then two cracking phases were detected. The first was associated with decohesion of weak steel interphases. The second was identified as crack propagation under high internal hydrogen pressure. Crack propagation decreased and eventually ceased over time. Analysis of AE data was then used to evaluate the extent of HIC after sour exposure. Correlation was found when appropriate data filtering was applied. AE analysis was also applied to sour service steels under an applied load. The first steel exhibited HIC AE signals. Its fracture surface was typical of a stress-oriented hydrogen-induced cracking (SOHIC) mode of failure, in good agreement with AE results. For the second steel, which also failed during the test, no AE related to HIC was detected. Fracture surface was typical of sulfide stress cracking (SSC), also in good agreement with AE findings. [ABSTRACT FROM AUTHOR]

Abstract: Among the technologies that are under study for CO2 capture from flue gas, the separation process using monoethanolamine (MEA) could be the first to be available for immediate industrial applications in the next few years. The principles of CO2 separation using alkanolamines were discovered nearly a century ago. The process has been applied successfully for several decades in areas such as natural gas processing or coal gasification. The application to flue gas treatment was introduced in the early 1980s, but was not widespread. In such industrial processes, corrosion represents one of the major operational problems. For the capture of CO2 from flue gas using MEA, the problem is even more critical since (i) MEA is one of the most corrosive amine when compared to secondary or tertiary amines that are also used for gas sweetening, and (ii) flue gas contains a certain amount of oxygen, which can react with the amine to form corrosive degradation products. In the framework of the CAPRICE project, which is an International cooperation and exchange project supported by the EU, The International Test centre for CO2 Capture from the University of Regina (CA) and IFP (F) have shared their experience on corrosion monitoring from CO2 capture pilot plants. The first pilot plant facility is owned by ITC. It has a capacity to capture 1 ton CO2/day from a natural gas burner. It is equipped with corrosion control instruments and other monitoring systems. The second pilot plant is located in a coal fired power station in Esbjerg (DK). It was built with the financial support of the UE through the CASTOR project under the lead of IFP. It has been in operation since early 2006, and has a capacity of 1.0 ton CO2/hour. It is equipped with weight loss coupons for corrosion evaluation at different locations in the process. This paper presents the major results of corrosion testing from both pilot plants under MEA operation. It appeared from both pilot plants that the areas most susceptible to corrosion were the stripper inlet and outlet, with corrosion rates around 1 mm.year−1 for carbon steel. [Copyright &y& Elsevier]

The permeation of hydrogen in steel in the presence Of acid gases is not a simple phenomenon because the steel may contain trapping sites and the permeation may be governed by surface reactions associated with corrosion. Recently, hydrogen permeation experiments carried out at the corrosion potential have shown a constantfluxfor various membrane thicknesses in the range from 0.05 mm to 0.8 mm. These resuits revealed the difficulty to express the flux for thicker steel membrane (i.e., pipe) from laboratory studies on thin membranes, since the classical rule (flux proportional to the inverse of the membrane thickness) is not always applicable and not conservative. This paper presents new permeation results obtained on steel membranes up to 10 mm thick. The transition between thin and thick membranes is clearly established and is in the millimeter range in sour conditions. The necessity to adopt a new interpretative framework to link permeation measurements and hydrogen cracking mechanisms is reinforced. For thin membranes, the permeation flux is constant and governed only by the charging flux crossing the entry face. This surface mechanism is probably correlated with a surface cracking mode, like sulfide stress cracking (SSC). On the other hand, the traditional concept of diffusion can only be used in thick membrane situations. The diffusion flux is inversely proportional to the subsurface concentration. This concentration is in direct relation with the hydrogen activity in the steel, which is probably correlated with internal cracking modes, like hydrogen-induced cracking (HIC). [ABSTRACT FROM AUTHOR]

A kinetic model of the physicochemical processes occurring during the corrosion of steel covered by a thin water film exposed to a CO2 atmosphere is proposed. This model explains theoretically the unusual physicochemical behaviors generally observed in such confined corrosive media: Fe(II) supersaturations, low corrosion rates, high pH values, and their respective dependence on the electrolyte film thickness. More quantitatively, the model predictions agree well with pH and corrosion rate measurements performed in environments similar to the annulus space of flexible pipelines. [ABSTRACT FROM AUTHOR]

With the international drive to deploy green energies and decarbonized intermediates in the place of fossil fuel sources, a large number of developed countries are actively preparing for a future where hydrogen plays a strategic role as an energy storage medium. Producing and using hydrogen requires the rapid expansion of a dedicated, economically viable industrial sector. Nevertheless, questions on how to safely store, transport and distribute hydrogen remain an important priority today. In countries with existing natural gas transport grids, the possibility to retrofit these networks to store and transport hydrogen-natural gas blends is being studied. A key challenge is to evaluate how pressurized H 2 would interact with steel structures with regards structural embrittlement of the latter, with a view to exploiting existing transport infrastructures for storage and transport applications. In this work, we evaluate the H 2 -performance of a non-hydrogen service ×65 pipeline steel. The cracking susceptibility of this steel grade has been evaluated at 100 bar H 2 using slow strain rate testing, Constant strain testing and fracture toughness measurements. Accompanying hydrogen permeation tests under pressure provide diffusion data and elucidate the discussion. Exposures were carried out in dry or wet H 2 and with or without H 2 S contamination at levels representative of biogas. The results underline that the impact of dry or wet hydrogen on this grade are moderate. The presence of traces of H 2 S together with humidity could risk seriously degrading the mechanical performance of the ×65 steel grade. • The risk of hydrogen assisted cracking is low with ×65 up to 100 bar H 2 in the absence of gas contaminants. • The decrease in fracture toughness is minimal under dry H 2 even though some embrittlement is visible in the fractured surface. • The fracture toughness in gaseous H 2 significantly decreases in presence of humidity with traces of H 2 S. • The extent of hydrogen induced cracking, even in the in presence of humid H 2 S contamination, remains low. • The hydrogen ingress assessed through TDS measurement was extremely low. [ABSTRACT FROM AUTHOR]