Deposit Recoat Research Articles

Further investigations into alloy induced acidic fluxing

ABSTRACT Gas turbine materials often feature precipitates containing refractory metals to enhance their mechanical strength. This can make them susceptible to alloy-induced acidic fluxing whereby refractory elements increase the acidity of salt deposits. It is not clear to what degree degradation around alloy precipitates is caused by alloy-induced hot corrosion mechanisms, or the inability to develop a protective scale where precipitates are located. The effect of alloy-induced hot corrosion was isolated from the disruption of the protective-scale formation by adding particles of molybdenum to the 80/20 (Na/K)2SO4 deposit for a ‘deposit re-coat’ style hot corrosion test. The resulting morphologies were compared to samples exposed without the addition of molybdenum. Morphology changes were investigated using scanning electron microscopy with energy-dispersive X-ray mapping. Results show a mix of sulphidation and pitting. The effects of molybdenum additions appear more severe for MarM 509 compared to PWA 1483.

Fireside performance of different coatings in biomass power plant

ABSTRACT The energy sector will need to employ novel strategies to reduce greenhouse gas emissions, such as the increase of steam temperatures/pressures or the use of low carbon fuels (i.e. biomass). Both cause heat exchanger materials’ degradation issues, due to the formation of more/different corrosive deposits, which requires the use of expensive nickel-based materials or coatings. This paper focuses on the behaviour of three different coatings (HVOF NiCrFeSi, laser clad FeCrAl and Laser Clad NiCrFeSi) deposited on TP347HFG, at 700°C (up to 1000 h exposure). Tests were performed using the ‘deposit recoat’ method (KCl deposit) in simulated biomass combustion environments. Cross-sections were analysed using dimensional metrology, to determine distributions of metal loss and internal damage. Intergranular damage and pits were identified using SEM/EDX. A ‘diffusion cell’ behaviour was observed, which led to depletion of alloying elements from the coating and consequent increase in damage. The results suggested a severe degradation of all coatings.

A comparative evaluation of waste wood and herbaceous biomass fireside corrosion behaviours

Biomass/biomass waste (BBW) is a renewable energy source fired in combustion power plants. However, challenges associated include accelerated ‘fireside’ corrosion of heat exchangers. Fireside corrosion is fuel dependent, e.g. virgin wood fuels have lower fireside corrosion risks; as such their demand and cost is high. Waste wood fuels (WWF) and herbaceous grass biomass (HGB), generate different combustion environments, influencing heat exchanger fireside corrosion damage.This paper compares the fireside corrosion of WWF and HGB fuels to improve understanding of their attack mechanisms on T91 and 374HFG. The species generated in combustion have been investigated by thermodynamic modelling. Corrosion damage has been evaluated by high temperature corrosion furnace tests at 600 °C, employing the well-established deposit recoat method based on these evolved species. Vapour condensation fluxes have been compared for both fuel categories; corrosion rates increase with this condensation flux. Deposition fluxes from HGB fuels are higher than for WWF. For example, the average KCl deposition fluxes calculated are 1566 µg/cm2h and 295 µg/cm2h per kg fuel feed respectively, explaining the comparatively greater fireside corrosion rates experienced in power plants combusting HGB fuels. The deposit chemistries generated are also different: K-containing compounds only (for HGB fuels) versus K-, Na- and Ca-containing compounds (for WWF).Evaluation of corroded samples exposed to the different deposit chemistries show increased corrosion attack to both steels under simulated WWF firing conditions than for the HGB at matched deposit flux (100 µg/cm2h).

The effects of water vapour on the hot corrosion of gas turbine blade materials at 700 °C

ABSTRACT Future developments in power generation are likely to require gas turbines to operate in novel combustion environments. The level of water vapour in the turbine’s gas stream is one variable that may change as a consequence. This paper explores the effects of water vapour on hot corrosion. The ‘deposit recoat’ technique was used to evaluate the hot corrosion performance of superalloys PWA 1483 and MarM 509 in atmospheres containing between 0 and 20 vol.% water vapour. Exposures were carried out at 700 °C in atmospheres containing 300 ppm SO2 for up to 500 hours. The deposit was an 80% Na2SO4, 20% K2SO4 solution applied with a deposition flux of 1.5 µg/cm2/h. The findings are compared to similar exposures with 3.6 ppm SO2. Increasing levels of water vapour were observed to reduce sound metal loss in atmospheres containing 300 ppm SO2 while increasing sound metal loss in atmospheres containing 3.6 ppm SO2.

Comparing the hot corrosion of (100), (210) and (110) Ni-based superalloys exposed to the mixed salt of Na2SO4-NaCl at 750 °C: Experimental study and first-principles calculation

The effect of crystal orientation on the hot corrosion behaviors of Ni-based single-crystal (SC) superalloys exposed to mixtures of 90 wt% Na2SO4 + 10 wt% NaCl at 750 °C for 200 h were studied using the “deposit recoat” method. The results showed that the mass gains of the specimens with different orientations increased in the order of (210) < (100) < (110). The (210)-oriented specimen exhibited superior hot corrosion resistance, which resulted in the lowest mass gain. First-principles calculations indicated that the origin of the orientation-dependent hot corrosion resistance was the different diffusivities of active cations in differently oriented alloys.

Effects of Pt and Si on the low temperature hot corrosion of aluminide coatings exposed to Na2SO4-60 mol% V2O5 salt

Hot corrosion of pack (zero/medium) Pt-modified aluminide and slurry (zero/low/medium) Pt-modified silicon-aluminide coatings exposed to a Na2SO4-60 mol%V2O5 deposit at 700 °C was evaluated using the deposit recoat technique. Thickness loss metrology was utilized to study corrosion penetration into the coatings. The corrosion products and remaining coatings were characterized by means of SEM, EDX, XRD and EPMA. The aluminide coating and medium Pt-modified silicon-aluminide coating showed the worst and the best corrosion resistance, respectively. Enhanced hot corrosion resistance of the Pt-modified silicon-aluminide was attributed to microstructure of the coating with a two-phase PtAl2-NiAl outer layer and formation of refractory silicides.

Interaction of hot corrosion fatigue and load dwell periods on a nickel-base single crystal superalloy

The effects of type II hot corrosion on the fatigue resistance of turbine blade superalloys is of growing interest as gas turbine (GT) original equipment manufacturers (OEMs) strive to optimise the operational efficiencies and versatilities of GT systems. Hot corrosion fatigue has been observed in the under platform regions of first stage GT blades, this location is subject to both relatively high principal stresses and stress gradients, combined with temperatures up to those associated with type II hot corrosion (500–700 °C). The effect of the deposition flux of corrosive salt species and the tensile stress dwell period on the fatigue performance and resultant crack morphologies of single crystal (SC) superalloy CMSX-4 has been studied at 550 °C. Deposit recoat methodologies were applied to specimens that were cyclically fatigued with a load-controlled trapezoidal waveform. It was observed that introducing a longer dwell period increased the number of {1 0 0} crack initiations and reduced the fatigue life (load cycles to failure). Optical and SEM microscopy and EDX techniques were used to examine specimen fractography, and mechanisms of crack advance and propagation discussed.

Effect of Rhenium Addition on Hot Corrosion Resistance of Ni-Based Single Crystal Superalloys

Hot corrosion behavior of two Ni-based single crystal superalloys containing 0 Re and 2 wt pct Re in molten sodium sulfate (Na2SO4) at 900 °C in static air has been investigated using the “deposit recoat” method. It was shown that the incubation period of the Re-containing alloy was much longer than that of the Re-free alloy. It was because Re increased the stability of the chromium oxide (Cr2O3) scale, promoted the formation of nickel titanate (NiTiO3), and suppressed the diffusion of Ni. In addition, the overall corrosion kinetics of the Re-containing alloy followed a multistage parabolic law, compared with the Re-free alloy. This could be because Re increased the activity of chromium (Cr) and titanium (Ti), which resulted in the periodically opening and closure of the cracks in the outer oxide layer.

Impact of Deposit Recoat Cycle Length on Hot Corrosion of CMSX-4

Hot corrosion causes significant problems for both aerospace and power generation industries, where the combination of high temperature, corrosive gases, and contaminants severely limits component operating lifetimes in gas turbine hot gas streams. Multiple laboratory testing methodologies exist to study this hot corrosion, and these can be affected by a range of variables. This paper investigated the impact of varying deposit recoat cycle length when using the ‘deposit recoat’ testing method. CMSX-4 samples were exposed to simulated type II (pitting) hot corrosion conditions, with the same overall deposit load (averaged across the total exposure run), but different deposit recoat cycles. Post-exposure, samples underwent dimensional metrology analysis to compare metal loss resulting from different deposit recoat cycle lengths. Results for CMSX-4 suggest very small differences in corrosion losses, indicating CMSX-4 hot corrosion datasets obtained from deposit recoat experiments with different deposit recoat cycle lengths can be compared with confidence.

Interaction of Ta and Cr on Type-I hot corrosion resistance of single crystal Ni-base superalloys

Type-I hot corrosion behaviour of single crystal Ni-base superalloys with different Cr and Ta contents in sodium sulphate (Na2SO4) at 900°C and 950°C in static air were investigated using the “deposit recoat” method. It was shown that, increasing corrosion temperature shortened the incubation period. Loss of hot corrosion resistance causing by Cr reduction cannot be compensated by increasing Ta content. The effect of Ta addition on hot corrosion resistance can be described by introducing the quantitative parameter Ta/Cr (wt.%) ratio. Interaction of Cr, Ta and temperature on hot corrosion behaviour was discussed in detail in the present paper.

Role of tantalum in the hot corrosion of a Ni-base single crystal superalloy

Hot corrosion behaviour of a Ni-base single crystal superalloy with low Cr, Ti and high Ta contents in molten sodium sulphate (Na2SO4) at 900°C in static air was investigated using the “deposit recoat” method. The corrosion scale was composed of an outer NiO layer, an inner Al2O3-dominant oxide network layer and a (CrSx(1.000<x<1.500), TaS2) sulphide layer. Ta was found to exhibit a beneficial effect by promoting the formation of NaTaO3 and TaS2, and therefore inhibiting the formation of liquid phases Na2MoO4 and Ni-sulphides. The formation mechanism and effect of TaS2 were discussed in detail in the present paper.

Hot corrosion resistance of gas turbine materials in combusted syngas environments

To reduce CO2 emissions, there is interest in a new generation of industrial gas turbines operating in advanced integrated gasification combined cycles (IGCC) with the option for pre-combustion CO2 removal systems. These gas turbines may be fired on syngas, cleaned H2 rich syngas, or natural gas, and this will alter the hot corrosion experienced by components in the hot gas path. Deposit recoat laboratory tests have looked at the response of 11 state-of-the-art materials systems under the expected IGCC conditions. MTData has been used to calculate the optimal deposits under the temperature and gas conditions for these tests. Studies of metal loss have helped assess quantitatively the resistance of the different materials systems, while microscopy techniques have given information on the degradation mechanisms experienced. Rene 80 has been selected to demonstrate the data from these tests and shows the most significant metal loss under partially cleaned syngas conditions.

Fireside corrosion degradation of ferritic alloys at 600 °C in oxy-fired conditions

This paper reports the results of a study carried out to investigate the effects of simulated coal/biomass combustion conditions on the fireside corrosion. The 1000h deposit recoat exposure (5×200h cycles) was carried out at 600°C. In these tests ferritic alloys were used 15Mo3, T22, T23 and T91. Kinetics data were generated for the alloys exposed using both traditional weight change methods and metal loss measurements. The highest rate of corrosion based on EDX results occurred under D1 deposit where provoke mainly by the formation of alkali iron tri-sulphate phase.

Effect of biofuel‐derived contaminants on coated industrial gas turbines blade materials

Combined cycle power systems offer increased efficiency of electricity generation and lower environmental emissions of CO2, SOx and NO2, as well as being adaptable to most fossil/biofuels. Industrial gas turbines are at the heart of such power stations and are being developed to perform at higher firing temperatures and pressures to achieve even greater efficiencies, with lower emissions. Fuel gases derived from renewable fuels, such as biogases from digestors or syngases from solid fuel gasification, may contain contaminants that are extremely corrosive to the gas turbine components (e.g. blades and vanes) located in the hot combusted gas path. Such damage can result in a gradual loss of turbine efficiency and reliability. Therefore, it is of paramount importance that the materials used for gas turbine components that operate in these environments provide acceptable and predictable in‐service life times. Single crystal superalloys (e.g. CMSX‐4) were developed to have improved mechanical properties (creep and fatigue) at increasing component operating temperatures, especially in relatively clean aero‐engine operating environments. This paper describes work carried out to investigate the development of hot corrosion processes on CMSX‐4 (uncoated and Pt‐Al coated) in a range of potential environments for blade materials in industrial gas turbines fired on biomass derived fuel gases. A series of laboratory tests has been carried out using the ‘deposit recoat’ technique, with exposure conditions covering: deposits of 80/20 and 50/50 (Na/K)2SO4, with additions of lead, a gas composition of 100 vpm SOx, 100 vpm HCl in simulated combustion gases, deposition flux of 15 µg/cm2/h, temperature of 700 °C, for periods up to 1000 h. During their exposure the materials were monitored using traditional mass change methods. However, quantitative damage data in terms of metal loss was obtained using dimensional metrology, pre‐exposure contact measurements combined with post‐exposure measurements of damage observed by optical microscopy on polished cross‐sections. These measurement methods allowed the distribution of damage to be determined and the material sensitivity to such hot corrosion processes to be quantified.

Trends in fireside corrosion damage to superheaters in air and oxy-firing of coal/biomass

This paper compares the laboratory-based fireside corrosion tests on superheater/reheater materials in simulated air-firing combustion conditions with oxy-firing combustion conditions (with hot gas recycling before flue gas de-sulphurisation). The gaseous combustion environment was calculated based on a specific co-firing ratio of CCP with Daw Mill coal. The fireside corrosion tests were carried out using the “deposit recoat” test method to simulate the damage anticipated in specific environments. A synthetic deposit (Na2SO4:K2SO4:Fe2O3=1.5:1.5:1mol.) which has commonly been used in fireside corrosion screening trials and is a mix that forms alkali-iron tri-sulphate (identified in many investigations as a cause of fireside corrosion) was used in these tests. The air-fired tests were carried out at temperatures of 600, 650 and 700°C and oxy-fired tests were carried out at temperatures of 600, 650, 700 and 750°C to represent the superheater/reheater metal temperatures anticipated in future power plants with and without synthetic deposits, with four candidate materials: T92, HR3C and 347HFG steels; nickel-based alloy 625 (alloy 625 was only tested with screening deposits). The progress of the samples during their exposures was measured using mass change methods. After the exposures, the samples were examined by SEM/EDX to characterise the damage. To quantify the metal damage, pre-exposure micrometre measurements were compared to the post-exposure image analyser measurements on sample cross-sections. The trends in corrosion damage in both air and oxy-firing conditions showed a “bell-shaped” curve, with the highest metal damage levels (peak) observed at 650°C for air-firing and 700°C for oxy-firing tests. However, at 600 and 650°C similar damage levels were observed in both environments. The shift in peak corrosion damage in oxy-firing condition is believed to be the presence of higher levels of SOx, which stabilised the alkali-iron tri-sulphate compounds. Generally, in both air and oxy-firing conditions the mean metal damage was reduced with increasing the amount of Cr in the alloys. However, at the highest temperatures in both air-firing (700°C) and oxy-firing conditions (750°C) the metal damage of nickel based superalloy 625 was higher than HR3C.

Fireside Corrosion of Superheater Materials in Coal/Biomass Co-fired Advanced Power Plants

A series of laboratory-based fireside corrosion exposures were conducted to assess the effect of such conditions on superheater/reheater materials at higher than conventional metal temperatures. Controlled atmosphere furnaces combined with the “deposit recoat” test method were used to generate the exposure conditions; the gaseous environment simulated that anticipated from air-firing 20 wt% cereal co-product mixed with a UK coal. The exposures were carried out at 600, 650 and 700 °C with four candidate materials: T92, HR3C and 347HFG steels; nickel-based alloy 625. After the exposures, the samples were examined by SEM/EDX to characterize the damage. Pre- and post-exposure dimensional metrology were used to quantify the metal damage in terms of metal loss distributions. For the austenitic steels, the combined deposit/gas/temperature exposure conditions enabled quantification of the characteristic ‘bell-shaped’ curves (of damage as a function of temperature) for fireside corrosion.

Fireside corrosion of superheaters: Effects of air and oxy-firing of coal and biomass

The growing world population requires increasing quantities of electricity from sources that have reduced environmental impact, especially CO2 emissions. For pulverised coal-fired power plants, reduced CO2 emissions can be achieved by increasing the operating temperatures/pressures of the steam systems (which increases the efficiency of power generation), the use of ‘carbon-neutral’ fuels such as biomass, and/or the implementation of CO2 capture technologies. The use of small quantities of biomass fuels (typically up to 5% of the energy content of the fuels) is already widely practised in the UK. As an alternative, oxy-firing pulverised fuel power plants provides a route to enable CO2 capture technologies to be introduced; but this route also requires the use of higher temperature/pressure steam systems to counter-act the efficiency penalty of CO2 capture and handling systems. All of these options to reduce CO2 emissions result in significant changes to the operating conditions (e.g. metal temperatures, gas temperatures, gaseous environments and deposits) that are anticipated for superheaters in these power systems. Such changes in operating conditions are expected to result in higher rates of fireside corrosion and so reduce the potential lives of these critical components.This paper reports the results of investigations that have been carried out to assess the effect on fireside corrosion of operating superheaters at higher metal temperatures in power systems using coal/biomass fuels fired with air or oxygen. A series of fireside corrosion experiments has been carried out using the ‘deposit recoat’ test method to simulate the damage anticipated in different specific environments. Using an alumina-lined controlled-atmosphere furnace, the gaseous and deposit environments were simulated for superheaters in (a) air-fired and (b) oxy-fired (hot gas recycle system variant) power plants using cereal co-product and a UK coal. The corrosion tests were carried out at temperatures of 600 and 650°C, to represent the metal temperatures anticipated in power plants in the near future. The potential superheater materials used in these tests were T92, 347HFG and HR3C steels, as well as one nickel-based material, alloy 625. The progress of the exposures was monitored using traditional mass change methods. Destructive examinations of the samples were carried out after their exposures, using optical microscopy and SEM/EDX methods to characterise the damage observed. The performance of the materials was determined using dimensional metrology; pre-exposure micrometer measurements and post-exposure image analyser measurements on polished cross-sections. The resulting metal loss distribution data for each sample exposed are being used for the development of statistical models of the fireside corrosion of superheater materials in novel operating environments.

Degradation of heat exchanger materials under biomass co-firing conditions

Co-firing biomass in conventional pulverised coal fired power stations offers a means to rapidly introduce renewable and CO2 neutral biomass fuels into the power generation market. Existing coalfired power stations are both much larger and more efficient than current designs of new biomass combustion systems, so feeding a few percent of biomass feed into an existing large coal fired station will give more biomass derived power than a new dedicated biomass station. Co-firing levels started at ∼2% biomass, but this has increased to ∼5–10% biomass, with higher levels of biomass co-firing being investigated, although supply of biomass becomes an issue with increasing co-firing levels. The lower levels of biomass co-firing (up to ∼5%) can be achieved with relatively minor modifications to existing plants, so avoiding the large capital costs and risks of building new biomass-only fired power systems. However higher levels of co-firing are more difficult to achieve, requiring dedicated biomass supply systems and burners. For existing coal-fired power stations, the co-firing of biomass causes some practical problems, e.g.: the control of co-firing two fuels; changes to bottom/fly ash chemistry; changes to deposition (fouling and slagging) within the boiler; reduced reliability of key high temperature components (e.g. heat exchangers) due to increased corrosion problems relative to those experienced with coal alone.This paper reports the results of assessments carried out to evaluate the potential operating conditions of heat exchangers in combustion systems with biomass (wood or straw) and coal cofiring, as well as laboratory corrosion tests that have been carried out to give an initial assessment of potential effects of biomass-co-firing.The corrosion tests have been carried out using the deposit recoat method in controlled atmosphere furnaces. A series of 1000 hour tests have been carried out at typical superheater and evaporator metal temperatures using simulated deposit compositions and gaseous environments (selected on the basis of plant experience and potential fuel compositions). Five materials were exposed in these tests: 1Cr steel, T22 steel, X20CrMoV121, TP347HFG and alloy 625. In order to produce statistically valid data on the actual metal loss from the materials, the performance of the materials in these tests was determined from dimensional metrology before and after exposure. For each material, these data have been used to determine the sensitivity of the corrosion damage to changes in the exposure conditions (e.g. deposit composition, gas composition) thereby producing initial models of the corrosion performance of the materials. The corrosion data and model outputs have been compared with data available from power plants operating on coal, straw or wood fuels.

Modelling hot corrosion in industrial gas turbines

Gas turbines are a critical component within combined cycle power systems that are being developed to generate electricity more cleanly and efficiently from solid fuel sources, that include coal and biomass. The use of such fuels, to produce fuel gases, increases the potential for significant corrosion and erosion damage to gas turbine blades and vanes.This paper addresses the modelling and prediction of type II hot corrosion in industrial gas turbines within the aim of given acceptable and predictable lifetimes.A matrix of corrosion tests have been undertaken using the ‘deposit recoat’ test procedure, with samples cooled periodically to re-apply controlled amounts of salt deposit. Deposited salt was 4/1 mole fraction of Na2SO4 and K2SO4, with deposited fluxes of 0, 1.5, 5.0 and 15.0 μg/cm2/h. Samples of polycrystalline (IN738 and IN792) and single crystal superalloys (CMSX4 and SC2B) were exposed for test durations of 500 and 1000 h at 700°C in a variety of gas compositions, consisting of air+50–500 vppm SO2+0–500 vppm HCl+0–5 vol% H2O.Section loss data has been measured, using precision optical metrology and analysed statistically. Models have been developed that predict section loss as a function of salt deposition rate and gas composition to precisions of ±20 mm loss, with 95% confidence (2×standard deviation).

Modelling hot corrosion in industrial gas turbines

Gas turbines are a critical component within combined cycle power systems that are being developed to generate electricity more cleanly and efficiently from solid fuel sources, that include coal and biomass. The use of such fuels, to produce fuel gases, increases the potential for significant corrosion and erosion damage to gas turbine blades and vanes.This paper addresses the modelling and prediction of type II hot corrosion in industrial gas turbines within the aim of given acceptable and predictable lifetimes.A matrix of corrosion tests have been undertaken using the ‘deposit recoat’ test procedure, with samples cooled periodically to re-apply controlled amounts of salt deposit. Deposited salt was 4/1 mole fraction of Na2SO4 and K2SO4, with deposited fluxes of 0, 1.5, 5.0 and 15.0 μg/cm2/h. Samples of polycrystalline (IN738 and IN792) and single crystal superalloys (CMSX4 and SC2B) were exposed for test durations of 500 and 1000 h at 700°C in a variety of gas compositions, consisting of air+50–500 vppm SO2+0–500 vppm HCl+0–5 vol% H2O.Section loss data has been measured, using precision optical metrology and analysed statistically. Models have been developed that predict section loss as a function of salt deposition rate and gas composition to precisions of ±20 mm loss, with 95% confidence (2×standard deviation).