No abstract

By the end of 2009, there will be eight biomass and five biomass co‐firing plants in Denmark. Due to the steep increase of corrosion rate with respect to temperature in biomass plants, it is not viable to have similar steam data as fossil fuel plants. Thus for the newer plants, Maribo Sakskøbing, Avedøre 2 biomass boiler, Fyn 8 and Amager 1 (Fyn 8 and Amager 1 are under commissioning), the steam temperature of the final superheaters are approximately 540 °C and the steel type used is an 18–10 stainless steel, (TP347H). However there is still a need to monitor corrosion rates, and to collate data to enable better lifetime prediction of vulnerable components in straw‐firing plants since the corrosion rates are so much faster than in coal firing plants. Therefore, there are continued investigations in recently commissioned plants with test tubes installed into actual superheaters. In addition temperature is measured on the specific tube loops where there are test tube sections. Thus a corrosion rate can be coupled to a temperature histogram. This is important since although a superheater has a defined steam outlet temperature, there is variation in the tube bundle due to variations of heat flux from the flue gas. This paper will describe the corrosion investigations for tube sections removed from Maribo Sakskøbing and Avedøre 2 biomass boiler which have been exposed for up to 30 000 h. In addition to monitoring the corrosion rates of actual components, there is a need to measure corrosion rates at higher temperatures to assess if there is a possibility to increase the outlet temperature of the plant, thus making the plant more cost effective. For this purpose Avedøre 2 biomass boiler has a test superheater loop fabricated in TP347H FG (the same material as the final superheaters). Some results from this test superheater will also be described. Effects of flue gas temperature and flue gas direction on corrosion rates are also discussed.

Deposit-induced chlorine corrosion was studied under well-controlled laboratory conditions, simulating the conditions in straw-fired boilers and boilers cofiring coal and straw. This was done by exposing pieces of superheater tube (TP 347H FG) covered with synthetic deposits of known Cl content to gas mixtures simulating straw-firing and cofiring of coal and straw, at 560°C (1040°F), for 3 days. The corroded specimens, and the reacted deposits, were studied in detail using a scanning electron microscope to determine the corrosion rate, investigate the chemistry and morphology of the corrosion attack, and study the sulfation behavior. Besides the gas compositions, various parameters were studied systematically. Most specimens suffered some internal attack, mostly by selective corrosion and in some cases by grain boundary attack. In all experiments with KCl and KCl-SiO 2 deposits, the corrosion products consisted of an oxide scale, containing oxides of Cr and Fe, and on top of that a characteristic mixed layer of iron oxide threads in a potassium sulfate matrix. However, the thickness and shape of this layer was found to be strongly dependent on the experimental conditions. An increase of the percentage of KCl in the deposit resulted in a more uniform and deeper internal corrosion attack. The presence of HCl in the flue gas did not seem to be essential for chlorine-induced corrosion to occur, when a deposit containing KCl was present, but it enhanced the corrosion rate. The degree of sulfation of KCl in the deposits after exposure was quantified by wet chemical analysis and was shown to be dependent on many parameters, including the SO 2 concentration in the gas flow, the concentration of KCl in the deposit, and the SiO 2 and KCl particle sizes in the deposit. No simple relation was observed between the degree of sulfation in the deposit and the depth of internal attack or the thickness of the oxide or mixed layer. Whereas SiO 2 particles were found to be chemically inert with respect to the flue gas and the corrosion attack, CaO particles reacted with HCl from the flue gas, and the resulting CaCl 2 played an important role in the corrosion mechanism. As a result, the corrosion rate was strongly enhanced when CaO was present in the deposit, instead of SiO 2 .

To obtain long term corrosion and steam oxidation data for the 9-12%Cr ferritic steels, test tube sections have been exposed in Amager 3 and Avedøre 1 coal fired power plants in Denmark (formerly run by ENERGI E2). Thus direct comparisons can be made for T91 and T92 for the 9%Cr steels and X20CrMoV121 and HCM12 for the 12%Cr steels. The test tubes were welded in as part of the existing final superheaters in actual plants and exposure has been conducted over a ten year period (1994)(1995)(1996)(1997)(1998)(1999)(2000)(2001)(2002)(2003)(2004)(2005). Compared to the older steel types, T92 and HCM12 utilise tungsten to improve their creep strength. From Avedøre I testing, T91 and T92 can be compared for exposure times up to y48 000 h exposure. From Amager 3 testing, X20, HCM12 and T92 were tested; T92 has been exposed for up to 31 000 h and X20 and HCM12 have had 84 500 h exposure. Tube sections were removed for various exposure durations such that steamside oxidation and fireside corrosion could be investigated with respect to exposure time. The fireside corrosion rate was assessed by oxide thickness and in some cases residual metal thickness. The growth of steamside oxide was assessed by inner oxide thickness. The microstructure and chromium content of the corroded layers has been investigated using light optical and scanning electron microscopy. The fireside corrosion rate for the T92 and HCM12 steels are comparable to those of T91, however X20CrMoV121 has a higher fireside corrosion rate after the longest exposure time. For steamside oxidation, it was HCM12 that revealed high oxidation rates after the longest exposure time.

Over the past few years, considerable high temperature corrosion problems have been encountered when firing biomass in power plants due to the high content of potassium chloride in the deposits. Therefore, to combat chloride corrosion problems cofiring of biomass with a fossil fuel has been undertaken. This results in potassium chloride being converted to potassium sulphate in the combustion chamber and it is sulphate rich deposits that are deposited on the vulnerable metallic surfaces such as high temperature superheaters. Although this removes the problem of chloride corrosion, other corrosion mechanisms appear such as sulphidation and hot corrosion due to sulphate deposits. At Studstrup power plant Unit 4, based on trials with exposure times of 3000 h using 0-20% straw co-firing with coal, the plant now runs with a fuel mix of 10% straw þ coal. Based on results from a 3 years exposure in this environment, the internal sulphidation is much more significant than that revealed in the demonstration project. Avedøre 2 main boiler is fuelled with wood pellets þ heavy fuel oil þ gas. Some reaction products resulting from the presence of vanadium compounds in the heavy oil were detected, i.e. iron vanadates. However, the most significant corrosion attack was sulphidation attack at the grain boundaries of 18-8 steel after 3 years exposure. The corrosion mechanisms and corrosion rates are compared with biomass firing and coal firing. Potential corrosion problems due to co-firing biomass and fossil fuels are discussed.