Fireside issues in advanced power generation systems

REVIEW Fireside issues in advanced power generation systems N. J. Simms*, J. Sumner, T. Hussain and J. E. Oakey The requirements to supply increasing quantities of electricity and simultaneously to reduce the environmental impact of its production are currently major issues for the power generation industry. Routes to meeting these challenges include the development and use of power plants with ever increasing efficiencies coupled with the use of both a wider range of fuels and technologies designed to minimise CO2 emissions. For fireside hot gas path components, issues of concern include deposition, erosion and corrosion in novel operating environments and increased operating temperatures. The novel operating environments will be produced both by the use of new fuel mixes and by the development of more complex gas pathways (e.g. in various oxyfired or gasification systems). Higher rates of deposition could significantly reduce heat transfer and increase the need for component cleaning. However, degradation of component surfaces has the potential to be life limiting, and so such effects need to be minimised. Materials and operational issues related to these objectives are reviewed. Keywords: Fuel compositions, Fireside corrosion, Oxyfiring, Co-firing, Gasification, Gas turbines, Review This paper is part of a special issue featuring contributions from the 8th International Charles Parsons Turbine Conference Introduction The electricity power generation industry faces major issues in developing its future power plants. The requirements that must be addressed include: (i) generating ever increasing quantities of electri- city: many assessments of future trends exist, some of which are revised annually, but one current example, from the International Energy Outlook 2010,1 projects an increase of 87% in worldwide electricity requirements during the period 2007–35 (ii) reducing the levels of CO2 emissions from power generation systems: as a result of concerns about global warming, the enhanced greenhouse effect that is widely believed to be a result of increasing levels of CO2 and other greenhouse gases in the atmosphere, measures are being introduced to limit the levels of CO2 emitted. Targets vary around the world. The European Union (EU) has put in place a target of a 20% reduction by 20202 (compared with 1990s emission levels) and developed a roadmap leading to an 80% reduction by 2050.3 In contrast, the latest UK government legislation4 requires an 80% reduction by 2050 (iii) security of supply: the reliable production of enough electricity to always meet demand becomes increasingly challenging as more intermittent renewable energy supplies (such as wind power) are used and also as fuels need to be transported over increasing distances and across several countries (e.g. natural gas pipelines from Russia to Western Europe)2 (iv) regulation of electricity generation and emis- sions: regulations from national governments and regional organisations (e.g. the EU) can directly affect electricity production, either in terms of subsidies/restrictions on the fuels that can be used and the emissions that can be generated, the granting of permission to build (and/or use) power plants or by influencing the prices that may be charged for electricity (v) economic viability: in many countries, electricity production is carried out by companies that need to be profitable. Thus, all costs associated with this production (from power plant construction, continuing fuel purchases, power plant mainte- nance, emission control systems, distribution systems, etc.) and income (from electricity, byproducts, subsidies, etc.) are important factors. In the present paper, the main focus is on the development of power generation systems that reduce CO2 emissions. A number of potential routes have been proposed to achieve this.5–7 Firstly, by increasing electricity generation efficien- cies. Higher operating temperatures and pressures for steam and gas turbines have been under development for Centre for Energy and Resource Technology, Cranfield University, Cranfield, Bedfordshire MK43 0AL, UK *Corresponding author, email [email protected] 804 � 2013 Institute of Materials, Minerals and Mining Published by Maney on behalf of the Institute Received 26 September 2012; accepted 26 September 2012 DOI 10.1179/1743284712Y.0000000133 Materials Science and Technology 2013 VOL 29 NO 7 many years and result in higher system efficiencies. However, the rate of change needs to be increased to meet the CO2 emission reduction targets being set. The resulting increases in component operating temperatures present many materials challenges, including creep and fatigue, as well as fireside issues. Secondly, by fuel switching, for example: (i) changing from coal fired to natural gas fired generation is an effective method of reducing CO2 emissions (due to the lower carbon content of methane per unit of energy than coal and also the higher efficiencies of combined cycle gas turbines compared to Rankin cycles) (ii) changing from coal to biomass fuels, which are classed as CO2 neutral fuels, with no net CO2 emission, as they require CO2 from the atmo- sphere to grow (iii) co-firing biomass with coal; in this case, a proportion of the coal fuel is replaced by biomass (again benefiting from the use of a CO2 neutral fuel). Thirdly, by capturing and storing CO2, for which many different CO2 capture technologies exist, which include systems for either pre- or post-combustion CO2 removal: (i) fuel gasification (using either oxygen or steam as the oxidant) produces a gas that can be conditioned to enable precombustion CO2 removal (ii) post-combustion CO2 capture can be carried out using either solid or aqueous sorbent processes (iii) oxyfiring of fuels is a technology that can enable more efficient post-combustion CO2 capture, but requires the use of an air separation unit (iv) chemical looping combustion provides the possibility of CO2 capture without the require- ment of an air separation unit or an absorption process. Finally, there is the option to increase the proportion of electricity generated by nuclear or renewable sources (e.g. wind, wave, solar power). A selection of issues related to the first three of these four routes is discussed below. In these developing power generating systems, the numerous possible combinations of new fuels, novel technologies and higher temperature operating conditions have the potential to produce challenging operating environments for components. Deposition, erosion and corrosion all have to be considered for the fireside surfaces of hot gas path components (which can include various heat exchangers, gas cleaning systems, gas turbines, etc.). High rates of deposition can significantly reduce heat transfer and increase the need for component cleaning. Furthermore, surface degradation, arising from the presence of particles, vapours and gas phase species within fireside environments, has the potential to be life limiting for such components. In summary, potential fuels for advanced power generation systems and the fireside issues that arise for some components in these systems are reviewed. Fuels An increasing number of biomass and waste fuels are being considered for use in power generation systems alongside more traditional fossil fuels.8 These potential fuels can have a wide range of different physical and chemical properties compared to fossil fuels, but other issues are also important, including fuel availability and fuel variability. Therefore, for many larger scale systems, it is necessary to consider the behaviour of fuel mixtures as well as single fuels. While properties affecting deposition, erosion and corrosion are of particular interest for the present paper, these need to be assessed alongside factors affecting fuel storage, preparation and handling, as well as the pyrolysis, combustion and gasification behaviours of different fuel size ranges. Solid fuels Coal A wide variety of coals are available around the world. These are often put into broad classifications of lignite, sub-bituminous, bituminous and anthracite coals. However, more detailed analyses show that distinctive coals are produced from individual coal mines, with differences including their structures, heat, moisture and ash contents, as well as major, minor and trace elements (included within the coal structure and its associated minerals). Such variations produce different deposition, erosion and corrosion behaviours in various types of combustion and gasification systems. Examples of coal fuels are given in Table 1.7–10 Traditionally, locally sourced coals were used for power generation systems, but now there is a large market in world traded coals, and so the cheapest delivered fuels tend to be used (depending on national regulations).5 This favours the use of imported coal when good transport links are available (e.g. port facilities), but often local coal when transporting large quantities of fuel is more difficult. For the UK, this has provided an opportunity to use lower sulphur (and often lower chlorine) content coals (Table 1). Table 1 Examples of coal, biomass and waste compositions*7–10 Parameter Unit UK coal South American coal US coal Polish coal Willow Miscanthus Wheat straw CCP Olive residue Moisture wt-% ar 11.9 13.0 10.5 11.0 15 25 25 11.8 13.5 Ash wt-% dry 15.3 9.0 11.3 5.4 2.0 4.0 5.0 5.3 4.5 CV (gross) MJ kg21 daf 34.3 32.7 34.4 34.0 20.3 19.8 19.8 20.1 21.4 C wt-% daf 81.6 79.9 84.6 83 49 49 49 49 49 H 5.2 5.3 5.1 4.6 6.2 6.4 6.3 6.2 6.0 O 8.7 12.2 7.6 10.0 44 44 43 44 40 N 1.8 1.7 1.7 1.6 0.5 0.7 0.5 0.5 2.24 S 2.28 0.8 1.2 0.7 0.05 0.2 0.1 0.18 0.1 Cl 0.7 0.1 0.07 0.04 0.03 0.2 0.4 0.19 0.1 *CV: calorific value; ar: as received; daf: dry ash free; CCP: cereal coproduct. Simms et al. Fireside issues in advanced power generation systems Materials Science and Technology 2013 VOL 29 NO 7 805 Biomass Biomass fuels can be classified in several different ways.11 One approach is to consider the intended purpose of the biomass, for example: (i) biomass specifically cultivated as ‘energy crops’; e.g. within the UK, this could include coppiced willow, poplar and miscanthus (ii) waste biomass, e.g. various straws, wood waste, forest residues, palm nut residues, olive residues, almond waste. Some biomass can be further processed to produce more distinctive products that are easier to handle and transport, such as pelletised wood or cereal coproduct (CCP). The low energy densities of many biomasses encourage their local use. However, as a result of some biomass producers and users being located near easy routes for bulk transport, and favourable economic conditions, a world trade in biomass has developed. Each biomass crop inevitably has a unique set of properties and compositions (Table 1).7–9 These depend to some extent on the fertiliser used during their growth, harvest time and post-harvest treatment/storage, as well as the type of crop and its growth location. In practise, a wide scatter in some properties is found, as indicated in the European Committee for Standardization (Comité Européen de Normalisation, CEN) standards developed for biomass fuels.9 However, faster growing biomass tends to have higher chlorine (and potassium) contents than slower growing biomass. Biomass fuels have much lower carbon contents than coal, but with higher hydrogen levels and much higher oxygen levels. Figure 1 illustrates how the bulk compo- sitions of biomass and coals fall within a trend if considered in terms of their H/C and O/C atomic ratios.8 In general, biomass contains lower levels of sulphur than coals (Table 1 and Fig. 2), so co-firing a coal with a biomass will result in reductions in SOX levels in the flue gas stream. In contrast, biomass chlorine contents cover the range of those in coals (Fig. 2), but can also extend up to y2?5 wt-% (on a dry, ash free basis). The variability of both coal and biomass fuels means that assessments of their potential behaviours need to be carried out for specific fuels and potential mixes of those fuels. Figure 3 shows the results of an assessment of potential SOX and HCl gas compositions obtained from co-firing either a UK coal or a Columbian coal with CCP or wheat straw (at mixes of 0, 10, 20, 30, 40, 50 and 100 mass-%). The trend lines shown for these four mixtures indicate that, in all cases, the SOX levels are reduced (more significantly for the UK coal), but the HCl content of flue gas can remain approximately the same, or increase, or decrease, depending on the specific fuel combination. Waste Waste fuels can include a wide range of materials: for example, various types of sewage sludges and municipal solid waste, as well as processed waste streams, such as refuse derived fuels and solid recovered fuels (SRFs).5 Raw wastes are well known to be inhomogeneous, with all the parameters that can be used to measure the fuel properties showing large scatterbands.12 In recent years, to try to assist in developing the use of wastes for energy production, SRFs have been developed, along with a systematic classification system.13 This focuses on properties related to heat recovery and emissions (i.e. mean net calorific value, mean chlorine content, and median and eightieth percentile values of mercury content, all on an as received basis). In parallel, standard methods have also been developed to measure other fuel properties so that they can be compared to those for coal and biomass fuels. Gas fuels It is necessary to consider an increasing range of gaseous fuels for power generation systems as their use in gas turbine can have the potential to offer more efficient and flexible electricity generation than solid fuels. These fuels can include: (i) conventional natural gas (ii) liquefied natural gas (iii) natural gas with increasing H2S levels (i.e. more sour), e.g. up to y5%H2S in natural gas 1 Relationship between H/C and O/C atomic ratios for coals and biomass8 2 Sulphur and chlorine contents of selected biomass and coals (wt-%, dry ash free basis)8 3 Effect of increasing levels of CCP co-firing on antici- pated SOX and HCl in fireside environments Simms et al. Fireside issues in advanced power generation systems 806 Materials Science and Technology 2013 VOL 29 NO 7 http://www.maneyonline.com/action/showImage?doi=10.1179/1743284712Y.0000000133&iName=master.img-000.jpg&w=227&h=133 http://www.maneyonline.com/action/showImage?doi=10.1179/1743284712Y.0000000133&iName=master.img-001.jpg&w=227&h=134 http://www.maneyonline.com/action/showImage?doi=10.1179/1743284712Y.0000000133&iName=master.img-002.jpg&w=226&h=133 (iv) hydrogen, e.g. derived from natural gas by steam reformation14 (v) fuel gases derived from various possible inte- grated gasification combined cycle (IGCC) systems. Depending on the system, these range from low calorific value fuel gases (containing H2, CO, CO2, H2O, N2 and a host of contaminants) to hydrogen enriched syngas.15,16 Systems of IGCC can be fired on coal, biomass, waste and mixed fuels (in the section on ‘Gasification systems’). The different bulk gas compositions present many challenges in terms of gas handling, control and combustion technologies. However, from the point of view of fireside materials issues, it is the minor and trace contaminants in these gas streams that cause issues related to deposition, erosion and corrosion (in the sections on ‘Gasification systems’ and on ‘Gas turbines’).14,15 Pulverised fuel systems Coal firing For many years, pulverised coal fired power plants have operated with steam conditions of about 540–560uC/ 160–180 bar (and efficiencies of y35% with retrofitted gas cleaning systems included). Fireside metal surface temperatures have traditionally been calculated to be about 30–50uC hotter than steam temperatures; for these older systems, about 570–610uC. However, for both new and retrofitted pulverised coal fired power plants, these operating conditions are changing:17,18 (i) current state of the art steam operating condi- tions are about 600–620uC/240 bar (giving design efficiencies of y45% and fireside metal temperatures of up to y650uC) (ii) 650uC steam systems were the focus of the EU COST536 programme (with corresponding fire- side metal temperatures of up to y700uC)17,18 (iii) 700uC steam systems were targeted by the EU Thermie programme (with fireside metal tem- peratures of up to y750uC)17 (iv) 760uC/350 bar steam systems are now being targeted by research programmes in the USA, Japan and EU (with fireside metal temperatures of up to y810uC).18 During the course of operating pulverised coal fired power plants, considerable experience has been gained of the fireside surface degradation of components in these systems while burning a wide variety of coals.8,14,19–21 It has been found that waterwalls and superheater/reheater tubes are particularly vulnerable. Waterwall tubes have traditionally operated with metal temperatures of up to y400uC and heat fluxes of y350 kW m22.8,20 These tubes have been manufactured from low alloyed ferritic steels. Slag type deposits can form on their surfaces, restricting heat transfer. The fireside corrosion of waterwall tubes has been found to be heavily influenced by the presence of FeS compounds in the surface deposits and by periods of exposure under reducing conditions.14,22 Reducing conditions can occur due to: flame impingement on the tubes; the use of low NOX burners; and, the use of boosted over firing air (BOFA), which further reduces the formation of thermal NOX. Moving towards higher temperature/pressure steam systems will change the operating conditions of water- wall tubes, giving higher metal temperatures, and will require the use of higher alloyed ferritic steels, particu- larly in the upper parts of these walls. For superheater/reheater tubes, it has been found that the formation of deposits around these tubes is an important part of the degradation process,20 with deposits forming through a combination of mechanisms, including the direct inertial impaction of larger particles, eddy impaction of particles, thermophoresis of smaller particles and vapour condensation (Fig. 4).8,23 Fireside corrosion is usually induced by alkali sulphate species in the deposit, reacting with the local environment and other deposit components to produce low melting mixtures at the tube surfaces (such as alkali pyrosul- phates or alkali iron trisulphates).19,20 It is believed, mainly following laboratory corrosion testing, that superheater/reheater fireside corrosion damage tends to follow a series of bell shaped curves with increasing temperature, as different low melting point deposits have distinct stability ranges (Fig. 5).8,19,20,22 As steam temperatures/pressures increase, the materi- als required for superheaters/reheaters will need to change from ferritic steels and lower alloyed stainless steels to higher alloyed stainless steels and nickel based alloys to enable sufficient creep lives to be maintained.18 However, fireside corrosion rates also increase signifi- cantly with temperature, as indicated by the bell shaped 4 Potential deposition processes around superheater/ reheater tubes in pulverised fuel fired power system10 5 Characteristic bell shaped curve for fireside corrosion damage mechanism8 Simms et al. Fireside issues in advanced power generation systems Materials Science and Technology 2013 VOL 29 NO 7 807 http://www.maneyonline.com/action/showImage?doi=10.1179/1743284712Y.0000000133&iName=master.img-003.jpg&w=227&h=195 http://www.maneyonline.com/action/showImage?doi=10.1179/1743284712Y.0000000133&iName=master.img-004.jpg&w=227&h=133 curves, so the peak rates and their metal temperatures for the alkali iron trisulphate corrosion mechanism (and any higher temperature alkali sulphate corrosion mechanisms) will become increasingly important. To counter the fireside corrosion damage and give adequate component lives, it may be necessary to develop and use protective coatings on such heat exchanger tubes. Both of these topics are being addressed in continuing research activities.24,25 Current candidate alloys for ultra supercritical (USC) and advanced USC (A-USC) plant boilers are listed in Table 2 with an indication of their main alloying elements and the potential components. The differences in materials selection required as a function of super- heater/reheater steam temperatures are summarised in Table 3, which illustrates the required move towards higher alloyed steels and nickel based alloys as component temperatures rise. Biomass co-firing Co-firing of biomass in conventional pulverised coal power plants offers one route to introduce these renewable, CO2 neutral fuels. 7,10 Biomass can be introduced into many existing coal fired plants following some relatively minor modifications and so avoids the much larger capital costs and risks of building a new (lower efficiency) biomass only fired power system. However, for the existing coal fired power stations, this gives some potential practical challenges: handling and feeding biomass fuels, control of co-firing two fuels (e.g. mixed fuel or separate burners), changes to bottom/fly ash chemistry, etc. Table 2 Candidate alloys for USC and A-USC plant boilers*36 Alloy Nominal composition Application ASME code Haynes 230 57 Ni–22Cr–14W–2Mo–La P, SH/RH tubes 2063 INCO740 50Ni–25Cr–20Co–2Ti–2Nb–V–Al P, SH/RH tubes CCA617 55Ni–Cr–0.3W–8Mo–11Co–Al P, SH/RH tubes 1956 HR6W 43Ni–23Cr–6W–NB–Ti–B SH/RH tubes Super304H 18Cr–8Ni–W–Nb–N SH/RH tubes Save12 12Cr–W–Co–V–Nb–N P NF 616 (P92) 9Cr–2W–Mo–V–Nb–N WW tubes 2179 HCM2S (P23) 2–1/4Cr–1.5W–V WW tubes 2199 HCM12 12Cr–1Mo–1W–V–Nb WW tubes 347HFG 18Cr–10Ni–Nb SH/RH tubes 2159 NF 709 20Cr–25Ni–NB–Ti–N SH/RH tubes HR3C 25Cr–20Ni–Nb–N SH/RH tubes 2113 HCM12A(P122) 12Cr–1.5W–Mo–V–Nb_N P 2180 NF12 11Cr–2.6W–2.5Co–V–Nb–N P IN625 21.5Cr–9Mo–5Fe–3.6Nb–AI–Ti P, T 1409 HR120 Ni–33Fe–25Cr–N T 2315 E911 9Cr–1Mo–1W–V–Nb–N P Sanicro25 22Cr–25Ni–3.5W–3Cu–Nb–N *P: pipe; SH: superheater; RH: reheater; WW: waterwall. Table 3 Components and candidate alloys for different steam conditions (superheater/reheater) in USC and A-USC coal fired power plants (adapted from Ref. 36)* Component 593/593uC (1100/1100uF) 621/621uC (1150/1150uF) 649/649uC (1200/1200uF) 704/704uC (1300/1300uF){ 732/760uC (1350/1400uF)1 SH outlet header/main steam pipe P91, P92, E911 P92, P122, E911, SAVE 12 NF12, CCA617 Nimonic263, CCA617 IN740 RH outlet header/RH pipe P91, P92, E911 P91, P92, E911 NF12, CCA617 Nimonic263 IN740 SH panels{ Super304H, HR3C, 347HFG Super304H, HR3C, 347HFG NF 709, Cr 30A Super304H, Sanicro25, HR3C, Super304H, 310N IN617, 347HFG Finish SH{ Super 304H, HR3C, 347HFG HR6W, HR120, HR3C IN617 I N617, IN740 IN740 Primary RH{ Super304H, HR3C, 347HFG Super304H, HR3C, 347HFG NF709, Cr 30A, Super304H Sanicro 25, HR3C, Super304H 304H, 347HFG Finish RH{ Super304H, HR3C, 347HFG Super304H, HR3C, 347HFG IN617 IN617, IN740 Haynes 230, Super304H, HR120 Economiser SA210C SA210C SA210C SA210C SA210C Lower waterwall T11, T12, T22 T22 T22 T23 T23 Upper waterwall T23, HCM12 T23, HCM12 HCM12, T23 TI B1010, 7Cr Mo V, T23, HCM12 T92, HCM12 *This table is for general information only and does not include all the nuances that need to be considered by the designer. The service condition listed in each column represents the maximum conditions of exposure. Steam pressure of 31 MPa (4500 lb in22) has been assumed for this table. {For corrosive, high sulphur/low NOX conditions, SH/RH and waterwall tubes may require weld overlay or cladding with IN72 (42% Cr). {Based on European AD700 Project. 1Based on DOE/OCDO Project. Simms et al. Fireside issues in advanced power generation systems 808 Materials Science and Technology 2013 VOL 29 NO 7 From the point of view of fireside issues, biomass co- firing has the potential to change the rate of formation of deposits on heat exchanger tube surfaces and the composition of the deposits, as well as changing the fireside corrosion mechanisms to give higher damage rates than experienced with coal alone.10,23 These effects all relate back to the compositions of the coals and biomass used (in the section on ‘Solid fuels’). When a biomass is fired alone, the different chemical and physical forms of the compounds present compared to coals produce different deposit compositions and deposition fluxes. When co-firing biomass and coal, it is necessary to consider the specific fuels being used. Figure 3 illustrates the sensitivity of SOX and HCl levels to the use of specific biomass/coal mixtures. Deposit compositions and fluxes can be influenced in a similar way. If a biomass has a higher level of available (reactive) alkali species than the coal it is being mixed with, then adding increasing levels of biomass will initially increase the levels of alkali sulphate species in a deposit (as there are excess sulphur species available from the coal). However, at higher levels of biomass, if it has a higher chlorine level than the coal, alkali chlorides and sulphates will both be formed in the deposit. Thus, the effects depend on the balance between the sulphur, chlorine and available (reactive) alkali species from both the biomass and coal being used. Such changes in deposit composition and deposition flux are of parti- cular concern for superheaters/reheaters, where the presence of chloride species could reduce the melting points of deposits. In addition, the presence of chloride species in a deposit enables different corrosion mechan- isms to take place, which produce more rapid metal damage than the sulphate dominated ones traditionally found in coal fired boilers.5,7,8,10–12 Consideration of such issues provides guidance on the compositions of the specific biomass and coals that should be combined as fuels, and limits the range of fuel mixes that should be considered to minimise adverse fireside degradation issues. Oxyfiring Oxyfiring pulverised fuel power systems produce a flue gas stream dominated by CO2 and steam. 5,6,26–28 In these systems, it is necessary to recycle the flue gases to maintain the gas stream volume flowing through the boiler and heat exchanger close to that of conventional boiler experience. The steam can be readily removed from such flue gas streams by condensation, so this provides one route to producing a CO2 rich gas stream suitable for processing and disposal. There are actually many different possible variants on such oxyfired pulverised fuel systems, depending on factors, such as:5 (i) the source of the flue gases being recycled, e.g. before any gas clean-up, after particulate removal, after flue gas desulphurisation (FGD) (ii) what further gas clean-up, if any, is carried out before recycling, e.g. drying primary combustion air, but not the secondary or tertiary combustion air streams (iii) the purity of the oxygen produced by the air separation unit. A schematic flow diagram of this type of power system is given in Fig. 6. In this diagram, some of the possible alternative options for flue gas recycling are shown: positions 1 and 2 correspond to flue gases being recycled after the particle removal system and after the FGD system respectively. Recycled gas flows ‘a’ and ‘b’ go directly into the secondary and primary gas feed systems respectively, whereas recycled gas flow ‘c’ goes through a drying unit before joining the primary gas feed system. All these options produce different compositions of the recycled flue gases re-entering the combustion chamber with the oxygen and fuel feeds. Therefore, the composi- tion of the combusted gas stream produced varies with the flue gas recycling route along with the fuel composition and oxygen purity. For a particular fuel and given oxygen fraction, the highest levels of SOX and HCl are generated by recycling the flue gases after the particle removal system (but before the FGD system), giving levels of about 4–5 times higher than for the same fuel in conventional air fired systems. Figure 7 illustrates the different bulk gas compositions formed using either a UK coal or a South American coal while air firing and oxyfiring (with the hot flue gas recycled before the FGD system). From the point of view of fireside issues, another critical factor is the supply of other inorganic constitu- ents from the fuels. These will still form deposits on the heat exchanger surfaces, but notable differences com- pared to air fired systems arise from breaking the link between the fuel composition and the component operating environment (as a result of the flue gas recycle 6 Schematic flow diagram for oxyfired pulverised fuel power generation system 7 Potential composition of fully mixed gases in coal fired systems with air firing or oxyfuel firing (hot recycled flue gas option) Simms et al. Fireside issues in advanced power generation systems Materials Science and Technology 2013 VOL 29 NO 7 809 http://www.maneyonline.com/action/showImage?doi=10.1179/1743284712Y.0000000133&iName=master.img-005.png&w=227&h=171 http://www.maneyonline.com/action/showImage?doi=10.1179/1743284712Y.0000000133&iName=master.img-006.jpg&w=227&h=133 loop reusing only the gaseous species produced, and potentially altering the ratio between them depending on the recycle option). The combined effects of higher heat exchanger surface temperatures and different gas compositions for a given fuel composition are still being evaluated in terms of deposit formation (compositions, rates of formation, melting points, viscosities, effective- ness of soot blowing, etc) and heat exchanger corrosion through a series of continuing research programmes in the UK, EU and USA.25,27–29 Gasification systems Combined cycle power generation systems using solid fuels are still being actively developed in the USA, Japan, Australia and Europe.14 These systems offer many potential advantages over conventional coal fired power generation systems, including increased power generation efficiency and lower environmental emissions (specifically CO2, SOX, NOX and particulates). A wide variety of systems have been proposed based on different gasifica- tion and associated gas cleaning technologies to meet system and emission requirements.5,14,15 First generation IGCC demonstration systems explored many of these options: for example, wet scrubbing systems or hot dry gas filtration systems to clean the syngases produced.14 The environments produced in gasification systems are quite different from those generated in combustion systems and have been reviewed elsewhere.14,15 The fireside material degradation issues can be summarised as:15 (i) elevated temperature gas phase induced corro- sion: including oxidation, sulphidation, carbur- isation/metal dusting and chlorination (ii) corrosion induced by surface deposits: either particles from the gasifier, species condensed onto those particles or species condensed onto the component surfaces (iii) dewpoint/downtime corrosion: induced by high temperature deposits becoming ‘damp’ during plant idling/shutdowns and gaseous species (e.g. HCl, H2S, etc.) reacting with condensing water during idling (e.g. forming HCl and polythionic acids) (iv) interaction of any of the above degradation modes with mechanical factors, e.g. creep or fatigue, to produce synergistic degradation, e.g. creep–corrosion or corrosion–fatigue (v) spallation of corrosion products: important on the clean side of the filter unit from where spalled scale may enter the gas turbine causing erosion damage. Along the hot syngas paths of plants, the actual degradation mechanisms found are component specific (e.g. heat exchanger and hot gas filter) and vary between gasification systems and with fuels. Limited data have been published on the performance of materials in such IGCC systems.14 Advanced IGCC systems that are under development include processing for CO2 capture in hot gas paths and precombustion CO2 capture. 16 Figure 8 shows a schematic flow diagram of this type of gasification system; the water gas shift reactor, CO2 separation and CO2 compression stages are all part of the additional units needed to achieve this precombustion CO2 capture and prepare it for transportation. The effect of integrating CO2 capture systems in this way is that the resulting syngases will have much higher H2 contents than those produced by first generation IGCC systems. The use of high H2 syngases in gas turbines in these systems creates a range of issues relating to combustion, mass flow and heat transfer, as well as to the hot gas path materials (discussed further in the section on ‘Gas turbines’).16 Such IGCC systems using H2 enriched syngases are being actively investigated (e.g. EU research project H2-IGCC).16 Gas turbines To gain the benefits of increasing efficiencies, there has traditionally been a steady increase in gas turbine operating temperatures/pressures, with current models firing at temperatures of up to about 1400–1500uC and at pressures of up to y33 bar.14,21,30,31 Recent increases in gas operating temperatures have been facilitated using increasingly sophisticated blade cooling technologies, coupled with the use of thermal barrier coatings (TBCs), to restrict the component bulk operating temperatures to less than y950uC.30,31 At these temperatures, the hot gas path components need to withstand the surrounding environments and also operate with both high and fluctuating stresses. Thus, the oxidation and hot corro- sion performance of materials systems are important, as well as their creep and fatigue properties. The environments generated in industrial gas turbines can be both physically and chemically aggressive, with particles producing erosion or deposition, while gaseous and vapour phase species produce different forms of deposition, in addition to oxidation and hot corrosion. As gas turbines have been developed, the potential environ- mental degradation issues that may be encountered with conventional fuels have been well characterised.14,20,30,32 The oxidation rates of state of the art gas turbine materials are sufficiently low below y900uC so as not to be life limiting. Hot corrosion mechanisms can occur much more rapidly and are potentially life limiting, but require a liquid (often sulphate) deposit on the surface of the components. The formation of this deposit depends on the level of trace metal species (e.g. alkali metal compounds) in the gas streams and on the levels of other reactive gas species (e.g. SO2, SO3, HCl). The extent of hot corrosion damage depends on factors such as the rate of deposit formation, deposit composition, local gas composition, metal temperature and exposure time. To date, two general types of hot corrosion have been identified in gas turbine environments: type I hot corrosion at about 750–900uC and type II hot corrosion at about 600–800uC.14,20,30,32 Both of these forms of damage include incubation and propagation stages, with the sensitivity of each varying with exposure conditions and materials (base alloy or coating). 8 Integrated gasification combined cycle system includ- ing precombustion CO2 removal Simms et al. Fireside issues in advanced power generation systems 810 Materials Science and Technology 2013 VOL 29 NO 7 http://www.maneyonline.com/action/showImage?doi=10.1179/1743284712Y.0000000133&iName=master.img-007.png&w=227&h=103 As gas turbines are required to run on a wider range of fuel gases, with increasing levels of contaminants, it is likely that there will be more potential to generate hot corrosion damage. Compared to natural gas fired systems, similar types of material degradation can be expected in gas turbines using syngases (e.g. gases produced by the gasification of solid fuels), as many of the contaminants are the same, in particular sulphur, chlorine and alkali metals (i.e. Na and K). However, other contaminant species can also be found in these gases, such as calcium, magnesium, aluminium, silicon and iron, as well as trace metals (e.g. Pb and Zn). The levels of these contaminants differ significantly, depend- ing on the fuel composition, gasification process and gas cleaning systems used.30 Thus, a range of fireside issues are being identified as potentially life limiting for gas turbines in new power generating systems: (i) corrosion damage below blade platforms and/or on disc rims as a result of the deposition of species entering via the cooling air and reacting due to increased component temperatures (ii) corrosion of TBC surfaces due to the deposition of CMASzFe (generally mixed oxides of calcium, magnesium, aluminium, silicon and iron) that can react at temperatures close to their melting points (iii) types I and II hot corrosion reactions being accelerated using much higher SOX levels than traditionally used (from dirtier/cheaper fuels) and/or higher trace metal contaminant levels (iv) corrosion of internal blade cooling passages as a result of contaminants in the cooling air (v) effects of novel environments: e.g. traditional gas turbine degradation issues combined with high steam levels from firing H2 rich syngases (Fig. 8) or high CO2/steam mixtures from oxyfiring of natural gas (Fig. 9)16,33 (vi) erosion of coated surfaces from particles entrained in the gas streams (vii) thermal cycling of all parts as a result of gas turbines having to be frequently switched on/off in response to intermittent renewable resources.30 Table 4 illustrates the range of protective MCrAlY coatings currently used by the major suppliers of industrial gas turbines. These different coatings have been selected to resist the service environments antici- pated by the gas turbine manufacturer. Currently, there is no single commercial overlay coating that can offer resistance to all the issues listed above.31 Alternative protective coatings can be manufactured using diffusion processes and include variations on aluminising and modified aluminising (e.g. Pt–Al, Sermaloy 1515).31 Thermal barrier coatings can be applied using atmo- spheric pressure plasma spraying or electron beam physical vapour deposition processes on top of various bond coatings (overlay or diffusion coatings). The industry standard composition for TBCs is currently 8 wt-% yttria partially stabilised zirconia.31 There are active research programmes investigating materials selection or operational solutions to the issues outlined above. For example, developing new TBC systems (often multilayered) to resist CMAS/Fe induced mechanisms and functionally graded metallic coatings to resist multiple degradation mechanisms.31,35 Conclusions The need to reduce CO2 emissions from power genera- tion systems coupled with the need to increase the quantity of electricity supplied are driving the develop- ment of new power generating systems. Significant gains in efficiency for pulverised fuel power systems can be made by increasing the steam temperatures and pres- sures. In addition, CO2 emissions can be effectively (and most efficiently) reduced by co-firing biomass and waste products (classified as CO2 neutral) with coal. For CO2 removal systems, oxyfiring of fuels is a promising technology for facilitating the post-combustion capture of CO2. In contrast, gasification of solid fuels produces a syngas that can be conditioned to enable precombustion CO2 removal, with the resulting H2 enriched syngas being burnt in a gas turbine. There are numerous potential combinations of new fuels, novel technologies and higher temperature compo- nent operating conditions in these new power generation systems. As a result of the deposition, corrosion and erosion processes that can occur in these new operating conditions, these issues need to be thoroughly investi- gated for critical components (such as heat exchangers, gas cleaning systems and gas turbines) to identify potential life limiting conditions. A thorough knowledge of these processes and the responses of current material systems will facilitate material selection and maintenance scheduling, reduce the risk of unexpected component failures and identify conditions that require the develop- ment of new materials or coating systems. Acknowledgements The present paper is an augmented version of a presentation made at the 8th International Charles 9 Schematic diagram of natural gas fired zero emission power plant (GAS-ZEP)33 Table 4 Nominal composition of some current MCrAlY overlay coatings used by industrial gas turbine manufacturers31,34/wt-% OEM Coating Ni Co Cr Al Y Ta Si Re Alstom SV20 Bal. 25 5.5 0.6 1.0 2.7 GE GT29 Bal. 29 6.0 0.5 GT33 Bal. 37 22 9.0 0.5 Siemens- Westinghouse CoNiCrAlY 32 Bal. 21 8.0 0.5 Siemens SC2231 30 31 30 8.0 0.6 SC2453 52 10 23 12.0 0.6 0.7 3.0 MHI CoNiCrAlY 32 Bal. 21 8.0 0.5 Simms et al. Fireside issues in advanced power generation systems Materials Science and Technology 2013 VOL 29 NO 7 811 http://www.maneyonline.com/action/showImage?doi=10.1179/1743284712Y.0000000133&iName=master.img-008.jpg&w=227&h=142 Parsons Turbine Conference, organised by the Institute of Materials, Minerals and Mining at Portsmouth, UK, on 5–8 September 2011. 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