REVIEW OF STATUS OFADVANCED MATERIALS FOR

POWER GENERATION

Report No. COAL R224DTI/Pub URN 02/1509

by

J E Oakey, Cranfield UniversityL W Pinder, Powergen UK UK plc

R Vanstone and M Henderson, ALSTOM PowerS Osgerby, National Physical Laboratory

The work described in this report was carried out under contract as part of the Department ofTrade and Industry’s Cleaner Coal Technology Transfer Programme. The Programme ismanaged by Future Energy Solutions. The views and judgements expressed in this report arethose of the Contractor and do not necessarily reflect those of Future Energy Solutions or theDepartment of Trade and Industry.

Crown Copyright 2003First published February 2003

REVIEW OF STATUS OF ADVANCED MATERIALSFOR POWER GENERATION

J E Oakeya, L W Pinderb, R Vanstonec, M Hendersonc and S Osgerbyd

SUMMARY

The construction of economically viable and durable power plant components is dependent onthe selection of the most appropriate materials and fabrication methods. The implementation ofadvanced materials in power generation applications has resulted in significant advances inplant performance and hence emissions reductions.

Advanced materials are now being deployed in new and existing power plant to improveoperating performance and reliability, availability, maintainability and operability. Thesematerials, from ferritic alloys for boilers to ceramics for filter elements or coatings for theprotection of gas turbine blades, are the result of extensive research programmes. In somecases, it can take over ten years to take a new material concept from initial trials toimplementation, supported by the necessary long term mechanical and environmentalperformance data.

This review addresses advanced materials and their applications in current and future coalpower technologies relevant to the UK and UK industry exports. All the key powertechnologies are covered from supercritical pulverised coal boilers, through steam turbines andgasifiers to gas turbines and advanced cycles involving fuel cells and CO2 management.

From the review, the R&D priorities for the UK can be divided into three overarching clusters:-

• high temperature materials for boilers, steam turbines, gas turbines, gasifiers, hightemperature heat exchangers, as well as functional materials such as sorbents, catalystsand membranes

• protective systems/coatings for the same technology areas as high temperature materials,and

• modelling of materials processing, component manufacture and life assessment.

The review concludes that materials technologies are critical to achieving significantimprovements in power plant efficiency. If ignored, they represent a major cost factor and a keyconstraint that will limit both:

• the implementation of new generation technologies and;• the adaptation of power plant technologies to new fuels,

thereby reducing opportunities for improved environmental performance.

Materials research is a major part of any initiative to produce cleaner/cheaper energy systems.Innovative materials – from concept to implementation – can take decades to develop. UKmaterials programmes must, therefore, have the foresight and resources to pursue the necessarytechnology through to practical ‘demonstrator’ outcomes.

As a result, this review recommends that an integrated long term materials R&D coreprogramme is needed for power generation covering three key elements - high temperaturematerials, protective systems and modelling. A long term view is essential. Low risk, near termdevelopment will not deliver the necessary benefits.

a Cranfield University, b Powergen, c ALSTOM Power, d NPL

TABLE OF CONTENTS

SUMMARY Pages

21. INTRODUCTION............................................................................................................................... 1

1.1 Background ........................................................................................................ 11.2 Aims and Objectives of the Review....................................................................... 2

2. IDENTIFICATION OF PLANT OPTIONS .................................................................................... 43. MATERIALS REVIEWS .............................................................................................................. 6

3.1 Boilers and Related Technologies .................................................................... 63.1.1 Combustion Systems ........................................................................................................... 63.1.2 Pressure Part Design........................................................................................................... 83.1.3 Operating Environments and Failure Modes: PF-fired Plant ...................................... 113.1.4 Operating Environments and Failure Modes: FBC Plant ............................................ 163.1.5 Flue Gas Desulphurisation ............................................................................................... 213.1.6 Component Integrity and Life Assessment..................................................................... 213.1.7 State of the Art PF-fired Boilers ...................................................................................... 213.1.8 State of the Art FBC ......................................................................................................... 273.1.9 Future R&D Priorities ...................................................................................................... 27

3.2 Steam Turbines ................................................................................................ 483.2.1 Steam Turbine Market Trends ........................................................................................ 483.2.2 Steam Turbine Development Trends .............................................................................. 483.2.3 Steam Turbine Design and Operation............................................................................. 493.2.4 Steam Turbine Materials – State of the Art ................................................................... 503.2.5 Steam Turbine Materials R&D........................................................................................ 523.2.6 Future R&D Priorities ...................................................................................................... 54

3.3 Gasification Systems........................................................................................ 603.3.1 Gasification and Gas Coolers ........................................................................................... 603.3.2 Gas Cleaning Systems ....................................................................................................... 64

3.4 Gas Turbines .................................................................................................... 753.4.1 Gas Turbine Market Trends ............................................................................................ 753.4.2 Gas Turbine Design, Operation and Materials ............................................................. 773.4.3 Review of UK Opportunities ............................................................................................ 883.4.4 Future R&D Priorities ...................................................................................................... 90

3.5 Associated Technologies ..................................................................................... 993.5.1 Introduction ....................................................................................................................... 993.5.2 Fuel Cells............................................................................................................................ 993.5.3 High Temperature Heat Exchangers .............................................................................. 993.5.4 CO2 Capture Technology ............................................................................................... 101

4. REVIEW OF UK OPPORTUNITIES .......................................................................................... 1055. FUTURE R&D AND TECHNOLOGY TRANSFER .................................................................. 1076. CONCLUSIONS ............................................................................................................................. 1087. RECOMMENDATIONS ................................................................................................................ 1088. ACKNOWLEDGEMENTS............................................................................................................ 108

ANNEX A......................................................................................................................................1Literature review..........................................................................................................................1A.1 Introduction ..................................................................................................................................... 1A.2 Low Alloy (1-3% Cr) Steels............................................................................................................ 1A.3 9-12% Cr Martensitic Steels .......................................................................................................... 3A.4 Austenitic Steels............................................................................................................................... 6A.5 Ni- and Co-based alloys .................................................................................................................. 7A.6 Intermetallics ................................................................................................................................. 12A.7 Oxide Dispersed Strengthened (ODS) Alloys ............................................................................. 13A.8 Ceramics......................................................................................................................................... 15A.9 Fuel Cell Materials ........................................................................................................................ 17A.10 Corrosion Resistant Coatings................................................................................................... 18A.11 Thermal Barrier Coatings (TBCs).................................................................................................. 24A.12 Erosion Resistant Coatings.............................................................................................................. 25A.13 References .................................................................................................................................. 27

ANNEX B ................................................................................................................................................... 11Listing of organisations involved in the preparation of the review .......................................11

1 of 108

1. INTRODUCTION

1.1 Background

The major challenges facing the Power Generation Industry in the 21st Century are focusedprimarily on achieving the difficult targets of increased efficiencies, increased reliability andstringent environmental standards. The challenge for coal, in particular, is to develop new, andevolve existing clean technologies, in order to achieve these goals.

One of the core activities essential to the attainment of these future requirements is that ofMaterials Technology. Many of the required enhancements in plant performance are restrictedby materials limitations and for this reason, a coherent and co-ordinated strategy outlining thefuture requirements for Materials R & D is essential.

There are many activities currently ongoing worldwide relating to the Materials R & Drequirements for the Power Generation Plant of the future. Recent publications from theInstitute of Materials1 and the European Commission have addressed in part some of the keyissues. The activities of collaborative programmes such as COST 501/5222 and FrameworkIV/V Joule/Thermie or Brite/Euram also include many materials programmes related to futuregeneration requirements.

Within the UK Foresight Programme, the Energy and Natural Environment Panel is continuingthe work of the previous Energy Panel, which prepared reviews on Clean Coal3 and GasTurbine4 Energy Technologies. These reviews highlighted Materials R & D as one of the keydevelopment areas for future advanced power plant. They also recognised that the long leadtimes required from material development to implementation in service, and the dependence ofthe UK on overseas suppliers, means that a well defined co-ordinated strategy is required in thevery near future to retain our competitiveness into the 21st Century.

An industry-led grouping, the Advanced Power Generation Task Force (APGTF)(recentlyrenamed as the Advanced Power Generation Technology Forum), was formed in 1998 as aForesight Associate Programme, to take a sector-wide view of the issues facing the powergeneration industry in the UK and overseas5. The review, presented in this report, has beenprepared by the Materials Technical Group, which provides advice on materials issues to theAPGTF. The Materials Group is based on the former Institute of Materials Task Force onPower Generation which produced an overview report on the UK’s activities in materials for thepower generation sector in 19971. The Group represents the complete power generation supplychain from materials manufacturers through to electricity producers.

ALSTOM Power – Gas Turbine and Steam Turbine Chromalloy UKCorus Group Cranfield University HowmetInnogy Institute of Materials (IOM) Mitsui Babcock Energy LtdNPL PowerGen Siemens Power Generation UKSpecial Metals Wiggin

The above organisations are involved on a day to day basis in materials issues relevant to allaspects of current and future power generation plant. This involves short-term problem solving(failure investigations), through plant integrity and remnant life assessments, to R&D on newmaterials and coatings to withstand the ever more onerous duties expected of power plantcomponents. In addition, the organisations are major participants in all recent/currentUK/European research projects of relevance to the review, for example:-

2 of 108

• Clean Coal Power Generation Group (CCPGG) for the development of Air BlownGasification Cycle,

• COST 522 European Collaborative Programme on Power Generation in the 21st Century:Ultra-Efficient Low-Emission Plant,

• THERMIE Advanced 700°C Ultra-supercritical Power Plant Project, and

• Practical Improvements in Power Plant Efficiency through Materials Engineering (PIPPE).

A core team from the Materials Technical Group, comprising Cranfield University, ALSTOMPower, Powergen and NPL (with assistance from the Institute of Materials) will undertake thereview, with active input from all the other APGTF Materials Technical Group members.Figure 1 illustrates the many sources of information and advice available to the team.

For the purpose of this review, the term 'Advanced Materials' relates to materials or materialssystems (e.g. combined alloys with coatings), which are being used today to improve theefficiency and reduce the environmental impact of power plants. These materials may be newlydeveloped and suited to new plant design or retrofit applications to extend component lives orbroaden a plant's operating envelope. Alternatively, they may be traditional materials in a newapplication for which little relevant performance data exist (e.g. the use of Ni alloys (developedfor aerospace applications) in steam turbines). So the term 'advanced', relates to the applicationas much as to the materials themselves, which for power generating equipment have beendeveloped in an evolutionary way over past decades. An example of an advanced applicationwould be the effects of advanced process or engineering concepts on the materials selected onthe basis of current best practice (e.g. steam cooling of gas turbine blading).

1.2 Aims and Objectives of the Review

The principal aims of the review were to assess the current ‘global’ state of development ofadvanced materials for coal-based power generation and to identify and prioritise areas wherefurther UK R&D and technology transfer activities need to be focused to enhance the marketpotential for UK materials products and services. The specific objectives were:

• to assess the global ‘state-of-the-art’ and application of advanced materials in coal-basedpower generation systems

• to identify opportunities for UK developers, suppliers and service providers, taking intoaccount current and future market influences

• to critically review current activities and capabilities of UK organisations and to identifypriority areas in which future R,D&D activities need to be focused, to meet current andfuture demands and to enhance the market potential for UK products and services.

The publication of the Review is expected to provide for:

• clearly directed areas of materials R & D in industry and academic/researchestablishments through DTI, EPSRC and similar initiatives.

• focused goals for alloy producers and processors to achieve the required material propertytargets, size, shape and fabricability requirements.

• utilisation of the above by the component and plant manufacturers to achieve therequirements of service conditions in terms of operating temperatures, environments and

3 of 108

stresses.• attainment of target efficiencies and emissions by the plant operators.• ensuring competitiveness of UK manufacturers products in the worldwide market.• spin-off advantages for non-coal-fired power generation plant.

References for Section 1

1. Institute of Materials Task Force Report, ‘Materials R & D Requirements for Power Plant:Into the 21st Century’, 1997.

2. J E Oakey, D H Allen and M Staubli, ‘Power Generation in the 21st Century – The NewEuropean COST Action’, Proc. 5th Int. Charles Parsons Conf: Parsons 2000 AdvancedMaterials for 21st Century Turbine and Power Plants. Edited by A. Strang, R. D. Conroy, G.M. McColvin, C. Neal and S. Simpson. IOM Communications, London, Book 736 (2000).

3. Foresight Research, Development and Demonstration Priorities for Cleaner Coal PowerGeneration Technology, DTI - OST, May 1999.

4. Foresight Research, Development and Demonstration Priorities for Gas Turbine andAdvanced Combined Cycle Technology, DTI - OST, November 1999.

5. Advanced Power Generation Task Force, Annual Report 1999/2000.

4 of 108

2. IDENTIFICATION OF PLANT OPTIONS

Before reviewing the status of advanced materials in coal-based power systems, it is necessaryto identify the range of systems to be considered.

There are several new initiatives that are currently ongoing which are looking at the strategic Rand D requirements for global power generation over the next 20-30 years. Examples of theseare: UK’s current Foresight initiative; EC’s Framework 6 consultations; USA’s Vision 21;Japan’s New Sunshine programme.

The APGTF issued a UK technology strategy out to 2030 in September 20011 to assist theidentification of those power plant technologies worthy of UK development for home or exportapplications. This strategy focused on the research and development needs for fossil-fuelledpower generation and associated technologies, including those for waste and biomass. Most future, global predictions2,3 still see the large, central power station as being dominant fornew build over the next 10-15 years. The dominant technology for new coal plant is likely toremain as pulverised fuel (pf). For gas turbines (GTs), large plant will continue to dominate butthere will be a growing market for the micro, small and mid-size GTs. Gradual growth ofDistributed Generation (DG) is expected to continue and up to 20% of generation in EU couldbe from Distributed Generation by 2020. The major impact of renewables on the electricity market is not expected to be felt until after2020. So, there is expected to be a continued drive for higher efficiency in fossil-fuelled plantwhich could act against the large central power station for some applications in the future and infavour of distributed generation, which may achieve higher efficiencies through combined heatand power applications. For fossil-fuel technologies, CO2 capture and sequestration is a future possibility. According toa recent US Department of Energy report4, ‘Scientific experts are optimistic that (large scale)CO2 capture and sequestration could be implemented on a scale that would mitigate climatechange ... and if successfully developed could allow the continued use of fossil fuels in thepresence of carbon emission constraints’. However, this is unlikely to be cheap; currentestimates by the US Department of Energy are that it will add up to 50% on the electricity priceto the consumer and this would still leave the problem of CO2 disposal. A more recentpublication from the IEA5 gives estimates of the cost of capture as 50-70% of the cost ofgeneration, depending on the technology. However, despite its expense, some utilities arecarrying out studies on how to implement CO2 capture and sequestration on some existing coalplants. If greenhouse gas trading or a system of credits comes into force in the future, then thiscould provide an extra incentive for CO2 capture or reduction technologies; it could also providean additional strong impetus for the development of higher efficiency power generationtechnologies.

In order to be competitive with the US and Japan out to 2030, then a UK/EC R and Dprogramme must have a set of comparable targets. The scenarios presented in the APGTFStrategy suggest that post 2020, new power plant will need to have very low emissions as wellas being commercially cost effective. The following would be required by 2030:

• efficiencies (in electricity) > 60% on coal> 70-75% on gas

• thermal efficiencies > 85-90%• near zero pollutant emissions• cost-effective management of CO2 emissions• cost-effective hydrogen technologies.

5 of 108

Other plant performance parameters such as reliability, availability and maintainability will alsoneed to be better than present values. This puts a strong emphasis on the materials used forsystem components.

Future plant options for the period up to 2030 must be based on those technologies which areeither fully developed or close to market today. Therefore, the APGTF strategy identifies thefollowing plant technologies as significant for the timescales considered and can use coal as afuel (or be involved in a coal-based system):

• Pulverised Fuel (PF) Combustion.• Gasification – air and oxygen-blown• Fluidised Bed Combustion• Pressurised PF or Fluidised Bed Combustion• Fuel Cells• Gas Turbines

Following on from this listing of the main plant technologies the Strategy identifies thefollowing key technologies:

• Hybrid or novel cycles• Co-fuelling with biomass• Hot gas clean-up• Fuel flexible gasification• Combustion• High temperature heat exchangers• Reformers and fuel cell fuelling• Fuel cell electrochemical processes• Membranes• Plant manufacture• Component integrity• CO2 Management• Plant Modelling• Control Systems.• Power Electronics

(Hydrogen Storage and Production if Hydrogen Fuelled is included)

All of the above have materials implications to greater or lesser extents; those highlighted initalics have been identified as priority technologies for this review. It should be noted that CO2

management is included as it can have important impacts on the selection, operation andperformance of the main plant technologies in the medium to long term and may changesignificantly the operating environments of the materials used.

References for Section 2

1. The Transition to Zero Carbon Emissions, a Technology Strategy for Power Generationfrom Fossil Fuel and Associated Technologies, 2001, APGTF.

2. World Energy Outlook, 1998, International Energy Agency.3. European Union Energy Outlook to 2020, 1999, European Communities.4. Carbon Management: Assessment of Fundamental Research Needs, 1997, US Department

of Energy.5. Carbon Dioxide Capture and Storage, 2000, IEA/DTI.

6 of 108

3. MATERIALS REVIEWS

The status of materials technologies etc. given in this section is divided into four parts. The firstdeals with boilers and related technologies, the second with steam turbines, the third with gasturbines and finally the fourth associated and new technologies, which also deals with thepossible effects of the introduction of CO2 capture.

3.1 Boilers and Related Technologies

3.1.1 Combustion Systems

Pulverised Fuel Combustion

Pulverised fuel (PF) has been the mainstay of coal-based electricity generation in the developedworld for many decades. Sub-critical cycles, where the boiler and turbine operate below thesteam/water critical pressure, represent the dominant technology to date. Over the years, there hasbeen a progressive increase in the size, operating temperature and pressure of this plant, leading toincreased thermal efficiency and a concomitant reduction in fuel costs. The constant drive toreduce fuel costs led to the development of super-critical designs (where the pressure exceeds thesteam/water critical pressure) in the 1950s and 1960s. However, technical difficulties, largelyrelated to the use of thick section austenitic steel components, led to unreliable plant with pooroperational flexibility. Consequently, for plant built throughout the 1970s and 1980s, the steamtemperatures have been limited to the 540-566°C range.

With increasing pressures on fuel costs, now being reinforced by ever more urgent environmentalimperatives to reduce SO2, NOx and CO2 emissions, the energy industry has increasingly returnedits attention to the development of super-critical steam cycles. Consequently, there has been aclear trend towards increasing steam temperatures and pressures in plant being designed and builtthroughout the 1990s. The potential improvement in heat rate achieved by increasing steamtemperature and pressure in single and double reheat cycles from a base case of 535°C/18.5MPa isshown in Figure 3.1.11.

The higher steam parameters operative in advanced supercritical boilers necessitate highercomponent operating temperatures and stresses. A number of plant design and operationalprocedures, advocated by the boiler manufacturers, can reduce the impact of these conditions onpressure parts. However, the continuing upward trend towards progressively higher thermalefficiencies has identified that better materials will be required in a number of critical componentsif reliable and flexible plant operation is to be achieved. The contribution that some materials andother cycle developments can make to improvements in thermal efficiency, according to dataprovided by Siemens, are shown in Figure 3.1.2. These improvements are very significant in termsof the near future requirements to reduce worldwide CO2 emissions, since it is estimated that a 1%improvement in efficiency would result in a reduction of around 1M tonnes of CO2 emissionsduring the lifetime of an 800MW machine2.

ELSAM have conducted study projects into IGCC, PFBC and USC plant for the construction ofpower generating plant in the range of 300-400MW. For the present and near future, they considerthat USC offers the highest efficiency coupled with the cheapest investment3. Limits to thedevelopment of USC boiler plant are seen to be:

• the creep properties and weldability of low alloy steam generating tubes,

• the weldability, creep and thermal fatigue properties of materials for thick section steamseparators, headers and steam pipes and,

7 of 108

• the creep, fireside and steamside corrosion properties of superheater materials.

Fluidised Bed Combustion

Fluidised bed combustion is a relatively young technology but is being used in most areas of theworld to generate electrical power, provide district or process heating and combust industrial andmunicipal waste. Its particular advantages in relation to many other forms of fuel firing are:

• Ability to utilise a wide variety of fuels, including solids, liquids and gases, and fuels witha high fraction of inert ash or water.

• Sulphur originating from the fuel can be captured in the combustor bed by means of asorbent, usually limestone or dolomite.

• Generation of the regulated nitrogen oxides (NOx - NO and NO2) is inherently lower than,for example, pulverised fuel (PF) firing due to the low combustion temperature.Additionally, the NOx emissions can be reduced, by at least 80%, by the relatively simplemeasure of introducing ammonia at the combustor outlet.

A disadvantage of FBC systems compared to PF plant with wet limestone/gypsum flue gasdesulphurisation (FGD) is the lower utilisation of the limestone. Hence, the FBC will produce agreater amount of solids waste, by about 10 to 30% based on a typical coal, due to the presence ofunused and partially reacted sorbent.

Combustor systems take two general forms: bubbling and circulating beds. Bubbling beds occupythe lower part of a combustor vessel and have a distinct bed surface. They are fluidised at gasvelocities, which give rise to upward flowing streams of bubbles which promote mixing. Incirculating beds, fluidisation velocities are greater. Most of the bed material is entrained in the gasstream and passes through the full height of the combustor, to be separated out by a cyclone andreturned to the bed vessel, either directly or via external fluidised bed heat exchangers. Both formsof FBC can operate at atmospheric pressure or pressurised conditions. With atmospheric systems,the combustor represents an alternative to other forms of boiler, with steam raised in thecombustor walls, convective back-pass and in some cases, in-bed tube banks or external heatexchangers, being used to drive a conventional steam turbine plant or supply heat.

Pressurised FBC typically forms part of a combined cycle, with the hot, pressurised gas from thecombustor driving a gas turbine and generating power, which supplements that produced in asteam plant. In all variants of FBC, the bed is made up of a large mass of hot inert particles (fuelash, spent sorbent etc) and the amount of solid fuel particles present in the bed is small, typicallyof the order of 1%.

Atmospheric Fluidised Bed Boilers

In atmospheric pressure plant, circulating bed combustors (CFBCs) have largely supersededbubbling beds due to a much longer contact time between the solid particles and the gas stream.This increases the efficiency of sulphur capture and improves carbon burnout. The fuel flexibilityof CFBC units is particularly wide and has allowed the utilisation of materials, such as miningwastes and sewage sludges, which before the advent of FBC technology would not have beenconsidered to be fuels at all. Additional advantages of CFBC over bubbling beds are that NOx

emissions can be reduced (by means of air staging), less fuel feed points are required and loadfollowing is simpler.

The increase in scale of CFBC plant from much smaller units, 50MWe or less, has occurred in thelast ten or so years. Consequently, operating experience at the larger scale is restricted and

8 of 108

materials and operational problems are still being resolved. All operating plant use sub-criticalsteam conditions, in many cases not very advanced, though super-critical units are in-design.

The thermal efficiency of an optimised CFBC boiler should be the same as a PF boiler. However,greater air fan power requirement may lead to a unit efficiency about 0.4% points less than PFwith FGD at the same steam conditions. Typically, operating plants remove 90-95% of the fuelsulphur. NOx emissions, without any NOx reduction technology, are generally three to seven timessmaller than the emissions from PF boilers in the UK fitted with low-NOx burners.

Pressurised Fluidised Bed Systems

Pressurising a fluidised bed results in a large reduction in combustor size: thus, for example, theamount of machined steel used in current PFBC units is about one-quarter to one-half of thatrequired for PF or atmospheric CFBC plant.

The ABB Carbon PFBC uses a bubbling bed combustor with, typically, two stages of cyclone toremove most of the entrained particles from the combustor exhaust gas before it is admitted to a'ruggedised' gas turbine. The gas turbine generator provides about 20% of the total plant output,the remainder coming from a steam turbine. Steam is raised by means of tube bundles submergedin the bed, by membrane-tube combustor walls and an economiser section in the gas turbineexhaust.

Gaseous emissions are similar to atmospheric plant but sorbent utilisation is better. The ABB unitshave achieved sulphur capture efficiencies of 90-99%. NOx emissions at low load increasesubstantially due to increase in excess air. As with atmospheric units, the NOx emissions can besignificantly reduced by injection of ammonia at combustor outlet, although at low load this needsto be combined with firing a small amount of additional fuel into the bed freeboard to maintaineffectiveness. The ABB combustor design appears tolerant of coal quality, an inherent advantageof all the FBC technologies.

PFBC systems based on circulating beds are being developed. Due to the high dust burden of thegas stream, these units will have a ceramic filter as the last stage of particle removal. While thisallows the use of fairly standard un-ruggedised gas turbines, the filter represents a major technicalrisk at the proposed operating temperature of about 850°C. Circulating bed systems are expectedto show advantages over bubbling beds in the same areas as atmospheric plant (e.g. sorbentutilisation and low load operation) but the benefits may not be so extensive. One reason for this isthat the contact time between solids and gas in pressurised bubbling beds can be made muchlonger than that for the atmospheric equivalent.

3.1.2 Pressure Part Design

Metal Temperatures

For design purposes it is necessary to know the mid-wall temperature of boiler tubes, pipes andheaders.

For boiler tubes, the difference in temperature between the furnace gases on the outside of the tubeand the water or steam flowing within the tube is determined by the summation of a number oftemperature gradients through various components, as shown in Figure 3.1.3. In order tocommence a metal temperature calculation it is necessary to determine the heat flux falling on thetube and the steam or water temperature within the tube. In most calculational methods, theinternal surface of the tube is assumed to be clean. Typically, an iterative calculation is used todetermine the inside wall temperature and this is then used, along with a knowledge of wall

9 of 108

thickness and the thermal conductivity of the chosen tube material to determine the mid walltemperature.

For thick walled components such as headers and steam pipes, there is no significant heat fluxfalling on the outside of the component. Hence, mid wall metal temperatures are typically takento be around 5°C above the temperature of steam delivered to the turbine. However,significantly higher metal temperatures could develop under ‘upset’ conditions, such as duringstarts, and these have to be accounted for in the design.

Codes

The design, manufacture and quality of pressure parts for boilers in the UK has typically been inaccordance with BS1113, which in turn refers to other British Standards for specific requirements.Similar design codes have been used in other countries according to their needs. Hence, examplesof Design Codes historically applied in Europe include TRD (Germany), AFNOR (France) andStoonwezen (Holland). A draft European code, bringing together the requirements of the differentmember states, is currently awaited. Japan (JIS) and America (ASME) currently have their ownCodes. The American ASME Codes tend also to be favoured in Asia.

The purpose of the Design Codes is to apply appropriate materials parameters and design methodsto produce an economical, safe and reliable system for the required duty. They have generallydeveloped by taking into account past experience of type and quality of construction, ranges ofoperating conditions and applied loadings, variability in materials properties and possible modesof failure. Therefore, the design methods have been derived, and the allowable design stresslimitations have been specified and modified as necessary, over many years.

Materials’ Properties

A table of allowable design stresses, for a number of approved materials, operating over a range oftemperatures, is given in BS1113. The allowable design stresses are related to temperature in theproof range and both temperature and time in the creep rupture range as follows.

Design StressMaterial

Proof Range Creep Rupture

carbon manganese and low alloy steels5.1

ReT

3.1

SRt

austenitic steels35.1

ReT

3.1

SRt

Where:

ReT = the minimum 0.2% proof stress for carbon, carbon manganese and low alloysteels or the 0.1% proof stress for austenitic steels.

SRt = the mean value of the stress to produce rupture in time t.

Figure 3.1.4 shows the 0.2% proof stress and creep rupture stress for 100,000 hours as a functionof operating temperature for a plain carbon boiler steel and the corresponding allowable stressesfor design. Hence, it is clear that the allowable design stresses effectively incorporate a safetyfactor to accommodate for, e.g. reduction in strength due to welding, variability in materials

10 of 108

properties, etc. Below the crossover point in the curve, the design stress is considered to beindependent of time, although creep can still occur to a limited extent and may lead to failures inparticularly highly stressed components at, for instance, structural discontinuities. Code scantlingcalculation allows stresses to be greater than design at such discontinuities with, for instance, astress concentration factor of up to 2.25 being allowed for at branch openings to drums or headers.No allowances are included for thermal stresses, weld residual stresses or stresses induced duringboiler erection.All pressure parts operating at temperatures above the crossover point are subjected to creepdeformation and likely to fail in creep rupture. Consequently, all such components are designedfor a specified minimum life. The life will be dependent upon the creep stress to produce creeprupture failure within a given time at a given temperature. Data is usually gathered from long-termcreep rupture tests in the laboratory and all such data typically show scatter of around ±20% aboutthe mean. Hence, the factor of 1.3 used to derive the design stress from mean creep rupture dataallows a small safety margin on minimum data.

Component Dimensions

Rules and design equations are given in the codes to calculate the required thicknesses of pressureparts within the boiler, including drums, headers, tubes and pipes. For plain, thick walled,cylindrical components such as boiler tubes, the principle life limiting stress is normally given bythe hoop stress:

Pf2

PDt

+=

where:

t = wall thicknessP = internal pressureD = outside diameter, andf = allowable hoop stress.

For headers and drums, a ligament efficiency (η) term is included in the above equation to takeaccount of the tube penetrations through the wall as:

Pf2

PDt

+η=

Various formulae for η are given in the design codes for different layouts and sizes of the tubepenetrations. Further rules are given to account for additional stresses due to, e.g., self weight andweight of contents, whilst local loads at supports are given in BS5500. The methods forcalculating additional loads due to thermal expansion and construction mismatch are covered inBS806.

Manufacture and Assembly

As well as considering the materials used, BS1113 describes the methods of fabrication,manufacturing tolerances, welding, stress relief and pre- and post-welding heat treatmentrequirements. Limits are placed on the acceptable levels of wall thinning and ovality which arisefrom tube and pipe bending. Special attention is drawn to austenitic to ferritic transition joints,which are always made under workshop conditions and located at butt welds clear of geometricaldiscontinuities.

11 of 108

Modern power stations use a range of materials from carbon steel through to highly alloyedaustenitic stainless steels. Component sizes range from a few mm to over 100mm. A number ofwelding processes is available and required to cover this range of materials and sizes. The currentroute for approval of weld procedures requires the manufacturer to demonstrate that the chosenprocedure is technically correct and that sound welds can be produced to the acceptance standard.Further, welder qualification tests are carried out to show that the welder is competent to carry outthe weld procedure. These are generally contractual requirements during power plant constructionand repair, but must satisfy the statutory approval process carried out by the inspecting andinsurance authorities.

Inspection and Testing

Inspection during construction is required to ensure that materials, design, construction and testingcomplies with the standard codes. This is normally carried out by an Inspecting Authority who isappointed by the insurers. The inspection will also include approval of welding procedures,inspection of weld approval tests and welder's certificates. Hydraulic testing is carried out todemonstrate the strength and integrity of individual components and the completed boiler.

3.1.3 Operating Environments and Failure Modes: PF-fired Plant

Steam Generating Walls

Furnace Wall Corrosion

Furnace wall corrosion has been a well-established and reported phenomenon since the 1940's.It has been responsible for numerous forced outages in most UK coal-fired plant, incurringconsiderable costs; not least those associated with lost generation. Numerous examples of plantsuffering from furnace wall corrosion have also been found throughout the world4. Enhancedwastage is generally found on the radiant face of the furnace wall tubes, over localised sectionsof the furnace wall, up to 3m in height and extending typically over 60 tubes wide. The wastagepatterns are highly dependent upon the firing configuration. For front wall fired boilers, wastagetypically occurs on the side or rear walls, although simultaneous attack can occur in bothlocations where the furnace chamber is relatively small for its rated capacity. On corner firedunits, wastage is often confined to the front wall, where the flame vortex is deflected forward bythe nose on the rear wall5.

In areas of persistent attack, gas analyses have revealed virtually zero oxygen partial pressures,>0.5% CO and uncombusted matter accounting for up to 50% of the solids recovered6. Whilststrictly the result of sub-stoichiometric combustion associated with impingement of the flameenvelope, such environments are frequently referred to in the published literature as reducingconditions. Recently research has shown that negligible corrosion occurs under predominantlyoxidising local flue gas conditions7. The corrosion rates are found to be dependent only uponmetal temperature, with no effects of coal composition or heat flux being discernible. Underreducing conditions, the corrosion mechanism shifts progressively from oxidation towardssulphidation as the CO content of the local flue gas increases. There is no measurable effect ofheat flux on the corrosion rates in the absence of chlorine, but increasing the CO content of thelocal flue gas increases the corrosion rates via the formation of progressively more sulphidewithin the corrosion scale. In the presence of even small quantities (<0.1%) of chlorine in thecoal burnt, metal chlorination, via the HCl/FeCl2 mechanism, comes into play and dominates theoverall metal loss. Linear reaction kinetics ensue and these are strongly influenced by a closeinterrelationship between coal chlorine content and heat flux7.

Low NOx Technology

12 of 108

Environmental legislation in the UK has demanded significant reductions in emissions fromcoal-fired power plant. The principal route towards meeting this requirement in existing UKplant has been the retrofitting of low NOx burners. The initial low NOx systems were fitted inthe late 1970's on corner-fired Units firing coals with a weighted mean chlorine content ofapproximately 0.3% and which were experiencing corrosion rates in excess of 600nm/h on thefront wall5. At the first survey after the low NOx installation, and in the absence of anysignificant changes in operating regime or fuel chemistry, marked reductions in corrosion ratewere found. Similar results have been reported on a corner fired super-critical boiler where thesecondary air has been offset to effect a partial low NOx system, although this improvement(1000nm/h to 100nm/h) coincided with a reduction in load factor. Based upon currentunderstanding of fireside corrosion, the beneficial impact of low NOx retrofits on furnace wallcorrosion has been attributed to:o containing the flame vortex within an oxygen excess blanket, mitigating the opportunity

for furnace wall tubes coming into contact with hostile environments,

o promoting a more diffuse heat pick-up in the burner zone, reducing the incident heatfluxes to which tubes are exposed.

Early experience with low NOx burner installations in front-fired boilers proved lessencouraging, with the detection of high CO levels on the rear walls and evidence of increasedmetal wastage on tube samples taken between surveys. Resetting the angle of secondary airvanes to promote greater swirl has subsequently rectified this problem by shortening the flamelength and these sites have now reported reduced corrosion rates in prior corrosion-affectedareas of the furnace wall. Burner retrofits at other Stations firing coals with a broad range of fuelchlorine contents have yielded comparable improvements in wastage rates.

The retrofitting of deeply staged low-NOx combustion systems in the USA has led to an upsurgein furnace wall corrosion problems with metal losses as high as 2mm per year being reported8.Super-critical units are generally more severely affected than sub-critical units and corrosion isgenerally limited to coals with more than 1%S. The highest corrosion rates have been reported inthat part of the furnace where H2S-rich sub-stoichiometric flue gas mixes with air from theoverfire air ports. It is postulated that FeS-rich ash deposits out of the reducing flue gas onto thetube surfaces. Because of the turbulent flow in boilers, these FeS-rich particles may be carried upand deposited on boiler tubes which are normally exposed to oxidising conditions. Under theseoxidising, or mixed oxidising/reducing, conditions these FeS deposits are thought to be oxidised,creating a highly sulphidising environment immediately adjacent to the tube surface.

Waterside Corrosion

The primary reaction involved in the waterside corrosion of high temperature boilers9 is theformation of magnetite, via the intermediary formation of ferrous hydroxide:

Fe2+ + 2OH- = Fe(OH)2

3Fe(OH)2 = Fe3O4 + 2H2O + H2.

In approximately neutral conditions, a magnetite scale forms on the tube, the growth of which isdominated by solid state diffusion through the scale. In the absence of sufficient hydrogen, thesolubility of magnetite in the boiler water is markedly temperature dependent and the corrosionrates of steels approach minimum (acceptable) levels around neutral pH values4-9. Excursions fromneutral values lead to increasingly severe attack.

In commercial drum re-circulating boilers, significant transport of corrosion products may occurin the water circuit and these tend to be deposited in areas of high heat flux. Hence, a porousoverlay of magnetite crystals, often incorporating nickel or copper derived from the feed system,

13 of 108

generally develops on the outer surface of the as-grown magnetite scale. The overall rate ofaccumulation of this deposit follows approximately linear growth kinetics and, under normalcircumstances, the rate of magnetite accumulation typically ranges from 1 to 2µm/1,000 hours.However, under the decidedly more flexible operating regimes now practised in the UK followingprivatisation, higher rates of magnetite growth and deposition (circa 4µm/1,000 hours) arebecoming more common.

In normal boiling conditions, steam generated at the tube surface is immediately replenished byadjacent liquid and no appreciable concentration of solutes is experienced. However, in areas oflocal dry-out, under thick porous deposits and in crevices, significant accumulation of solutes mayoccur. Concentration factors of up to five orders of magnitude may be generated, leading to severeon-load corrosion. Hence, common boiler water practice is to minimise corrosion, deposition andcarryover of boiler water solutes in the steam. This is often achieved by adding hydrazine to thewater to scavenge the oxygen and by removing some of the boiler water on a regular basis byblow-down. Further, regular acid cleaning of the boiler is often carried out to limit the total oxide(both grown and deposited) thickness.

In once-through units, any dissolved salts present in the boiler water remain in the system10.Hence, the concentration of contaminating salts in the feedwater must be maintained at a very lowlevel to ensure very low boiler water conductivity. A water treatment regime gaining in popularityis the neutral, oxygenated, low conductivity (NOLC) regime. Significant oxygen is deliberatelyadded to the water, either directly or as hydrogen peroxide, which results in the formation of veryprotective oxide films (magnetite/haematite) on the tube bore. Further, maintaining very lowconductivity reduces the deposition which might otherwise lead to an increase in tube walltemperature with time.

In order to prevent the risk of hydrogen induced stress corrosion cracking of ferritic steels fromthe internal fluid, the hardness in the heat affected zones of welds in boiler tubes should notexceed 350 Hv10

11. Further, austenitic steels are susceptible to stress corrosion cracking whenexposed to typical boiler water chemistries in high temperature plant.

Final Superheater/Reheater Banks

Superheater/Reheater Corrosion

Superheater and reheater tubes may fail well inside their intended design life by a combination offireside corrosion and creep5. Excessive corrosion attack of the leading tubes in a pendant stage isgenerally characterised by the formation of wastage flats on the tube surface at approximately the2 and 10 o'clock positions in relation to the gas flow. This is associated with the preferentialaccumulation of ash debris on the radiant crown, sculpted by the gas flow around the tube. Theaccumulated debris thermally insulates the crown section from the flue gas, displacing thehottest operating section of the tube surface towards the 2 and 10 o'clock positions where thedeposits are thinner and, consequently, the transmitted heat flux is greatest. Metal loss on tubesdeeper within the bank is invariably less pronounced, by virtue of their more sheltered position,and any wastage flats that form tend to be located at the 3 and 9 o'clock positions relative to thegas flow.

The fundamental mechanism of high temperature fireside corrosion is well established, being firstproposed in the mid 1940's12 and it is quite distinct from that operating on furnace walls, involvingmolten sulphatic phases derived from deposited ash. These molten sulphatic phases, specificallythose of alkali metals, exacerbate metal loss by a combination of direct sulphidation and scalefluxing to form alkali metal tri-sulphates.

The primary factors which dictate the rate of metal loss, either in isolation or synergistically,have been identified as tube metal temperature, incident heat flux (determined by the gas

14 of 108

temperature (Figure 3.1.5), and fuel chemistry, together with the tube material and the positionand alignment of the tube within an element.

The influence of tube metal temperature on molten salt corrosion was characterised by classicwork in the late 1950's and early 1960's13,14. At relatively low tube metal operatingtemperatures, typically below 550°C, the ash deposits in contact with the tube substrate and/orcorrosion scale are present as a porous solid layer. These deposits allow relatively free access ofthe bulk flue gas to the metal substrate/scale and the corrosion proceeds according to thetemperature dependent rate for the gas phase oxidation-sulphidation of the metal. As the tubemetal temperature increases, sodium and potassium sulphates, formed earlier in the furnacesection, gradually accumulate on the tube surface facing the gas flow by condensation at thebase of the porous alumino-silicate deposit. As the temperature increases through the meltingrange of the deposit, the chemical activity of the melt is heightened, causing a rapid increase inthe corrosion rate. However, as the temperature increases, the stability of iron sulphate/iron-trisulphate under the prevailing SO3 partial pressure decreases. Eventually, a temperature isreached at which the instability of sulphated iron species becomes dominant, causing the rate ofattack to diminish back to that associated with corrosion by gaseous species in the bulk flue gas.The dominance of melt activity, or corrosion product instability with temperature, gives rise tothe classic 'bell shaped' temperature dependence of corrosion under molten sulphates whichstarts at 600ºC and reaches a peak around 670ºC10.

Low NOx Technology

The retrofitting of staged low-NOx combustion systems in the USA has raised concern regardingcarburisation of austenitic stainless steel superheater and reheater tubes8. The C-content of the flyash is increased which may lead to locally reducing conditions in the superheater and reheaterareas, leading to carburisation of the tubes. Measurement of the increase in carbon content ofsuperheater steels in boilers fitted with staged low-NOx burners has suggested that 6% of thechromium content of the steel can be tied up as carbides15. In addition, delayed combustion of thefuel may result in higher metal temperatures of the superheater and reheater tubes which couldalso lead to an increase in corrosion rates16.

Steamside Oxidation

The exposure of all classes of steels to high temperature steam leads to the formation of an oxidescale, accompanied by some metal loss. For plain carbon steels, the oxide scale which forms islargely magnetite (Fe3O4) which offers some protection to the underlying substrate as it thickens.Hence the incremental increase in scale thickness declines with time, with total scale thicknessfollowing a parabolic relationship. The underlying metal loss typically equates to around one halfof the overlying scale thickness. For low alloy steels, a duplex scale, comprising an inner inwardgrowing spinel phase, overlying a magnetite layer of similar thickness, is formed. With increasingchromium content in the steel (>9%Cr), the first scale to form may comprise a highly protectivechromium sesquioxide (Cr2O3), the rate of thickening of which may be several orders ofmagnitude lower than that found on the lower alloy steels. However, the highly protective natureof this scale may eventually break down, leading to the more rapid growth of the more familiarduplex scales seen on lower alloy steels (Figure 3.1.6). The tendency for this scale reversion tooccur can be inhibited by increasing the rate of chromium supply to the growing oxide scale. Thismay be facilitated by increasing the chromium content of the steel, chromising the surface or byenhancing chromium diffusion in the substrate by surface cold working or significantly reducingthe grain size of the steel. For instance, shot blasting the bore is claimed to improve the steamoxidation resistance of austenitic boiler tubes by about an order of magnitude10.

For most conventional PF-fired plant, metal losses due to steamside oxidation are relatively minorand scant attention is taken of the effects of oxidation on, e.g. the creep rupture life of thecomponents. Figure 3.1.717 shows that the anticipated scale thickness on the bore of 1 to 2%Cr

15 of 108

steels after 200,000 hour exposure at 560°C is only anticipated to be around 450µm, whichequates to a metal loss of approximately 0.25mm. This equates to a loss of around 4% of the wallthickness of a 6mm thick superheater tube and 0.3 to 0.4% of that of a header or main steam pipe.However, for higher temperature plant, the growth of oxide on the bore of superheater tubingprogressively insulates the tube and restricts the heat flux through it. This can increase the mid-wall metal temperature of the tube (Figure 3.1.8), resulting in higher rates of both steamside andfireside corrosion and shorter creep rupture life11. In addition, the issue of scale spallation from thebore of low alloy steel tubing and the subsequent solid particle erosion of turbines has reportedlybeen a significant problem in the USA8. Increasing the volume of steam grown oxide in the boreof the tubes is likely to exacerbate this problem.

Headers/Pipes/Steam Separators

Thermal Fatigue

Fatigue due to cyclic loading can occur at local stress concentrations and thermal stresses due totemperature differentials. The latter is of particular relevance to thick walled vessels which maysee rapid changes of temperature due to start-up and shut down cycles. Hot water or steamentering a cold, thick walled vessel can lead to steep temperature gradients through the wallthickness. Expansion of the inner regions of the wall, close to the bore, may be constrained by theouter, cooler material. This imposes compressive stresses near the bore which may be sufficient tocause local yielding. As the temperature gradients equalise, and the outer regions of the wallexpand, the material at the bore may then go into tension. With continued operation at temperaturethe residual tensile stress relaxes until, on cooling, the process is reversed. Principal factors inlimiting the thermal fatigue life of plant components are the material properties (thermalconductivity, coefficient of expansion, mechanical properties), plant start-up and shut-down ratesand the presence of stress concentrating factors, such as tube penetrations into a header. Ferriticsteels generally have higher thermal conductivities and lower thermal expansion coefficients thanaustenitic steels and are thus less prone to suffer from thermal fatigue (Figures 3.1.9 & 3.1.10)18.

Problems Associated with Welding of Pressure Parts

Fusion welding is by far the most important process used in the fabrication of modern boilers.Components are joined by the formation of a molten pool of metal between them. The productionof high quality welds with a high degree of consistency is readily achievable. However, defectsare more likely to occur in welds than in wrought material. Whilst there are several modes of weldfailure, these are generally associated with inadequacies in weld procedure or practice and shouldreadily be detectable by non-destructive testing during manufacture. Nontheless, welding ofpressure parts can lead to other failure modes that only reveal themselves with time in service.Examples of such problems can arise due to stress corrosion cracking of weldments in low alloysteels exposed to boiler water and Type IV cracking in thick walled components.

The need to limit the hardness in steam generator tube welds to less than 350Hv10 has thus farlimited the choice of materials to low alloy steels such as plain carbon steel, 15Mo3 and T11. Thewell known T22 steel cannot be used since this, and more highly alloyed steels, require post weldheat-treatment (PWHT) to reduce the hardness in the heat-affected zones of welds. PWHTpresents no problems for the shop manufacture of membrane wall panels. It does, however, posegreat difficulties during erection and repair in the boiler.

Type IV cracking typically arises in the extremities of the weld and spreads into the inter-criticallyannealed regions. It manifests itself late in component life (typically after 35,000 hours in_%Cr_%Mo_%V steel hot reheat pipework) and propagates rapidly. Cracking appears to be adirect consequence of exhaustion of creep ductility in the “soft” Type IV zone at the extremity ofthe weld HAZ19 in these materials. This leads to a stress reduction factor of 20% and a cyclic lifereduction factor of approximately two under low cycle (i.e. thermal) fatigue.

16 of 108

3.1.4 Operating Environments and Failure Modes: FBC Plant

Atmospheric Pressure Fluidised Beds

Corrosion in Bubbling Beds

In view of the low combustion temperature (< 900ºC) and the capture of sulphur by addedsorbents such as limestone or dolomite, it was originally felt that there would be few, if anyfireside corrosion of in-bed tubes in AFBCs. However, early pilot plants demonstrated that theatmosphere in the bed could be aggressively sulphidising in the combustor if limestone ordolomite was present20. Enhanced sulphidation/oxidation was even found to occur in the absenceof limestone if the coal had a high, naturally occurring, CaO content21.

In an AFBC burning a range of different coals in a bed of sand with no limestone added the CoalResearch Establishment identified that negligible corrosion occurred on the cooler (up to 450ºC)in-bed tubes, even when burning UK coals with up to 0.73% Cl22. For the hotter tubes (550 and650ºC) the extent of corrosion was found to vary markedly with coal type. Only slight oxidationoccurred when burning a low Cl, Illinois coal but corrosion was accelerated by mixedoxidation/sulphidation, though not to unacceptable levels, when burning high Cl, UK coals. In allcases, corrosion was greater on the in-bed tubes than those tubes exposed to the same temperatureabove the bed. However, the most severe corrosion was observed when burning coals with higherthan average sodium contents when scale fluxing, analogous to the fireside corrosion experiencedin the superheaters and reheaters of PF boilers, was observed.

Corrosion in Circulating Beds

High temperature corrosion, separate from mechanical wastage, was not previously reported as aproblem in CFBC's23. Ahlstrom Pyropower use a straightforward 1%Cr 0.5%Mo steel for most oftheir superheater tubing, reverting to standard austenitic boiler tube steels when a higher creepstrength is required (i.e. in reheaters). However, with CFB units now being used to fire highchlorine-content fuels such as agrobiofuels, straws, grasses and domestic waste, the hightemperature chlorine-enhanced corrosion of superheater surfaces is becoming increasinglycommonplace.

Biofuel combustion results in the formation of gaseous alkaline sulphates and chlorides. Atmetal temperatures in the range 300-550ºC and flue gas temperatures of approximately 750ºC,such as those found in the superheater, any alkali metal chlorides carried over from thecombustion process are likely to partially melt and adhere to heat exchanger tube surfaces.Deposits on superheater tubing in a CFB boiler in Sweden were found to contain both sodiumand potassium chlorides24. Cl, Na and K in biomass fuel have resulted in corrosion beneathdeposits on tube surfaces and subsequently accelerated erosion-corrosion wastage of the furnacewall surface25.

The effects of high-temperature chloride corrosion have been reduced by the application ofprotective coatings at particularly exposed points, operational optimisations i.e. limitingtemperatures in the superheater to below that of the melting points of the alkali chlorides, andthe development of new superheater materials. At Grenå, evaporator wings have been retrofittedto the combustor to aid temperature control, and external fluid-bed heat exchangers account forfinal superheating from 470-505ºC. The intermediate superheaters in the convective pass areoperated at safe steam temperatures of less than 450ºC to prevent chlorine-induced corrosion.The highest loaded banks in each section are designed for periodic replacement and the hottest

17 of 108

convective heat surfaces are designed for excessive fouling by deposits with low ash meltingpoints26.

Erosion in Bubbling Beds

Sethi and Wright27 have made the general observation that steel tubes operating at temperatures ofabove ~400ºC tend to from a hard, thick and adherent oxide scale that leads to relatively littlewastage by erosion in the bed of an AFBC. However, at lower temperatures, the steel cannot forma protective oxide scale and severe erosion can be experienced.

Identical units burning different feedstocks have shown markedly different responses to erosivewear23 but there is no clear understanding of what factors are involved. Bakker, Liebhard andBrekke28 point out that correlations between bed-material properties and erosivity are noneexistent.

In terms of particle dynamics, Sethi and Wright27 have listed a number of potential causes oferosion in FBC systems. These are:

• the general flow of particles past the tubes,

• the presence of localised in-bed jets arising, for instance, near re-injection nozzles and close tobubble caps,

• the presence of long range flow patterns such as the general downflow of particles nearcombustor walls and the net upflow at the centre of the combustor,

• local flow regimes which arise as a result of geometrical irregularities,

• fast-moving particles ejected by bursting bubbles in the splash zone just above the bed,

• fast moving particles in bubble wakes,

• bubbles tracking along vertical or inclined tubes which can travel faster than those in thegeneral bed,

• intrinsically fast particles, at the top end of the range of general particle velocities, which maybe travelling at up to five times the superficial velocity.

• blocks of particles impacting onto tubes due to the presence of pressure pulses, in thefrequency range of 0.5 to 5 Hz, within the bed.

Given such complex particle dynamics, modelling of the local particle velocities and flowdirection in different areas of different bed designs has proven impractical. Consequently, much ofthe knowledge of in-bed erosion problems has accumulated with experience and many of theameliorative techniques have been developed on a trial and error basis.

Erosion in Circulating Beds

As with bubbling FBCs, wastage processes within the combustion chamber of circulating bedFBCs are dictated by the particle flow patterns. These are dominated by the general flow pattern,with additional flows being induced by gas injection, solids injection, bed recycling and otherdesign features, which may induce turbulence. Wastage rates are also thought to be a function offeedstock with, for instance, increased sodium in the ash increasing the erosivity. However, again,there is no clear understanding of what the dominant factors are.

18 of 108

The distribution of solids at the distributor plate has proven to be a significant problem. Thisdistribution is non-uniform, owing to various design factors such as solids feeds and recycleinjection ports. Any asymmetry in flow may lead to enhanced erosion rates and this is likely tobecome a bigger problem as unit size increases. Injector nozzles in this area are subject to heavyerosion and require frequent replacement.

The bulk of the particle flow within the combustion chamber takes place downwards around thewalls. As the particles fall, they tumble and rotate. This particle motion can lead to severe wastageat any discontinuity or disturbance to the flow pattern. The termination of the refractory coating onthe waterwall tubes acts as such a discontinuity and appears to be the area in CFBC's mostconsistently affected by severe erosion.

Following the patterns of behaviour adopted to deal with erosion of in-bed tubes in bubbling beds,the operators of the CFBC's have tried a number of essentially empirical 'fixes' to alleviate erosionat the refractory termination of existing plant. These include the attachment of shelves, plates orscalloped bars, to disrupt the downward flow pattern at the walls29,30, modification of the shape ofthe refractory at the termination, the use of coatings and weld overlays25,30,31 and redesign of thetube profile by the use of ‘kick-out’ tubes32.

In order to abstract as much heat as possible from the gas flow in the larger units, manufacturerssuch as Ahlstrom are now installing pendant tubes into the combustion chamber, prior to thecyclone. This exposes the tubes to a more erosive environment than they would otherwise see inthe back passes.

To alleviate this problem, Ahlstrom have introduced 'Omega' tubes into the boiler. These tubes aredesigned to eliminate any unnecessary discontinuities in the gas path that would change thedirection of upward or downward flowing particles. They are extruded as a standard product bySumitomo Industries and come in a variety of standard sizes. They have flat sided extensionswhich, when welded together, form a rectangular panel of tubes with straight sides aligned parallelto the general particle flow. It is claimed that these tubes have shown no signs of erosion damage,other than at the base of the lowest tube. Even this is claimed to have been rectified by welding aflat plate of iron into the lower channel to develop a backpressure which deflects the particle flowaway from the tube underside. Double “Omega type” tubes are used in the primary superheaterof the 230MWe circulating fluidised bed (ACFBC) plant at Turow in Poland33.

Pressurised Fluidised Bed Combustion

Bubbling Beds

The pressure vessel for the ALSTOM Power (formerly ABB) PFBC is constructed from lowcarbon steel. This pressure vessel contains a deep bubbling bed FBC operating at a bedtemperature of 850°C. Normally, the tube bank is totally immersed in the bed and comprises theevaporator, superheater and reheater (if required). The boiler chamber is of refractory coated,membrane wall construction; the steamside is conventional with 600ºC metal temperatures.

Circulating beds

Ahlstrom Pyropower describe their pressurised circulating FBCs as being of identical constructionto their atmospheric CFBC's. The water walls of the combustion chamber are of membraneconstruction with the lower section being refractory lined. The fluidising velocity is 5m.sec-1 witha bed temperature of 870ºC. The superheater and reheater are located high in the furnace and areconstructed from “Omega” tubes linked together to form a flat plate. Minimum erosion has beenexperienced on the side faces since they are aligned parallel to particle flow.

19 of 108

With the exception of hot gas filter materials, there are no materials problems specific to PFBCswhich have not been experienced in atmospheric FBCs,

Erosion- and Corrosion-Resistant Coatings

Protective coatings are seeing increased usage as plant operators seek to reduce the number offorced or planned outages necessary to repair or replace components susceptible to erosionand/or corrosion by extending the component’s life. Indeed, a flame spray coating ofAl/80Ni20Cr now has a lifetime of at least 3 years when applied to waterwall tubes30. A numberof coatings have been used in both operational and pilot plant, and a number have undergone, orare currently undergoing, laboratory testing, with variable performance in all cases. The choiceof erosion-corrosion resistant coatings should be specific to each individual application. Often acoating will perform well in one FBC environment, only to fail in another. This is because theerosion-corrosion behaviour of a coating is not only related to the morphology of the coating,but also to the characteristics of the erodent particles34.

Weld overlay was initially the preferred protective coating, typically forming layers 3mm thickusing 1.85% Cr hardfacing material25. Durable layers of Alloy 625 have been built up toapproximately 7mm thick on waterwall tubes in the USA30. However the application of weldoverlay is restricted due to the low productivity of the process, erosion of the resulting ledge andthermal shock35. Repeated applications at successive outages leads to embrittlement of the oldoverlay and to cracks that could propagate into the tube proper36. This had led to more attentionbeing focused on the application of thermal spray coatings.

A range of materials and application techniques (arc spraying, flame spraying, high velocityoxygen fuel spraying [HVOF], sintering) are available37. A variety of alloys have beenemployed in efforts to improve on parameters such as the adhesion strength of the coating to thebase material, resistance to spalling, hardness and oxidation in the bonding zone, heattransferability and resistance of the coating to corrodent penetration37. It is important torecognise that the coating performance is sensitive to surface preparation and post-processing,with the elimination of surface irregularities, and the critical nature of the contour of the coatingfrom its bottom to top edge. The coating should also be applicable on site at a reasonablecost25,38,39.

Refractories

Refractories in the combustion chamber of CFBCs may experience rates of temperature change ofthe order of 550ºC in a matter of a few minutes. Refractories in the combustor roof and cyclonemay experience even more damaging temperature excursions greater than 1100ºC. Thesetemperature excursions can lead to cracking, spalling and subsequently enhanced erosion ofrefractories23.

In their earlier plants, ABB-CE used to use SiC bricks to cover the wall tubes in the lower, bedarea, of the combustion chamber. These were held in place by spigots attached to the boiler tubes.However, oxidation of the spigots led to their ultimate failure, with the SiC bricks becomingdetached from the chamber walls. Thin refractory linings on studded water walls are now thenorm for utility size CFBC's. These refractories comprise SiC plastic or gun mix applied overdensely spaced studs and castable steel anchors. Repairs are carried out using phosphate-bondedplastic. The lower, sloping portion of the combustion chamber of ABB plant is studded andcovered with a 25mm thick layer of plastic refractory, Alumina Paste.

Following an internally-funded review of refractory experience in FBC plant, Powergenconcluded that:

20 of 108

• Many of the early refractory installations in FBC’s suffered significant degradation in thefirst few months of operation as a result of failure of support structures, cracking andspalling due to thermal cycling or thermal shock and erosion by circulating solids.

• Most of these failures could be attributed to the installation of appropriate refractories usinginappropriate attachment methods, including faulty gunning techniques or improper dry-outand curing procedures. Others were largely attributable to the failure to adopt operationalprocedures (e.g. control of heating and cooling rates) commensurate with refractoryproperties.

• Application of second-generation refractory technology, such as low cement castables inuncooled ducts, thin phos-bonded plastic on water-cooled walls and shop-fired bricks incyclones, has largely been successful in combating refractory failures in modern CFBCplant. Refractory lives commensurate with total plant life are being predicted for manyinstallations.

• The cyclone target area is subject to the most intense erosion within CFBC plant and is theone area where refractory lives of just two years are still anticipated.

However, recently published experience shows that problems with refractories still includefabrication quality control, mechanical design when anchoring refractory components to metalswith different expansion coefficients and also the operating time required to heat up or cooldown these materials40.

Refractories within the barrel and cone of the cyclone see the most onerous conditions23. Theefficiency of particle separation from the gas requires high centrifugal force which is dependentupon a high gas velocity and a tight turning angle. Erosion has proved to be a major problem onthe cyclone target area which can be reduced by careful design. The gunned linings of cyclones onthe first generation of CFBC's suffered from severe crack formation and movement of largesections adjacent to major openings and along the sidewalls41. Eventually, large lumps broke awayand clogged the cyclones. Within the first twelve months many systems had to be completelyreplaced. Now, the only castable refractories are in the cyclone roof, inlet roof and outlet duct tothe bypass. The nose section of the cyclone is typically lined with phosphate-bonded plastic. Therefractory system on the barrel often comprises a multi-component lining of dense, high-alumina,abrasion resistant, fibre-reinforced, super-fireclay brick, (or 90% Alumina or SiC) overlayingcalcium silicate insulating block adjacent to the barrel. The target zone of the cyclone may becovered with a silicon-oxynitride-bonded, silicon carbide.

The thermal cracking of refractories in cyclones has been mitigated by recent improvements indesign, utilising thinner layers of refractory. The thermal stress resistance of a thin refractorylayer makes the cyclone more suitable for frequent turn-down operating conditions42. As anexample, the water-cooled Kvaerner Cylindrical Multi Inlet Cyclone (CYMIC) uses lessrefractory than previous designs, leading to shorter start-up and shut-down periods and toleranceof wide load variations. Water-cooling means that light refractories can be used. Twocommercial CYMIC boilers are in operation, the largest of which is 185MWth at Rauma,Finland. An Integral Cylindrical Cyclone and Loopseal (ICCL) assembly has been developedfor larger units, with a 500t/h installation operating in the USA30,43.

In the Foster Wheeler Compact CFBC design, a water- or steam-cooled centrifugal separator (a‘square’ cyclone) is used, with the entire separation unit fabricated with flat walls constructedfrom conventional water-cooled membrane panels. To counter erosion, the interior walls of theseparator are covered with a thin layer of refractory held in place by a dense pattern of metalstuds. This lining has apparently proven very durable. The cooled construction minimisesdifferential expansion between the furnace and separator, thus minimising both the number and

21 of 108

the relative movement of expansion joints. A number of such plants are either operating orunder construction30,44.

3.1.5 Flue Gas Desulphurisation

Flue Gas Desulphurisation (FGD) is widely used to control the emissions of SO2 and SO3 fromPF-fired plant. A variety of processes are available, most of which use an alkali sorbent, such aslimestone, to capture the sulphur compounds from the flue gas. The most widely used FGDsystems comprise the limestone gypsum process, producing either saleable gypsum by-products,or disposable wastes such as sludges or mixed solids.

The only FGD plants on large PF-fired power stations in the UK are fitted at Drax and Ratcliffe-on-Soar. These both comprise the limestone wet scrubbing system and were both ordered in 1990.At the time, this system could be described as a mature technology, with many of the earlycorrosion and scaling problems having been cured by the application of suitable materials andcoating regimes. These included the use of rubber, glass flake vinyl ester resins and high nickelalloys. These materials have performed very well so far, giving little impetus for further materials’developments. However, some improvements have been made with slightly improved, or lowercost, alloys and the addition of mica, rather than glass flake, to the vinyl esters. The latter canwithstand slightly higher flue gas temperatures. Further, scrubbers manufactured from glass-reinforced plastic, which are cheaper than metal absorbers and offer better corrosion and weather-resistance and easier maintenance, are becoming available in increasingly large sizes. FGDrecycle pumps are probably the main area of plant where materials improvements are stillrequired. Rubber coatings on these pumps can suffer damage from contact with solids and themetal castings and impellers are susceptible to corrosion and cracking, particularly in highchlorine environments.

3.1.6 Component Integrity and Life Assessment

Operating conditions and environments represent an ongoing threat to component integrity insteam raising plant. There is no prospect of any utility being able to adopt a ‘fit and forget’philosophy within the design life of a boiler. Indeed, current life extension means that much of thePF-fired plant in the UK is approaching, or has already exceeded, twice the original design life.Further, with changes in commercial markets and regulation, existing plant is currently having tooperate in a much less certain and much more flexible regime than its original design intent.Accordingly, components are increasingly being subjected to ever more onerous operatingconditions under ever more aggressive environments. Hence, all utilities are obliged to develop,adopt and continually improve methods for assessing the integrity and future safe life ofcomponents in service. These life assessment methods incorporate the most up to date NDEtechniques and metallographic assessment procedures to determine materials’ degradation inservice. These are supplemented by extensive databases of materials’ properties, fracturemechanics, knowledge of microstructural evolution with time at temperature, measurement andanalysis of corrosion mechanisms and finite element stress analysis, in order that risks tocomponent integrity can be minimised.

3.1.7 State of the Art PF-fired Boilers

Table 1 lists the chemical compositions of the boiler materials referred to in this section. Onlyrecent and near-term developments are discussed below.

22 of 108

Steam Generating Walls

Current

Without exception, the steam generator tubes in the furnace walls of supercritical plant are ofmembrane wall construction. In conventional supercritical plant (250bar, 540°C) the maximumtemperature of the water/steam fluid in the water-wall panels is 420°C at the outlet. Because of thehigh heat fluxes in the furnace chamber, the mid-wall metal temperature is approximately 450°Con entering service. Growth and deposition of magnetite on the bore of the tubes increases thetemperature difference through the walls such that, at 100,000 hours, the estimated mid-walltemperature rises to 455°C. Under such conditions 1%Cr 0.5%Mo steel has adequate mechanicalproperties for a 100,000 hour life. Stork Ketels use a 0.5%Cr steel in the evaporator wall tubes andclaim an acceptable metal temperature at the furnace outlet of 460ºC. Temperatures of up to 500ºCcan be tolerated for short periods (5 minutes) at low pressures during start-up. ABB favour the useof T11 or T22 steels and quote a maximum operating temperature of 538ºC. Then, C-Mn and low-alloy steels can continue to be used for main steam conditions of up to 580ºC and 290 bar.

All of the boiler manufacturers offer some form of staged combustion to limit the NOx emissions.In all cases this implies sub-stoichiometric combustion in the lower portion of the furnacechamber. Such sub-stoichiometric conditions pose the danger of furnace wall fireside corrosionwhich can lead to very rapid thinning and, hence, early failure of the membrane wall tubes. ABBclaim that they favour the use of T22 steel over the T11 steel because the increased chromiumcontent offers improved oxidation resistance. However, chromium contents in excess of 25% arerequired before any real improvement in furnace wall corrosion rate is likely to be experienced.None of the materials proposed thus far possess sufficient corrosion resistance to withstandfurnace wall fireside corrosion. For furnace wall applications, bimetallic boiler tubes, such asthose produced by co-extrusion, are the only tubes likely to possess the required corrosionresistance. However, the use of an austenitic outer layer for furnace wall corrosion resistancewould pose tremendous difficulties with differential thermal expansion in membrane walls.Consequently, all boiler manufacturers offer some means of ensuring more oxidising conditionsclose to the furnace walls. ABB, Steinmüller and Stein Industrie all use corner fired units with, forinstance, offset secondary air. Stork Ketels use a front wall fired system with the stoichiometry ofthe burners closest to the sidewalls set up to be more oxygen rich.

620ºC/325bar

For USC plant of 325 bar and 620°C, the maximum water/steam temperature at the outlet of thewater walls is approximately 475°C. This equates to a mid-wall temperature of 497°C on enteringservice which climbs to 513°C over 100,000 hours. The metal temperature of the outer surfacemay rise as high as 524°C in general and 539°C in the highest heat flux areas (burner zone). Themechanical properties of conventional boiler steels are no longer adequate for this duty and morehighly alloyed, creep resistant, materials are required. Hence, UNIPEDE 45 consider that the maindifficulty in creating high-grade supercritical steam conditions in the 600°C/350 bar range isconcerned with the steam generating tube materials available. It will only be possible to exceed45% thermal efficiency if materials for construction of membrane walls can be found which canoperate above 500°C.

Preliminary calculations based on the allowable stress data for T23 (Table 3.1.2, Figure 3.1.11)suggest that the maximum permissible water/steam temperature using T23 in the waterwalls ofsupercritical plant would be 480°C. This should be sufficient for use in plant operating at 325bar,620°C3.

7CrMoVTiB10-10 has a slightly higher creep strength than T23 steel at temperatures up to570°C (Table 3.1.3, Figure 3.1.13), whilst above this temperature, T23 would be the preferredchoice. However, the long term strength values for the latter may be somewhat optimistic as

23 of 108

they are derived from extrapolation of much shorter duration creep rupture data (~15,000hours). Further, precipitation of W-bearing Laves phase is expected during exposure, resultingin some loss of solid solution hardening. By contrast, the data for 7CrMoVTiB10-10 steelextend out to nearly 100,000 hours, so that some confidence can be placed in the strengthvalues.

Both T23 and 7CrMoVTiB10-10 are readily welded, neither requiring preheat or post-weld heattreatment. Similarly, both steels are reported to have good fabrication characteristics46,47.However, whether either of the materials has the necessary resistance to steam oxidation foroperation at such temperatures remains an open question.

ALSTOM Power and Mitsui Babcock are currently considering the use of T23 for water wallapplications in supercritical plant. Trial panels of T23 and T24 have been installed inAsnaesvaerket in Denmark and Cordemais in France. Preparations are in hand for further trials inWeisweiler, Neckar 2 and Altbach48. Vallourec and Mannesmann have just received their firstcommercial order for T23 for superheater tubes in a plant in Morocco. If the ongoing tests aresuccessful then problems concerning the water-walls will be solved and it will be possible tooperate with water/steam temperatures of 500 to 520°C in the water-walls49.

650ºC/350bar

For USC plant with steam conditions above 620°C/325 bar, further materials improvements willbe necessary to reach steam/water temperatures much above 480°C in the water-walls. In viewof thermal expansion limitations in membrane wall construction, the materials of choiceinvariably comprise ferritic steels. In view of this, Mitsubishi Heavy Industries are looking atfurther improving the creep strength of T23 for these applications by the addition of Re50.However, considerable attention is being directed towards the 9 and 12% chromium steels suchas T91/P91, X20CrMoV121 and HCM1251. Notwithstanding the higher chromium contents, itshould not be assumed that these steels will have adequate corrosion resistance and, as they aremore expensive, their use will inevitably increase constructional costs.

Full sized furnace wall panels were made from T91 and HCM12 by a number of manufacturersfor the European COST 501 Round 2 Programme51 without reported difficulty. The panels werefound to be completely defect-free when examined both visually and by NDT. However, nomanufacturer managed to complete a panel fully in compliance with the German TRD code withrespect to the hardness criterion of < 350 Hv10 and the weld not more than 150 Hv10 greater thanthe parent material, without resorting to post-weld heat treatment. Efforts are being made toestablish whether reducing the carbon content of these steels will ensure hardnesses of less thanthe critical value of 350 Hv10 in welds without any reduction in the creep strength of the material11.However, Masuyama et al26 expect HCM12 to be applicable to water walls because it has betterweldability than T91 and a lower susceptibility to SCC. On this basis Franklin and Henry51

recognise that field tests and discussion with local authorities will be needed before either materialcan be used. As part of this ongoing development, test panels of P91 and HCM12 have been builtinto the water-walls of plant operating in Germany.

Steam Separating Vessels

For once-through, super-critical units, steam separator vessels are positioned at the steamgenerating wall outlet to separate the water from the saturated steam. The steam flows on to thesuperheaters whilst the water is returned to the boiler water feed train. The separators are large,vertical vessels, which have to be sized to accept large changes in the fluid level without dumpingwater. At between 40% and 100% of boiler load, the separators are running dry (containing steam)but at lower load, and during start-up and shut down, they pass through the transition from wet(water) to dry (steam)51. This mode of operation imposes severe thermal fatigue stresses on thematerials of construction.

24 of 108

The steam separators for Steinmüller plant are currently manufactured from a high strengthcarbon-manganese steel whilst Stein Industries favour the use of the 1%Cr _%Mo steel13CrMo44. Although the steam separators of advanced super-critical plant could conceivably bemanufactured from the above materials, the necessary increase in wall thickness would cause adegradation in operational flexibility, seriously increasing the start-up and shut-down timesnecessary to limit the through wall temperature transients. Hence, both Steinmüller and SteinIndustries consider that materials with a higher proof strength will be required for increasingsteam conditions. However, materials choice does not necessarily limit boiler operation, sincethere is the option to use more separators of lower capacity, thus reducing the required wallthickness. Franklin and Henry51, for instance, claim that a large capacity boiler of approximately800 MW would require 8 separators.

P91 or X20CrMoV121 could be used to reduce the wall thickness and thus lower the thermalstress if required. However, long term testing has confirmed the reported tendency for failure inthe “soft” Type IV zone at the extremity of the weld HAZ19 in these materials. Steinmüller do notexpect the material properties of P92 to be much better than P91 in this application. Whilst thethermal expansion of P91 and X20CrMoV121 are very similar, P91 shows a higher thermalconductivity11. Hence, P91 is expected to possess a greater tolerance to thermal cycling, with alower tendency to thermal fatigue cracking. Since it is cheaper than the higher chromiumX20CrMoV121 steel, the former is expected to be favoured as a steam separator material for moreadvanced steam conditions11.

In terms of further materials development, HCM12 is claimed to demonstrate a low increase inhardness after welding, possesses a high creep strength and a relatively lower sensitivity to TypeIV cracking than P91 or X20CrMoV121. It does, however, possess a relatively high delta ferritecontent (up to 30%) which could pose toughness problems, particularly for thick walledcomponents, after a long time in service51. Pipes manufactured from P122 are claimed to have ahigher creep strength, better corrosion resistance and better weldability than those manufacturedfrom P91 steel52.

Superheater Tubes

Current

Superheater tubes must be designed to operate at temperatures some 35ºC above live steamtemperature48. For current steam temperatures of up to around 580ºC, metal temperatures will bearound 615ºC and low alloy steel tubes such as T22 may be adequate. However, not only do theadvanced steam parameters for supercritical plant impose higher stresses and temperatures on thesuperheater tubes, they also increase the potential rates of both fireside and steam side corrosion.Fireside corrosion on the outer surface of superheater and reheater tubes can lead to rapid thinningand, hence, subsequent premature failure by creep. Experience within the CEGB in the 1970's, forplant with final steam temperatures of 565ºC and burning coal with chlorine contents greater thanaround 0.15%, showed that these low alloy steels did not possess sufficient fireside corrosionresistance. Consequently, the 500MW units required selective re-tubing with the austenitic steelsT316 and T347.

If the steam temperatures are to be only moderately increased, and the fireside corrosion potentialis low, then the improved medium chromium ferritic/martensitic steels such as P91, P92 and P122could be considered as possible alternatives to X20CrMoV121. In such circumstances, thesteamside oxidation rate assumes increasing importance. Increasing the steam temperature leads tomore rapid growth of oxide scales on the bore of the tube17. As the bore oxide scale thickens, theheat transfer to the steam inside the tube is reduced. Hence, the wall temperature of the tubeprogressively increases with increasing service life51. Such an increase in wall temperature notonly leads to the more rapid accumulation of creep damage, it also results in higher fireside and

25 of 108

steamside corrosion rates. Thus, thinning of the boiler tube and increasing wall temperatures arelikely to progress ever more rapidly under a self-accelerating process. Steam oxidation rates on9Cr steels limit practical application to 600ºC.

620ºC/325bar

For steam conditions of 325 bar at 620°C the metal temperature in the final superheater will bearound 660°C49. Boiler tubes operating under these conditions will need a 105 hour creep rupturestrength of about 100MPa and a fireside corrosion rate leading to a maximum metal loss of 2mmin 100,000 hours. Both P91 and P92 are unlikely to possess sufficient fireside corrosion resistancein this application. However, it is hoped that these new, higher creep strength, ferritic steels willlimit the cost impact by their selective use in cooler parts of the circuit. Austenitic materials, suchas X8CrNiMoNb1616, X8CrNiMoVNb1613 and X3CrNiMoNb1713 exhibit similar creepproperties to the currently employed 12%Cr steels, such as X20CrMoV121, at a metal temperaturesome 70 to 80 °C higher 51. Increasing the chromium content of these steels confers a greaterresistance to fireside corrosion53. Even with the austenitic steels, the fireside corrosion rate hasbeen found to be very sensitive to the chromium content below approximately 30% (Figure3.1.13). A 20% chromium steel, for example, shows a fireside corrosion rate of approximately onethird of that of a 15% chromium steel under similar conditions54.

Whilst fine grained 347HFG and Super 304 both have the required creep rupture strength foroperation up to 650°C, the inadequate corrosion resistance conferred by chromium contents ofaround 18% may limit their operating temperatures to 615-620°C51. The tubes will also need to bemanufactured from a material showing minimal steam side oxidation at these temperatures. Thiswill be necessary in order to limit overall oxide growth and any tendency toward magnetiteexfoliation.

For both NF709 and HR3C, the creep rupture data relate to tests of relatively short duration(circa 30,000 hours) and hence some caution should be exercised regarding the quoted strengthvalues for operation to 100,000 hours. Also, whilst the steels are likely to have good corrosionand steam oxidation resistance, the final choice of material should be made on the basis ofspecific data, preferably obtained from tests on panels installed in operating plant. Currently,only data from short-term laboratory tests on material exposed to idealised environments aregenerally available, these being inadequate for proper evaluation of performance over timesrelevant to plant.

650ºC/350bar

For tubes with metal temperatures approaching 700C, enhanced versions of austenitic steels suchas NF709, AC66, HR3C and HR6W will be required to limit the bore oxide thickness48.

Headers and Steam Pipes

Current

As headers and pipes are situated outside the furnace, fireside corrosion resistance is not a factorin the selection of materials. However, resistance to steam oxidation must still be considered.

Since 1980, all new plants built for the ELSAM system have been super-critical49. Ferritic steels,from C-steel up to X20CrMoV121 (12%Cr), have been used for thick section components in plantdesigned for steam conditions of 250 bar and 540°C, with steam lines being manufactured fromX20CrMoV121. The same X20 steel is being used for thick section components in plant operatingat the higher steam conditions of 250bar and 560°C51. Materials with even higher creep strength

26 of 108

will be needed for thick section components under more advanced steam conditions andP91/T91/F91 are claimed to be suitable for such use up to 300 bar and 580°C.

Keeping the design parameters constant, Figure 3.1.14 shows how the wall thickness can bereduced as the creep properties of the steel increase45.

620ºC/325bar

A temperature of 620°C for steam delivered to the turbine implies metal temperatures ofapproximately 625°C during normal operation. However, significantly higher metaltemperatures could develop under ‘upset’ conditions, such as during starts. Such temperaturespose a dilemma as regards the selection of materials, these being at the limit at which currentlyavailable ferritic steels can operate. Thus, above 600°C the creep strengths of even the strongestcurrently available ferritic steels begin to fall off rapidly, with steam oxidation ratescoincidentally showing a marked rise. Nevertheless, the possibility of using ferritic steels isattractive since they have a low coefficient of expansion and, hence, headers would be expectedto have a low susceptibility to thermal fatigue cracking. However, the low creep strength atthese temperatures would lead to vessels of relatively thick wall, raising the cost, and possiblylimiting the cycling capability of the plant.

The choice of materials for superheater headers, manifolds and pipework will depend to a largeextent on the philosophy applied to the design of the boiler. P92 and P122 steels appear primecandidates for use where ferritic materials are required. However, welds in thick section headersand pipework are likely to be susceptible to Type IV cracking and allowable stresses willultimately be limited by the need to account for this phenomenon. Similar consideration willalso need to be paid to the performance of transition joints.

After successful welding trials, P92 (as NF616) has been tested in a main steam line of the250bar/560ºC unit at Esbjerg Unit 3. P92 and P122 were chosen for thick-section boilercomponents and steam lines for coal fired USC with 325bar 620ºC/630ºC steam conditions in anELSAM design study. Subsequently, as part of COST 501 Round II, superheater outlet headerswere manufactured in P92 and P122 and installed in one of ELSAM's 400MWe double-reheatUSC plants with 290 bar 580ºC/580ºC/580ºC. Recently, P122 has been chosen by MHI forTsuruga 2 (24.1 MPa 593ºC /593ºC) and Babcock Hitachi have selected P122 and P92 forTachibanawan (24.1 566ºC/593ºC), both for commissioning in 2000. In Denmark, P92 waschosen for headers and steam lines in Avedoere 2. Table 3.1.8 lists trials of these advanced9/12%Cr steels in plant during the COST 501 programme.

ASTM and ASME approval of E911 as P93 will allow construction of thick-section boilercomponents and steam lines for USC plant with steam parameters of 610CºC/325bar for mainsteam and 625ºC for hot reheat49.

Since they possess higher thermal expansion coefficients and lower thermal conductivities thanferritic/martensitic steels, components manufactured from austenitic steels are expected toexhibit less favourable thermal cycling behaviour54. With regard to the choice of austeniticmaterials, the somewhat lower metal temperatures expected in headers and pipework mean thatless expensive grades with lower chromium contents can be considered than for tubing. A gradesuitable for the present application is reported to be X3CrNiMoN1713 steel (Table 3.1.1)55. Theallowable stresses for this steel for 100,000 hours operation, derived from the published creepstrength values56 are given in Table 3.1.9.

The higher creep strengths of the austenitic steels implies that a significant reduction in wallthickness may be realised (Figure 3.1.15). As the required wall thickness of a header increases,the martensitic steels lose their advantage over austenitic steels in terms of allowable rate oftemperature change (Figure 3.1.16). Then, at 600ºC for instance, the allowable rate of

27 of 108

temperature change for a header manufactured from P91 steel is only one half of that of onemanufactured from the austenitic 1.4910 steel11. With suitable design, involving a large numberof smaller, parallel steam paths and the use of header manifolds to reduce the number ofweakening penetrations, then 1.4910 steel could be used at up to 620ºC and 350 bar or 650ºCand 250 bar (Figure 3.1.17)11. Four German power stations have decided to install 1.4910 on alarge scale for the first time. Boilers planned or under construction include Units R and S inLippendorf (2 x 800 MW) and Unit 4 at Boxberg (440MW).

650ºC/350bar

For final steam conditions in excess of 620ºC, the new COST 522 programme will be looking tothe development of the 12%Cr martensitic steels for higher strength and higher steamsideoxidation resistance.

In 1997 the National Research Institute for Metals (NRIM) in Japan started R&D for advancedferritic steels for large diameter pipes and headers for USC plant with 650ºC and 350 bar57. Thiswork has been directed towards the development of W-strengthened 9% and 12% Cr steels withlong-term creep strengths higher than P92 and P122 and will comprise iridium additions toincrease creep strength and silicon additions (especially with simultaneous addition of Ti or Y) toimprove oxidation resistance. The even stronger NF12 (12%Cr-W-Co) is also under consideration,since extrapolation of short-term data implies that this steel may have a 105 hour creep rupturestrength of around 100MPa at 650°C.

3.1.8 State of the Art FBC

A recent development in CFBC is the Foster Wheeler Integrated Recycle Heat Exchanger(INTREXTM) design. This is a bubbling bed heat exchanger located in the lower part of thecombustion chamber as part of the furnace, containing one or more tube bundles to coolcirculating solids. The immersed tube bundles can replace a superheater in the furnace orbackpass. As the INTREX heat exchanger is fluidised with air, the most corrosive elements inthe gas stream do not come into contact with high temperature superheater tubes. INTREX unitshave been installed at a 30MWth plant in Finland and the 77MWth Grenå plant in Sweden.Plants under construction using INTREX include a biofuel-fired 157MWth ACFB boiler inVasteras and a 265MWe project at the Jacksonville Electric site in Florida30,44.

3.1.9 Future R&D Priorities

Much work has been carried out to develop new steels for advanced super-critical plant over thepast 20 years. In Europe, where government funding is severely limited, the research work has hadto be highly targeted to make the most of limited funding. Government funding for the COSTProgramme has been very patchy, with projects in Germany and Austria receiving substantialsupport, whilst that in the UK has previously had little or no financial support. As a consequence,most of the really significant advances in new materials appear to have been made in Japan, wheresubstantial government funding continues to be made available. As a consequence, the Japanesesteel makers are already claiming to have developed materials which will allow the manufactureof plant capable of operating up to 650ºC main steam.

Nevertheless, steels with improved mechanical properties are becoming available in Europe.These have allowed a progressive increase in main steam temperatures, such that power plant withfinal steam temperatures of 600ºC can now be considered available. Further, main steamtemperatures of 620ºC should be realisable in the near-term future. However, further work will berequired to realise some of these goals, particularly with regard to achieving the higher main steamtemperatures of up to 650ºC.

28 of 108

The creep rupture data reported in the published literature for most of these developmental steelsextends to only about 45,000 hours, with the 105 hour creep rupture strength being derived byextrapolation. Data obtained from much longer exposures will be required before these 105 hourcreep rupture strength values can confidently be used for boiler design purposes. In addition, the9-12%Cr steels continue to display a 20% or so reduction in strength in the Type IV cracking zoneon welding. Either this will need to be accounted for in design, or further work will be required inan attempt to minimise the problem. A joint PowerGen/Mitsui Babcock Programme is underwayto examine the mechanical properties and weldability of E911.

Perhaps of even greater concern is the fact that most of the fireside corrosion data provided byJapanese steel manufacturers is generally based on 24 to 100 hour exposures of the trial materialsto an idealised molten salt mixture in laboratory studies. Whilst these data may be of value forranking purposes, much more realistic fireside corrosion data, obtained from much longerexposures of the trial materials to relevant environments, will be required. Little attention has beenpaid to the fireside corrosion of candidate boiler tube steels in the earlier COST programmes,particularly the effects of fuel quality on corrosion rates. This is being rectified to some extent inthe new COST 522 programme, where more realistic exposure to high temperature flue gases in avariety of operating plants is underway to elucidate the longer-term performance of some of thenewer alloys.

Similarly, little attention appears to have been paid to the steamside oxidation resistance of mostof the steels. The Japanese have shown that silicon has an important influence on steamsideoxidation rates for the 9 to 12% chromium steels (Figure 3.1.18)62, revisiting work carried out bythe CEGB in the 1970's. However, the authors noted that increasing the Si-content of the steelabove 0.4% was found to be detrimental to toughness. Given that oxidation rates will inevitablyincrease with increasing temperature, more work needs to be done on determining the best meansto limit the steamside oxidation rates on all components in the system.

The latest initiative in alloy development comprises computer-aided alloy design. Widespreadapplication of computer programs such as "Thermo-Calc", "MT-Data" and "Dictra" have resultedin major improvements in the ability to understand and predict the equilibrium phase diagrams ofmulti-component systems, their thermodynamic and diffusion behaviour and diffusion controlledphase transformations, from alloy composition and heat treatment. Such methods, called the"Calphad approach", have been used to calculate alloy compositions for COST 522.

The development of improved creep strength in alloys is often obtained at the expense ofcorrosion resistance. In order to achieve the ever increasing strength levels required it may benecessary to sacrifice some of the corrosion resistance of the base alloy. Then more effort willneed to be directed towards the development of coatings or surface treatments that confersubstantial resistance to both fireside corrosion and steamside oxidation if ever-increasing cycletemperatures are to be achieved in advanced plant.

Developments in life assessment procedures are required to take into account the higher metaloperating temperatures, the more arduous thermal cycles and the more aggressive combustion andsteam environments that will be experienced in the more advanced boilers burning a wider rangeof coal and biomass mixes currently being contemplated. These procedures will need to includemethods for condition-monitoring and life-assessment of protective coatings.

The overall objective of the major European AD 700 project is to develop and demonstrate a newgeneration of PF plant with advanced steam conditions63. This will be achieved through theapplication of Ni-based superalloys to allow the use of steam temperatures up to 700°C/375barand an overall thermal efficiency of 55%, compared with the 47% efficiency of state-of-the-art600°C/300bar/300 bar double-reheat plant. This is expected to reduce fuel consumption and thusCO2 emissions of around 15%. Much larger components are required for steam cycle plant than in

29 of 108

gas turbines so these temperature increases represent a significant materials challenge. There willbe a need to demonstrate both the manufacturing capability and innovative constructiontechniques. In terms of materials development, the major needs are seen as creep strength for long-term operation at high temperatures, corrosion resistance in flue gas and steam, thermal fatigueresistance and the ability of components to be manufactured and welded in thick sections.

The future R&D requirements for boiler materials may be summarised as follows:-

1. T23 and 7CrMoVTiB1010 appear to be the most likely materials of choice for the waterwalltubes in super-critical plant operating up to 625°C and 325 bar, but stronger materials will berequired for higher steam conditions. The candidate materials at the most advanced stage ofdevelopment at present are P92, P122 and E911, but all three currently require post-weldheat treatment during fabrication.

2. Current materials are available for the manufacture of steam separating vessels for steamconditions of up to 625°C and 325 bar. Where limitation of wall thickness criteria apply,stresses in the walls of these components may be reduced to acceptable levels by increasingthe number of separators and reducing their duty. Stronger materials will be required foroperation above 625°C and 325 bar, with T91/P91 being a strongly favoured candidate.

3. Austenitic stainless steels which possess adequate creep rupture strength and fireside andsteamside corrosion resistance are available for use in the final superheater tubes of advancedPF-fired plant operating with steam parameters up to 290bar/580°C, provided the inherentflue gas corrosivity (Cl content) is low. However, it is unlikely that the fireside corrosionresistance of these steels will be sufficient to operate much above 620°C.

4. More highly alloyed steels are under development which may allow operation at steamtemperatures of up to 630°C. However, more work is required to extend the creep rupturedata for these steels out to longer times and longer-term fireside corrosion data, collectedunder more realistic conditions, will be required before these materials can be used with anydegree of confidence.

5. The recent ASTM/ASME approval P92 and P122 should allow construction of thick-sectioncomponents and steam lines for advanced PF-fired plant operating with steam parameters ofup to 325bar/610°C. However, welds in thick-section headers and pipework are likely to besusceptible to Type IV cracking and allowable stresses will ultimately be limited by theneed to account for this phenomenon. Similar consideration will also need to be paid to theperformance of transition joints.

6. The higher creep strength of the austenitic steels and the somewhat lower metaltemperatures expected in headers and pipework mean that less expensive grades, such asX3CrNiMoN1713, with lower chromium contents, can be considered than for tubing.

7. Solid Particle erosion presents by far the biggest threat to long-term component integrity inFBC plant. Designs are increasingly being adopted that minimise the likelihood of in-bederosion. However, as the number of FBC plants burning biofuels continues to rise, so theproblem of chlorine-enhanced erosion-corrosion becomes more of an issue. Heatexchangers are especially susceptible to the deposition of alkali metal chlorides andsubsequent corrosion, particularly at the superheater.

8. Thermal cracking of refractories continues to be an issue in FBC plant, particularly in thecyclone, and anchoring of refractory components to metals is still problematic. However,recent cyclone designs now utilise thinner layers of refractory, thus reducing the thermalstresses associated with thicker layers.

30 of 108

9. The development of ceramic tube hot gas filter systems (CTFs) for particulate removal isthe most significant recent development in PFBC technology. However, developing andcommercial ceramic filter systems are limited by process upsets and process equipmentfailures, and require improvements in life and temperature capability for use in PFBC.CTFs could limit the development of advanced PFBC plant, as they have not operatedreliably at the elevated gas temperatures they would be exposed to.

10. Recycle pumps are probably the main area of FGD plant where materials improvements arestill required. Rubber coatings on these pumps can suffer damage from contact with solidsand the metal castings and impellers are susceptible to corrosion and cracking, particularly inhigh chlorine environments.

11. Ongoing requirements for improved materials for advanced boiler plant include:

• further development, refinement and validation of microstructural modelling procedures,

• long-term creep rupture and thermal fatigue data,

• long-term fireside corrosion and steamside oxidation data in real environments,

• development of protective coatings,

• further development and validation of life-assessment procedures, including coatings.

1.

References for Section 3.1

1. K. H. Mayer, W. Bendick, R-U Husemann, T. Kern and R. B. Scarlin (1998), "NewMaterials for Improving the Efficiency of Fossil-Fired Thermal Power Stations". VGBPowerTech (1998) No.1 pp 22-27.

2. D. V. Thornton and K. H. Mayer (1999), in "Advanced Heat Resistant Steels for PowerGeneration" Eds. R. Viswanathan and J. W. Nutting, IOM Communications 1999 pp349-365.

3. R. Blum, (1994), “Materials Developments for Power Plants with Advanced SteamParameters: Utility Point of View” in “Materials for Advanced Power Engineering 1994”Proceedings of a Conference held in Liège, Belgium, 3-6 October 1994. Edited byCoutsouradis, D. et al. Kluwer Academic Press, (1994), pp15-30

4. B. Dooley. (1993); "Boiler Tube Failure Metallurgical Guide, Volume 1: TechnicalReport", EPRI Report TR-102433-V1.

5. P. J. James and L. W. Pinder, (1997), "Effect of Coal Chlorine on the FiresideCorrosion of Boiler Furnace Wall and Superheater/Reheater Tubing". Materials at HighTemperatures 14(3) (1997) 187.

6. F. Clarke and C. W. Morris, (1983) "Combustion Aspects of Furnace Wall Corrosion" inCorrosion Resistant Materials for Coal Conversion Systems, edited by Meadowcroft,D.B. and Manning, M.I., Applied Science Publishers.

7. C. J. Davis, P. J. James, L. W. Pinder and A. K. Mehta , (2001) "Effects of FuelComposition and Combustion Parameters on Furnace Wall Fireside Corrosion inPulverised Coal-Fired Boilers", Materials Science Forum, in Press.

31 of 108

8. R. Viswanathan and W. Bakker, (2001), "Materials for Ultrasupercritical Coal PowerPlants - Boiler Materials: Part 1". Journal of Materials Engineering and Performance, Vol.10, No 1, 2001, pp 81 to 95.

9. D. G. Kingerley, (1994), Chapter 17.4 ‘Boiler and Feedwater Treatment’ in Shreir, L.L.,Jarman, R.A. and Burstein, G.T. ‘Corrosion, Third Edition’ Butterworth Heinemann,London 1994.

10. A. Fleming, R. V. Maskell, L. W. Buchanan and T. Wilson, (2000) "MaterialDevelopments for Supercritical Boilers and Pipework" in Materials for High TemperaturePower Generation and Process Plant Applications Edited by Strang, A. Institute ofMaterials Publication Book No. 728. pp 32-77.

11. A. Kather, G. Helermann, R-U Husmann, P. Hougaard and M. Knizia, (1994), "SteamGenerators With Advanced Steam Parameters", Private Communication.

12. W. T. Reid, (1971), "External Corrosion and Deposits; Boilers and Gas Turbines.American Elsevier Publishing Company Inc. New York, 1971.

13. J. G. Koopman, E. M. Marselli, J. Jonakin and R. C. Ulmer,(1959); Proc. Amer.Pwr.Conf, 21, 236.

14. W. Nelson and C. Cain (1960): Corrosion of Superheaters and Reheaters of PulverisedCoal Fired Boilers, J Eng for Power, 82, Ser A No 3, pp194-201, July 1960.

15. D. N. French (1998), "Carburization Corrosion in Superheaters and Reheaters."Proceedings of the 3rd International Conference on Boiler Tube Failures in Fossil Plants,EPRI Report TR-109938, 1998.

16. W. T. Bakker, J. L. Blough and W. W. Seitz, (2001), Low-NOx Combustion Systems andSuperheater Corrosion- Is there a Connection?" Paper 01168, NACE 2001, HoustonTexas March 11-16 2001.

17. Sumitomo Metal Industries Ltd (1989), "Steam Oxidation on Cr-Mo-Steel Tubes, PaperNo. 805, 1443A.

18. R. Blum, J. Hald, W. Bendick, A. Rosselet and J. C. Vaillant, (1994), "NeuentwicklungenHochwarmfester Ferritisch-Martensitischer Stähle aus den USA, Japan und Europa" VGBKraftwerkstechnik, Vol. 74, No. 8 (1994), pp 641-652.

19. N. Naylor, P. Bontempi, G. Maciga and M. Livragi, (1994), “Creep and FatigueCharacteristics of Advanced 9Cr Steel- Base and Welds”, in “Materials for AdvancedPower Engineering 1994” Proceedings of a Conference held in Liège, Belgium, 3-6October 1994. Edt. Coutsouradis, D. et al. Kluwer Academic Press, (1994), pp 341-350

20. B. Davidson, D. B. Meadowcroft, and J. Stringer, "High Temperature AlloyRequirements for Coal Fired Combined Cycles", CEGB TPRD Report No.TPRD/L/3123/R87, 1987.

21. Report on EPRI Contract CS-3511, 1984.22. J. Oakey, A. Minchener and N. Hodges, (1991), "The Use of High Chlorine Coals in

Industrial Boilers" in "Chlorine in Coal", Eds. Stringer J and Banerjee D B, ElsevierScience Publishers, pp 250-274, 1991.

23. J. Stringer, J. Stallings and W. Bakker, (1991), "Materials' Issues in CirculatingFluidised Bed Combustion Systems", Conference on Fluidised Bed CombustionSystems, London, pp 39-50, December 1991.

24. B-M. Steenari, O. Lindqvist and B. A. Andersson, (1999), "PreliminaryCharacterisation of Deposits Formed on Superheater Surfaces in an FBC Boiler Firedwith Municipal Solid Waste", Proceedings of the ASME 15th International Conferenceon Fluidised Bed Combustion, Savannah, May 1999.

25. N. G. Soloman, (1998), "Erosion Resistant Coatings for Fluidised Bed Boilers",Materials Performance, Vol. 37, No. 2, 1998, pp 38-43.

26. I. Rasmussen, I. Hundebol, and L. Hogh Sorensen, (1997), "The ELASM Coal andBiomass CFB Power Plant Project", VGB Kraftwerkstechnik, Vol. 77, No. 6, p429-432.

27. V. Sethi and I. Wright, (1993), "Materials Support for EPRI Fluidised Bed CombustionProgram", EPRI Report TR-101804, Vol. 1, May 1993.

32 of 108

28. W. Bakker, M. Liebhard and D. Brekke, (1993), "Erosion of Refractories in CFBC's:Effect of Bed Materials and Refractory Properties: A Laboratory Study", 12th ASMEInternational Conference on Fluidized-Bed Combustion, 1993.

29. S. Brain and E. Rodgers, (1987), "Experience of Erosion of Metal Surfaces in UK FluidBed Boilers" presented at EPRI/Argonne National Laboratory Workshop on Wastage ofIn-Bed Surfaces in Fluidized Bed Combustors, Argonne, Illinois, 1987.

30. A. J. Minchener, P. J. I. Cross, T. N Smith and M. J. Fisher, (2000), "Fluidised BedCombustion Systems for Power Generation and other Industrial Applications", CREGroup Limited, Report No. COAL R188, DTI/Pub URN 00/743.

31. F. Belin, S. Kavidass, M. Maryamchik, D. J. Walker, A. K. Mandal and C. E. Price,(1999), "Update of Operating Experience of B&W IR-CFB Coal-Fired Boilers",Proceedings of the ASME 15th International Conference on Fluidised Bed Combustion,Savannah, May 1999.

32. R. Zychal and S. Darling, (1990), in "Proceedings: Workshop on Materials' Issues inCirculating Fluidized-Bed Combustors", EPRI Report No. GS-6747, 1990.

33. W. Z. Nowak, J. Laskawiec, W. Krzywoszynski and R. Walkowiak, (1999), "Designand Operation Experience of 230MWe CFB Boilers at Turow Power Plant in Poland",Proceedings of the ASME 15th International Conference on Fluidised Bed Combustion,Savannah, May 1999.

34. B. Wang, (1997), "The Dependence of Erosion-Corrosion on Carbide/Metal MatrixProportion for HVOF Cr3C2-NiCr Coatings", Proceedings of Surface ModificationTechnologies XI, Paris, Sept 1997

35. A. Verstak, B. Wang, V. Baranovski and A. Beliaev, (1998), "Composite Coatings forElevated Temperature Erosion-Corrosion Protection in Fossil-Fuelled Boilers",Materials and Components in Fossil Energy Applications, No. 135, August 1 1998, pp7-11.

36. D. L. Pearce, (1999), "To the Advanced Coal Steering Group: The 6th InternationalConference on Circulating Fluidised Beds, Würzburg August 22-27 1999", PTC ReportNo. PT/99/BA1350/M.

37. P. Tarkpea, (1998), "Coatings as Protective Barriers in Fluidised Beds", VaermeforskService AB, SE-101 53 Stockholm, Sweden, Report No. SVF-656.

38. S. Arends, (1999), "Thermal Spraying Against Wear and Corrosion", Praktiker, Vol. 51,No. 11, 1999, pp 448-450.

39. Y. Dutheillet and V. Prunier, (1998), "Evaluation of the Erosion-Corrosion Resistanceof Coated Metallic Materials for CFBC's Application", Energy Technology, Vol. 5, No.2, 1998, pp 779-787.

40. J. M. Bursi, L. Lafanerchere and L. Jestin, (1999), "Basic Design Studies for a 600MWeCFB Boiler (270b, 2 x 600ºC)", Proceedings of the ASME 15th International Conferenceon Fluidised Bed Combustion, Savannah, May 1999.

41. T. Elliot, (1994), "Shoot for More Durable, Less Costly Refractory in CFB Units",Power, February 1994, pp 69-71.

42. Z. Junfu Ljiansheng, L. Qing, L. Xiaoma, L. Jiling, Z, Xiaoxing, L. Yi, Y. Long, L.Xudong, and L. Zhengyl (1999), "The progress of the Water Cooled Separator CFBBoiler in China’, Proceedings of the ASME 15th International Conference on FluidisedBed Combustion, Savannah, May 1999.

43 M. G. Alliston, T. Luomaharju and A. Kokko, (1999), "Improved Water-CooledCyclone Constructions in CFBs", Proceedings of the ASME 15th InternationalConference on Fluidised Bed Combustion, Savannah, May 1999.

44. S. L. Darling, (2000), "Foster Wheeler’s Compact CFB; Current Status", FosterWheeler Technical Papers, www.fwc.com/publications/tech_papers/powgen/compact.cfm.

45. UNIPEDE (1995), “Pulverised Coal-Fired Power Plants with Advanced SteamConditions” UNIPEDE Thermal Generation Study Committee 20.01 Thermoprocess,Group of Experts: New and Advanced Processes for Electricity Generation, June 1995,Ref 02001Ren9519.

33 of 108

46. F. Masayuma, T. Yokoyama, Y. Sawarages and A. A. Iseda, (1994), “Development of aTungsten Strengthened Low Alloy Steel with Improved Weldability”, in “Materials forAdvanced Power Engineering 1994” Proceedings of a Conference held in Liège,Belgium, 3-6 October 1994. Edited by Coutsouradis, D. et al. Kluwer Academic Press,(1994), pp 173-181.

47. R. U. Husemann, W. Bendick, K. Haarmann, J. Heeschen and A. Helmrich, (2000),‘The New 7CrMoVTiB10-10 Material (Part 2) For Boiler Membrane walls’, VGBPowerTech 7/2000.

48. M. Staubli, W. Bendick, J. Orr, F. Deshayes and Ch Henry, (1998), "EuropeanCollaborative Evaluation of Advanced Boiler Materials" in "Materials for AdvancedPower Engineering 1998" Proceedings of a Conference held in Liège, Belgium, 5-7October 1998. Edited by Lecomte-Beckers, J. et al. Forschungszentrum Jülich Gmbh(1998) pp 87-104.

49. E. Metcalfe and B. Scarlin, (1998), "High Temperature Forged Components for AdvancedSteam Power Plants" in "Materials for Advanced Power Engineering 1998" Proceedingsof a Conference held in Liège, Belgium, 5-7 October 1998. Edited by Lecomte-Beckers,J. et al. Forschungszentrum Jülich Gmbh (1998) pp 53-70.

50. F. Masuyama and N. Komai, (1998) "Effect of Re Addition on the Creep Strength of HeatResistant Cr-W Steels", in "Materials for Advanced Power Engineering 1998"Proceedings of a Conference held in Liège, Belgium, 5-7 October 1998. Edited byLecomte-Beckers, J. et al. Forschungszentrum Jülich Gmbh (1998) pp 269-276.

51. C. J. Franklin and C. Henry, (1994), “Materials Developments and Requirements forAdvanced Boilers” in “Materials for Advanced Power Engineering 1994” Proceedings ofa Conference held in Liège, Belgium, 3-6 October 1994. Edited by Coutsouradis, D. et al.Kluwer Academic Press, (1994), pp 89-107.

52. Y. Sawaragi, A. Iseda, K. Ogawa and F. Masayuma, (1994), “Development of a HighStrength 12Cr Steel (HCM12A)”,in “Materials for Advanced Power Engineering 1994”Proceedings of a Conference held in Liège, Belgium, 3-6 October 1994. Edited byCoutsouradis, D. et al. Kluwer Academic Press, (1994), pp 309-318.

53. Ikezhima, (1983) Bulletin of the Japanese Institute of Metals, Vol 22, No. 5, (1983).54. R. Blum, J. Hald, W. Bendick, A. Rosselet and J. C. Vaillant, (1994) ."Neuentwicklungen

Hochwarmfester Ferritisch-Martensitischer Stähle aus den USA, Japan und Europa" VGBKraftwerkstechnik, Vol. 74, No. 8, (1994) pp 641-652.

55. B. Rukes, W. Vollmer and E. Wittchow, (1994), “Power Plants With High SteamPressures and Temperatures – Matched Design of Steam Turbine and SteamGenerator”, VGB Kraftwerkstechnik 74 (1994), Number 5, p5.

56. C. W. Wegst, (1998), “Stahlschlussel (Key to Steel)”, p300. Verlag Stahlschlussel WegstGmbH, 1998.

57. F. Abe, M. Igarashi, N. Fujitsuna, K. Kimura and S. Munecki,. (1998), Research andDevelopment of Advanced Ferritic Steels for 650ºC USC Boilers" in "Materials forAdvanced Power Engineering 1998" Proceedings of a Conference held in Liège, Belgium,5-7 October 1998. Edt. Lecomte-Beckers, J. et al. Forschungszentrum Jülich Gmbh(1998) pp 269-276.

58. P. Eggerstedt and J. Zievers, (1999), "High Temperature Particulate Removal UsingRecrystallised Silicon Carbide Candle Filters", High Temperature Gas Cleaning, Vol. 2,1999, pp 375-383.

59. T. E. Lippert, G. J. Bruck, R. A. Newby, D. M. Bachovchin, V. L. Debski and H. T.Morehead, (1997), "Westinghouse Hot Gas Particle Filter System", Proceedings of the14th International Conference on Fluidised Bed Combustion, Vol. 2, Vancouver, May1997.

60. J-F. Lecostaouec, (1999), "3D Braided Fibre Reinforced Ceramic Hot Gas Filters",High Temperature Gas Cleaning, Vol. 2, 1999, pp 428-441.

61. J. D. Spain and H. S. Starret, (1999), "Characterisation of Monolithic and CompositeFilter Elements", High Temperature Gas Cleaning, Vol. 2, 1999, pp 414-427.

34 of 108

62. T. Tamura, T. Sato and Y. Fukuda (1995), “High Temperature Strengths and SteamOxidation Properties of New 9~12%Cr Ferritic Steel Pipes for USC Boilers” 2ndInternational Conference on Heat-Resistant Materials 11-14, September 1995, Gatlinburg,Tennessee, USA.

63. R. Vanstone, (2000), "Advanced 700oC Pulverised Fuel Power Plant" Proc. 5th Int.Charles Parsons Conf: Parsons 2000 Advanced Materials for 21st Century Turbine andPower Plants. Edited by A. Strang, R. D. Conroy, G. M. McColvin, C. Neal and S.Simpson. IOM Communications, London, Book 736 (2000).

35

{PRIVATE }Table 3.1.1. Chemical Compositions of Boiler Tube Materials

{PRIVATE }MATERIAL C Si Mn P S Al Cr Ni Mo V Nb W N Cu(Ce)

Ti B

15Mo3(1.5415)

0.120.20

0.100.35

0.400.90

max0.035

max0.03

- - - 0.250.35

- - - - - - -

13CrMo44(1.7335)

max0.15

max0.50

0.300.61

- - - 0.801.25

- 0.440.65

- - - - - - -

T22 (10CrMo910)(1.7380)

0.080.15

max0.50

0.300.60

- - - 1.902.60

- 0.0871.13

- - - - - - -

T23 (HCM2S) 0.040.10

max0.50

0.300.60

max0.03

max0.01

<0.03(sol)

1.902.60

- max0.30

0.200.30

0.020.08

1.451.75

max0.03

- - max0.006

T24 (7CrMoVTiB10-10) 0.05

0.10

0.15

0.45

0.30

0.70

Max

0.02

Max

0.01

Max

0.02

2.20

2.60

- 0.90

1.10

0.20

0.30

- - Max

0.012

- 0.05

0.10

0.0015

0.0070

P 91/T 91(X10CrMoVNb91) (1.4903)

0.080.12

0.200.50

0.300.60

max0.02

max0.01

max0.040

8.509.50

max0.40

0.851.05

0.180.25

0.060.10

- 0.050.08

- - -

E 911 0.090.13

0.100.30

0.300.60

max0.02

max0.01

max0.025

8.509.50

0.100.35

0.901.10

0.150.25

0.060.10

0.901.10

0.050.08

- - -

P92 (NF 616) max0.15

max0.50

max1.00

max0.02

max0.01

- 8.0013.00

- max1.00

0.100.30

max0.10

1.502.50

0.020.15

- - max0.01

HCM 12 max0.12

max0.50

0.300.70

max0.03

max0.03

- 11.013.0

- 0.801.20

0.200.30

max0.20

0.801.20

- - - max0.01

P122 (HCM12A) 0.060.14

max0.70

max0.70

max0.03

max0.02

- 10.0012.60

max0.70

0.200.60

0.150.30

0.020.10

1.502.50

0.020.10

0.301.70

- max0.005

X20CrMoV121(1.4922)

0.170.23

max0.50

max1.00

max0.03

max0.03

- 10.0012.50

0.300.80

0.801.20

0.250.35

- - - - - -

E1250 0.050.15

0.300.75

5.507.00

max0.03

max0.03

- 14.0016.00

9.0012.00

0.801.20

0.150.40

0.751.20

- - - max0.05

0.0030.009

12R72X10CrNiMoTiB1515

0.080.12

0.300.80

1.502.00

max0.03

max0.02

- 14.0016.00

14.0016.00

1.001.40

- - - - - 0.300.60

0.0040.008

17-14CuMo 0.11 - - - - - 15.9 14.5 2.5 - 0.43 - 0.01 3.10 0.24 -

X8CrNiMoVNb1613(1.4988)

0.040.10

0.300.60

max1.50

max0.035

max0.015

- 15.5017.50

12.5014.50

1.101.50

0.600.85

max10xC

- - - - -

36

Table 3.1.1. (Continued) Chemical Compositions of Boiler Tube Materials

{PRIVATE }MATERIAL C Si Mn P S Al Cr Ni Mo V Nb W N Cu(Ce)

Ti B

X8CrNiMoNb1616(1.4981)

0.040.08

0.300.60

max1.50

max0.035

max0.015

- 15.5017.50

15.5017.50

1.602.00

- max10xC

- - - - 0.08

X3CrNiMoN1713(1.4910)

max0.04

max0.75

max2.00

max0.035

max0.015

- 16.0018.00

12.0014.00

2.002.80

- - - 0.100.18

- - -

AISI T316 max0.08

max1.00

max2.00

max0.03

max0.045

- 16.0018.00

10.0014.00

2.003.00

- - - - - - -

AISI T321 max0.08

max1.00

max2.00

max0.03

max0.045

- 17.0019.00

9.0012.00

- - - - - - 5 x C -

AISI T347 max0.08

max1.00

max2.00

max0.03

max0.045

- 17.0019.00

9.0013.00

- - 10 x C - - - - -

AISI T304 max0.08

max1.00

max2.00

max0.03

max0.045

- 18.0020.00

8.0012.00

- - - - - - - -

Super 304 0.070.13

max0.30

max1.00

max0.04

max0.010

- 17.0019.00

7.5010.50

- - 0.300.60

- 0.050.12

2.503.50

- -

NF709 max0.20

max1.00

max1.50

max0.03

max0.010

- 18.0022.00

22.0028.00

1.02.0

- 0.100.40

- 0.050.20

- 0.020.20

0.0020.010

Alloy 800 max0.10

max1.00

max1.50

max0.015

- 0.150.60

19.0023.00

30.0035.00

- - - - - max0.75

0.150.60

-

AISI T310 max0.25

max1.50

max2.00

max0.03

max0.045

- 24.0026.00

19.0022.00

- - - - - - - -

Valinox T310N 0.050.07

0.300.50

1.001.40

max0.01

max0.025

- 24.4025.00

20.6021.50

max0.20

- 0.400.50

- 0.180.24

max0.20

- -

HR3C(1.6974)

0.040.10

max0.75

max2.00

max0.03

max0.030

- 24.0026.00

17.0023.00

- - 0.20.6

- 0.150.35

- - 0.005

HR6W max0.10

max1.00

max2.00

max0.030

max0.030

- 21.0025.00

35.0045.00

- - max0.40

4.008.00

- - max0.20

-

AC66 (1.4877) 0.040.08

max0.30

max1.00

- - max0.025

26.0028.00

31.0033.00

- - 0.61.0

- - (0.05)(0.10)

- -

37

Table 3.1.2. T23 - Allowable Stresses for 105h Operation

Temperature, C Allowable Stress,MPa

400 124450 117500 111525 105550 87575 71600 56

Table 3.1.3. 7CrMoVTiB10-10 (T24), Allowable Stresses for 105h Operation

Temperature, C Allowable Stress,MPa

400 131450 126500 117525 112550 95575 67600 39

Table 3.1.4. P92, Allowable Stresses for 105h Operation

Temperature, C Allowable Stress,MPa

399 132454 126510 116538 110566 103593 94621 70649 48

Table 3.1.5. P122, Allowable Stresses for 105h Operation

Temperature, C Allowable Stress,MPa

399 134454 127510 118538 112566 104593 89621 64

38

Table 3.1.6. NF709, Allowable Stresses for 105h Operation

Temperature, C Allowable Stress,MPa

450 130500 125550 120600 117650 82700 57

Table 3.1.7. HR3C, Allowable Stresses for 105h Operation

Temperature, C Allowable Stress,MPa

500 108600 105650 75700 45

Table 3.1.8. Installation of Trial Header and Pipes in COST 501

Station Material Size Component Manufacturer Steam InstalledID Wall

Vestkraft Unit 3 NF616 240 39 Straight pipe Main steam Japan 560°C/250 bar 1992

Nordjyllandsvaerket NF616HCM12A

160 45 Header Japan 582°C/290 bar 1996

Schkopau Unit B E911 550 24 Induction bend hot reheat M, V&M 560°C/70 bar 1996

Staudinger Unit 1 E911 201 22 Induction bend main steam M, V&M 540°C/213 bar 1996

Skaerbaek Unit 3 E911 230 60 Induction bend main steam M, V&M 582°C/290 bar 1996

GK Kiel P92 480 28 Header MannesmannröhrenwerkDüsseldorf-Reisholz

545°C/53 bar 1997

VEW E911 23.8 4 Superheater M, V&M 650°C 1998

Westfalen E911 159 27 Steam Loop M, V&M 650°C/180 bar 1998

Westfalen P92 159 27 Steam Loop M, V&M 650°C/180 bar 1998

Avedoere 2 P92 Headers and steam lines 580/600300 bar

2000

Table 3.1.9. X3CrNiMoN1713, Allowable Stresses for 105h Operation

Temperature, C Allowable Stress,MPa

550 147600 94650 55700 34

39

300

250

225

185535 560 600 650

-14

-12

-10

-8

-6

-4

-2

-0

Live steam pressure (bar)

Live steam/reheat temperature (oC)

Imp

rove

men

t in

hea

t ra

te (

%)

- 4.20- 5.74

- 7.89

- 10.14

- 8.41

- 9.24

- 8.62

- 7.30

- 5.14- 3.23

- 1.88

Wnet

Wnet

Figure 3.1.1 Improvements in Power Plant Heat Rate with Increases in Temperature and Pressure to theTurbine1

43.244.5 45.2 45.6

47.748.5

49 49.8 50.2

38

40

42

44

46

48

50

52

250/540/560Staudinger 5

Current status250/580/600P91 used

300/600/620NF616 used

315/620/620austenitics used

370/700/720Nickel alloys (Thermie)

Double reheat

Improved boiler layout

Reduced boiler pressure drop

Cold end heat recovery

Figure 3.1.2 Potential Power Plant Efficiency Gains from the Utilisation of New Materials and CycleImprovements

40

BULK GAS TEMPERATURE

BULK STEAM/WATERTEMPERATURE

ST

EA

M/W

AT

ER

FIL

M

TUBE WALL BO

RE

OX

IDE

GA

S F

ILM

OU

TE

R O

XID

E/F

OU

LIN

G

Figure 3.1.3 Schematic Diagram of the Temperature Gradients through Boiler Tube Walls for Design

500

250

100

50

0100 200 300 400 500 600

MINIMUM TENSILE STRENGTH

MINIMUM 0.2% PROOF STRESSOR LOWER YIELD STRESS

DESIGN CURVEINCORPORATING SAFETY FACTOR

MEAN STRESS FORRUPTURE IN 100,000h

TEMPERATURE oC

ST

RE

SS

(MP

a)

Figure 3.1.4 Relationship between Measured Proof and Allowable Design Stresses for Plain CarbonSteel

41

580 590 600 610 620 630 640 650 660

200

150

50

100

0

CO

RR

OS

ION

RA

TE

(n

m.h

ou

r-1)

SURFACE METAL TEMPERATURE (oC)

Tg = 900o C

Tg = 1000o C

Tg =

1100o C

Tg =

1200o

C

Figure 3.1.5 Fireside Corrosion Rate of Austenitic Superheater/Reheater Materials as a Function ofGas and Metal Temperature.

Figure 3.1.6 Breakdown of Highly Protective Chromia Scale (right) on 12%Cr Steel to produceDuplex Scale Nodules (left)

42

800

700

600

500

400

300

200

100

0

0 20 40 60 80 100 120 140 160 180 200

BO

RE

SC

AL

E T

HIC

KN

ES

S (

m)

EXPOSURE TIME (103 hours)

1% & 2% Cr @ 600oC

1% & 2% Cr @ 560oC

9% Cr @ 560oC

9% Cr @ 600oC

12% Cr @ 600oC

12% Cr @ 560oC

Figure 3.1.7 Anticipated Bore Oxide Scale Thickness as a Function of Material, Temperature andOperating Hours for Low-medium Cr Superheater Tube Materials17.

50

40

30

20

10

0

0 20 40 60 80 100 120 140 160 180 200

TU

BE

WA

LL

TE

MP

ER

AT

UR

E IN

CR

EA

SE

(oC

)

EXPOSURE TIME (103 hours)

9Cr @ 600oC

12Cr @ 600oC

9Cr @ 560oC

12Cr @ 560oC

Figure 3.1.8 Increase in Tube Wall Tube Wall Temperature as a result of Increasing Bore ScaleThickness17.

43

0 100 200 300 400 500 600

40

30

20

10

0

TEMPERATURE oC

TH

ER

MA

L C

ON

DU

CT

IVIT

Y (

W.m

-1.K

-1)

10CrMoV121

P91

X20CrMoV121

X3CrNiMoN1713

Figure 3.1.9 Thermal Conductivity of Some Current and Proposed Header and Steam SeparatorMaterials18.

X20CrMoV121

P91

10CrMo910

X3CrNiMoN1713

20

18

16

14

12

100 100 200 300 400 500 600

ME

AN

CO

EF

FIC

IEN

T O

F L

INE

AR

TH

ER

MA

L E

XP

AN

SIO

N

1

0-6

BE

TW

EA

N 2

0oC

AN

D IN

DIC

AT

ED

TE

MP

ER

AT

UR

E

To

K

TEMPERATURE oC

Figure 3.1.10 Mean Coefficient of Linear Expansion for some Current and Proposed Header and SteamSeparator Materials18.

44

0

20

40

60

80

100

120

140

160

500 525 550 575 600 625 650

Temperature ( oC)

Allo

wab

le S

tres

s V

alu

es (

MP

a)

HCM12A

HCM12

T91

HCM2S

X20CrMoV121

T22

Figure 3.1.11 Comparison of Allowable Stress Values for 2 to 12% Cr Steels

0

20

40

60

80

100

120

140

160

400 450 500 550 600 650

Temperature ( oC)

Allo

wab

le S

tres

s (M

Pa)

T22

T23

T24

T91

Figure 3.1.12 Design Values for T23/T24 Compared to Other Grades

45

1 17-14 CuMo

2 AN31

3 E1250

4 12R72

5 15-15N

6 TP321H

8 TP347H (MITI)

9 TP347H (Fine Grain)

10 800H

11 807

12 617

13 625

14 310S

15 HK4M (35)

16 HR3C

17 SZ (36)

18 35 Cr-54 Ni-Nb

19 40 Cr-50 Ni-Fe

20 in-671

21 ChromisedWE

IGH

T L

OS

S (

mg

.cm

-2)

CHROMIUM CONTENT (%)

15

0 10 20 30 40 50 60

50

40

30

20

10

0

12

34

5

6

7

8

10

11

1213 14

16

17

1819

20

21

9

Figure 3.1.13 Metal Loss Rate as a Function of Cr Content for Higher Cr Materials under SimulatedFireside Corrosion Conditions54.

66

NF616

P91

X20

46

97

Figure 3.1.14 Comparison of Relative Wall Thickness Requirements for Main Steam Pipework for300bar/580ºC Duty Manufactured from X20, P91 and P92 Steels45.

46

SUPERHEATER OUTLET TEMPERATURE (oC)

110

100

90

80

70

60

50

40

540 550 560 570 580 590 600

HE

AD

ER

WA

LL

TH

ICK

NE

SS

(m

m)

X20CrMoV121

300bar

260barP91

300bar

260bar

1.4910

300bar

260bar

Figure 3.1.15 Calculated Wall Thickness for Final Superheater Outlet Headers at 260 and 300 bar as aFunction of Material and Operating Temperature11.

SUPERHEATER OUTLET TEMPERATURE ( C)o

RA

TE

OF

TE

MP

ER

AT

UR

E C

HA

NG

E ( C

.min

)o

-1

P91

X20CrMoV121

1.4910

300 bar

260 bar

260 bar

300 bar

260 bar

300 bar

Figure 3.1.16 Acceptable Rates of Temperature Change for Header Materials11

47

STEAM TEMPERATURE AHEAD OF TURBINE ( C)o

PR

ES

SU

RE

AH

EA

D O

F T

UR

BIN

E (b

ar)

ID = 140mm

Wall = 70mm

Range of Application for 1.4910Steel

Figure 3.1.17 Application Limits for the Use of 1.4910 Austenitic Steel in the Superheater OutletHeaders of Supercritical Plant11.

2.25%Cr1%

Mo

0.02%Si

0.11%Si

0.25%Si

0.44%Si

0.57%Si

0.78%Si

Figure 3.1.18 Steamside Oxidation Rate of NF616 at 650°C as a Function of Si-content62.

48 of 108

3.2 Steam Turbines

3.2.1 Steam Turbine Market Trends

Steam turbines are an essential part of all combustion-based power generation technologies. Atsome point in the cycle, all of these technologies raise steam whose energy is converted via asteam turbine. The materials issues related to the steam turbine depend largely on thetemperature and pressure of the steam generated and, as such, are almost independent of thesteam raising technology employed.

At the current time steam turbines serve two principal fossil-fired technology markets:• Coal-fired plant based on PF or CFB combustion technology. For utility-scale generation

this may require steam turbines with outputs up to 800MWe.• Gas-fired plant incorporating a combined cycle where the exhaust gas from a gas turbine is

used to raise steam. To match the lower power output of the gas turbine, steam turbines forthese applications have outputs typically in the range up to 250MWe.

At the moment the second of these markets is dominant. The “dash for gas” in the UK is beingreplicated to a greater or lesser extent in markets around the world, of which the NorthAmerican market has recently been the most buoyant. The use of gas has significantly displaceddemand for new coal-fired plant over recent years. Nonetheless concerns over security of supplyand over the volatility of gas prices have led many utilities, both in Europe and the USA, tobegin re-examining the potential for coal-fired generation.

In addition to the construction of new plant, an important subset of the first market is retrofitturbines. Advances in the internal efficiency of steam turbines have made it economicallyattractive to replace elements of older turbines with improved modern turbine components. Theadvantage can be taken to reduce fuel consumption or increase power output.

3.2.2 Steam Turbine Development Trends

Steam turbine development trends fall into two categories:

1. Improvements in the internal efficiency of the steam turbine. These developmentslargely focus on improved aerodynamic performance, sealing and cylinderconfiguration:• Improved aerodynamics to reduce losses in the steam path, including valves, blades and

cylinder exhausts.• Improved sealing to reduce steam leakage flows.• Improved cylinder configuration to minimise the number of steam flows and thus

minimise losses associated with flow over steam path surfaces. This essentially involvesthe extension of single flow concepts as far as possible rather than the use of doubleflow cylinders. It is linked to increasing the exhaust area of LP cylinder flows throughthe introduction of longer blades.

Category 1 improvements bring benefits to the whole range of technologies served by the steamturbine and they have provided the basis for the current retrofit market. Advanced materialshave played, and continue to play, a role in this area, for example through:

• The introduction of stronger or less dense blading alloys enabling more efficient steampath arrangements.

49 of 108

• The introduction of rotor materials with the necessary combination of high temperaturecreep resistance and low temperature fracture toughness to enable the construction ofsingle-flow, single cylinder steam turbines.

2. Improvements in the cycle efficiency. These developments focus on increasing steamtemperatures and pressures so as to increase the thermal efficiency of the overall cycle.

Category 2 improvements are focused much more on steam turbines for coal-fired plant wherethere are clear advantages in elevating temperature and pressure to increase thermal efficiencyand reduce emissions. In combined cycle plant, the drivers for increased temperature in thesteam turbine are low. Here the steam turbine inlet temperature is largely dependent on gasturbine exhaust temperatures and there is no great thermodynamic benefit in elevating thisexhaust temperature. Currently these steam turbines operate with inlet temperatures of up to565oC but there is no great driver for increasing this temperature. Improvements in temperatureand pressure capability for coal-fired plant are almost entirely dependent on improvements inmaterials technology through:

• Development of alloys with creep resistance at higher temperatures• Development of alloys or surface treatment technologies with steam oxidation

resistance at higher temperatures

The drivers for steam turbine development for current coal-gasification based power generationcycles are similar to those for gas-fired combined cycle plant, where superheating is limited tothe exhaust gas from the gas turbine. However, if methods of superheating in the hightemperature fuel gas or supplementary superheating stages are provided, then these systemscould take advantage of the higher steam conditions being used in PF plant.

3.2.3 Steam Turbine Design and Operation

The first sixty years of the twentieth century witnessed progressive increase in operatingtemperatures and pressures. In the 1950s the continuation of this trend to temperatures of 540-565oC was enabled through the introduction of a generation of creep-resistant low alloy steels,such as the 1%CrMoV rotor forging alloy. A generation of 12%Cr alloys was developed forblading applications and it remains the practice to use these alloys throughout the turbine.

This trend reached its peak in the early 1960s when operating temperatures were raised to 593oCat the Drakelow plant in the UK and even to 649oC in the Eddystone plant in the USA.Austenitic stainless steels were applied to critical turbine components such as the valve chestand rotor forgings. However service experience with these plants was not successful eventhough some continue to operate to the current day. Austenitic steels have a poor combination ofphysical and mechanical properties to withstand thermal cycling: their high coefficients ofthermal expansion, low thermal conductivities and low yield strengths mean that thermal cyclesresult in high thermal gradients in thick section components, leading to stresses which canexceed yield. This resulted in poor dimensional stability in thick section components and one ofthe Drakelow boilers collapsed. Continued operation has only been possible through the use ofcareful warming of valve chests in preparation for start-up.

As a result of this experience, steam turbine conditions retreated to the 540-565oC level andremained at that level for the next 30 years. The majority of this plant operated under sub-critical conditions with pressures of around 180bar but in Europe and in the USA several plantswith higher super-critical pressures of around 250bar were built.

Only with the development of more creep resistant martensitic stainless steels, starting with thedevelopment of P91 in the late 70s and early 80s, was a further advance in steam conditionsconsidered. In Japan a series of plants have been built or are under construction with steamconditions of up to 610oC. In Europe the double reheat Danish plants at Skaerbaek and

50 of 108

Nordjlland with conditions of 580oC/580oC/580oC/285bar were followed by the construction ofthe Lippendorf plant with a reheat temperature of 585oC and the Avedore plant with a reheattemperature of 600oC. Siemens is carrying out a design study for a plant at Westfalen with evenhigher temperatures. In Europe the increase in temperature has been coupled with an increase inpressure but in Japan pressures have remained at the level of 240bar (Figure 3.2.1).

In Europe, Japan and the USA, development programmes are now in place to elevate operatingtemperatures to beyond 700oC through the application of nickel based alloys. Commissioning ofthe first of such plant is foreseen in the years around 2010.

As well as operation under steady load, steam turbines are often operated under daily stop-startcycles (two-shifting) so that an ability to withstand such cycling is required and is specified bycustomers. Modern plant is generally more efficient than older plant and may operate under abase-load regime early in its life but later, as still more advanced plant is built, it may beoperated under cycling conditions.

3.2.4 Steam Turbine Materials – State of the Art

A review of materials developments for steam turbines is incorporated in the literature review(Annex 1). In addition excellent review papers have been published in recent years1,2,3,4

An important driver for all areas of steam turbine development is the issue of cost. The steamturbine market is an extremely competitive one and the manufacturers are under constantpressure to reduce costs. This contributes to developments that simplify turbine architecturesuch as the development of single cylinder machines and also to the application of cheapermaterials. An example is the development of cast irons to replace cast steels.

Steam Turbine Applications

Advanced PF Plant

The current generation of ultra-supercritical (USC) PF plant being constructed in Japan andEurope is based on a generation of improved martensitic stainless steels developed for steamturbine applications in the 1980s and early 1990s. Rotor forgings are based on 9-10%CrMoVNbN steels, the main alloys currently being applied having either a Mo addition of1.5% or an addition of up to 1.0%W in partial substitution of the Mo content. V and N contentshave been optimised to provide precipitation strengthening through a dispersion of VN particlesand a low level of Nb is incorporated to control grain size during high temperature heattreatments. Castings for valve chests and cylinder casings exploit analogous alloys, generallywith lower C content to provide improved weldability. Blading alloys are similar to the rotorforging alloys. Meeting the requirements of bolts operating at the very highest temperatures hasfrequently required the exploitation of Ni-based alloys such as Nimonic 80A or Refractalloy 26.

The temperature at which 100,000 hour rupture strength is around 100MPa is a reasonableindicator of the maximum application temperature of steam turbine materials. The alloyingdevelopments described above have led to increases in this temperature of around 50-70oC(Figure 3.2.2). Even more advanced B containing steels have been developed and demonstratedas full scale forgings in both Japan and Europe. To provide higher oxidation resistance, alloyswith higher Cr levels (11-12%) have also been developed: in order to balance the compositionof these alloys to avoid delta ferrite formation, additions of cobalt have been made. However,these more advanced alloys have not yet been applied in service.

51 of 108

In support of the development of steam turbines for temperatures greater than 700oC,development of nickel based alloys for application to critical steam turbine components iscurrently in progress5.

Retrofit Plant

In some cases the alloys developed for the USC plant have also provided benefits for retrofitplant. For example higher allowable stresses in advanced blading steels have enabled theincorporation of additional stages in retrofit turbines leading to higher efficiency.

Steam Turbines for Combined Cycle Plant

To a large extent, it has been possible to base steam turbines for combined cycle plant, withtheir modest steam conditions, on the conventional low alloy steels used since the 1950s.However opportunities have been found for the more advanced steels to improve performanceor reduce cost. For example the use of 10%CrMo(W)VNbN steels for rotor forgings can lead toimproved cycling resistance4 and the use of newly developed low alloy steels has enabled theconstruction of single cylinder machines with advantages in performance and cost.

Materials Sources

The most critical components for steam turbines are manufactured from the following productforms:• Large forgings for rotors• Smaller forgings for diaphragm construction, valve components and larger blades• Bar for blades and bolts• Castings for valve chests and cylinder casings

The main sources of these materials for UK plant manufacturers are in the UK and in the rest ofthe European Union. Nonetheless there is a growing trend to source materials from low costcountries such as those of Eastern Europe and for contracts in Asia there is a commoncontractual requirement to use local material suppliers. In addition Japanese suppliers areoccasionally used for supply of large rotor forgings. Despite these trends, UK material suppliersstill play a major role in the supply of materials to UK turbine manufacturers and also to turbinemanufacturers in other countries. Examples include:• Sheffield Forgemasters Engineering Ltd: rotor forgings and castings• Hi-Tec: castings• Goodwin Steel Castings: castings• Corus: blading and bolting bar• Allvac SMP: blading and bolting bar• Firth-Rixon: small forgings• Walter Somers: small forgings• International Forgemasters: small forgings

Repair, Maintenance, Life Assessment

Many steam turbine components have been constructed from steels which are inherentlyweldable. Therefore ready means of repair through welding are available. Advances in weldingtechnology have extended the range of alloys considered weldable. At one time 1%CrMoV rotorsteels were considered unweldable but today welding procedures have been developed to extendthe life of these components6.

In components where NDE has revealed no defects, the first stage of life assessment is generallybased on application of the most recent design and stress analysis techniques. This may berefined by materials testing on the component in question so that analysis is based on specific

52 of 108

component properties rather than minimum properties for the alloy. This may be supported bymetallographic examination for evidence of creep or LCF damage. The latter part of thisassessment requires a knowledge of the evolution of microstructure as creep damage or LCFdamage accumulates.

In situations where cracking has been observed, information on creep-fatigue crack growth isrequired for optimum life management.

The application of oxidation resistant coatings in the future will necessitate the development ofmeans of assessing their state of life-exhaustion and of repair procedures.

3.2.5 Steam Turbine Materials R&D

Current Projects

The major projects for development of steam turbine materials in which UK participants areactive are as follows:

COST 522

This programme is a collaborative project involving participants from the UK, other EUcountries and other non-EU countries such as Poland, Switzerland, Czech Republic, Slovakiaand Hungary. The programme covers a wide range of power generation technologies but one ofits major themes is Steam Power Plant (SPP) within which there is a major activity on steamturbine materials7 (Figure 3.2.3). It includes all the major European turbine makers and theirmaterial suppliers. The programme started in 1998 and runs to 2003 although there is apossibility that it will be extended. UK participants in this project are supported via the DTI’sCleaner Coal project. The COST 522 SPP activity’s main objective is the development ofmaterials technology to enable operation of power plants with steam temperatures of 650C.Development is focussed on improving the temperature capability of martensitic stainless steelsand covers:• The development of new 9-12%Cr martensitic stainless alloys for rotor forgings and

casings, the objective being an improvement in the creep strength of alloys previouslydeveloped in COST 501, the forerunner to COST 522, coupled with improvements inoxidation resistance. Testing therefore includes oxidation testing in a range of laboratoryenvironments as well as mechanical testing.

• The development of new high strength bolting alloys with thermal coefficients of expansionmatching those of the 9-12%Cr martensitic stainless steels.

• Metallographic investigation and modelling of the new alloys.

EU Thermie AD700 Project: Advanced 700 C PF Power Plant

This project started in 1998 and is a phased project5 extending to 2014 (Figure 3.2.4). The firstphase, to run until 2003, is receiving support from the EC and, in the case of the UKparticipants, from the DTI’s Cleaner Coal Project. The project involves 40 participants from 7European countries. A second phase of the project has recently been launched with additionalsupport from the EC. This phase of the project will run from 2002 to 2005. The first three yearsof the project resulted in confirmation of the technical and economic feasibility of the conceptwhich fundamentally depends on the application of nickel-based alloys to enable steamtemperatures of 700-720°C. Turbine related activities included the assessment of a range ofcandidate alloys and the manufacture of the first prototype components. The second phase willinclude the extension of the prototype demonstration and characterisation programme.

DTI Cleaner Coal Projects

53 of 108

As well as supporting the involvement of UK participants in the COST 522 and Thermieprojects, funding has been provided for other turbine-related research projects in the areas ofmaterials and aerodynamics.

NPL Life Performance of Materials Programme

NPL has recently launched activities under its Life Performance of Materials programme whichsupport turbine development:• The High Temperature Degradation project includes research into oxidation mechanisms on

a range of steam turbine alloys.• The Aqueous Corrosion project includes research into stress corrosion cracking in steam

turbine materials.These projects began in 2001 and are planned to run for three years.

There are other steam turbine development programmes in Europe from which UK participantsare excluded. In Germany in particular there is strong national funding for the MARKCOprogramme and the VGB is funding the long-term characterisation of advanced 9-12%Crcomponents under its VGB 158 project.

There are also significant development programmes outside Europe. In Japan NIMS isresponsible for a major programme (ABE, Parsons) focussed on the continued development of9-12%Cr steels for 650C steam conditions, the same principal objective of COST 522. Aprogramme funded by the EPDC has also been launched whose objective is 700C steamconditions.

In the USA there are fewer programmes to develop steam turbine technology. NonethelessAmerican turbine makers have access to many of the results of developments in Europe andJapan. Despite the apparently low level of turbine development, there are major initiatives inboiler development, the DOE having just launched a 5- year, $21 million programme to developboiler materials technologies for steam temperatures up to 870oC. EPRI continue to funddevelopment of pipework materials within its project 1403.

UK Strengths and Weaknesses

The UK strengths and weaknesses are addressed in terms of the required capacity for materialsR&D and in terms of the UK’s ability to exploit the results of that R&D.

• Modelling of microstructural evolution during processing and in service, of mechanicalproperties, of oxidation and of the behaviour of oxidation-resistant coatings.The UK research community is competitive in this field. Universities such as Cambridgeand Loughborough have expertise in microstructure and property modelling and participatein COST 522. Other universities such as Imperial College are also active in creepmodelling. NPL have expertise in modelling of oxide and coating behaviour.

• Test capacity for short and long-term mechanical property characterisation: creep testing,low cycle fatigue and cyclic hold testing, fracture toughness testing, creep-crack initiationand growth testing.UK turbine manufacturers such as ALSTOM and larger material suppliers such as Corushave in-house capability for this testing and can call on support from research institutessuch as NPL.

• Test capacity for environmental (steam oxidation) testing, including the influence ofthermal cycling on oxide layers on coatings.NPL and Cranfield University have capacity for laboratory testing. However the correlationbetween laboratory testing and service performance is weak. The UK lacks a capacity for

54 of 108

exposure in operating power stations. Such facilities exist in Denmark and Germany andplace the UK at a disadvantage.

• Manufacturing capacity for trial melts and more significantly for prototype componentsincluding weldments where appropriate.UK forgemasters and foundries have the capability to contribute in this area. SFELmanufactured one of the first COST 501 prototype rotors and Goodwin Steel Castings isactive in the Thermie project.

• Capacity for development of welding consumables.UK suppliers are active participants in COST 522.

• Capacity for coatings resistant to steam oxidation.UK suppliers exist who are capable of contributing in this area. Some are already active insupport of gas turbine coating activities in COST 522.

Although UK universities are strong on modelling, the other areas of research requirements arelargely met by industry itself. In other countries such as Germany, universities and researchinstitutes make a much greater contribution to the short and long-term mechanical testingrequirements, for example providing creep testing facilities at lower costs than available in theUK, especially since these bodies attract government support for these activities.

Many of the strengths of the UK for R&D derive from the capabilities of UK industrialcompanies. It follows that involvement of those material suppliers, turbine makers, coating andconsumable suppliers in R&D projects carries with it an implicit ability for rapid and effectiveindustrial exploitation.

The principal weakness identified in R&D lies with the absence of an environmental test facilityin operating plant. This reflects the UK electricity generators’ absence of investment in R&Dsince the privatisation of the CEGB and under the financial and commercial pressures of de-regulation.

3.2.6 Future R&D Priorities

As a result of the trends in steam turbine development, the major emphasis of materialsdevelopment around the world is focussed on improved high temperature materials for the hightemperature cylinders. Nonetheless development continues at a lower level of effort onmaterials for single cylinder turbines and on materials for the low temperature turbine:• Development of rotor materials for single cylinder machines• Improved understanding of stress corrosion cracking• Substitution of lower cost materials

High temperature materials development is a very long-term process. A typical developmentprogramme proceeds through several stages:• Investigation of trial melts including creep testing to at least 10,000 hours (~2 years)• Manufacture of a prototype component in the best trial melt (~1 year). This stage is essential

to demonstrate the alloy can be applied to the very large components required for turbinerotors and casings without problems arising from excessive segregation or cracking duringmanufacture. The inspectability of large components is also demonstrated.

• Characterisation of the prototype including creep testing to at least 30,000 hours (~4 years).There is potential for significant variation of properties through the section of largecomponents, especially in comparison to the properties achieved in trial melts. Thereforecharacterisation of the prototype is essential. Characterisation typically includes long-termcreep testing, low cycle fatigue and cyclic hold testing and investigation of the influence of

55 of 108

long-term ageing on tensile and impact strength. Investigations of fracture toughness andcreep crack initiation and growth properties may also be carried out.

• Launch as commercial material and gain first order (~1 year)• Test commercial products to establish scatterband of properties (~4 years). Cast to cast

variation in properties is typically of the order of +/-20%. A knowledge of this scatterbandand the position of the first prototype within it is required to fully exploit the propertiesdemonstrated in a single prototype.

It thus takes about 12 years to achieve a completely reliable, mature material. For example inEurope the development of a new generation of martensitic stainless steel material for hightemperature rotors began in the COST 501 programme in 1986. After investigation of trialmelts, two prototype rotors were manufactured in 1989-90. Long-term characterisation of thesematerials led to their selection for the Skaerbaek and Nordjylland power plants in Denmark in1993. These machines were manufactured and commissioned in 1993-97. Test pieces from therotor forgings used for these turbines were included in a long-term testing programme funded byVGB that was launched in 1998. This programme finished in 2001 with the issue of dataestablishing a scatterband of properties for commercial rotors manufactured in these alloys. Thetotal time that elapsed from the launch of the development programme to this fully maturecondition has been 15 years.

Attempts are being made to reduce this development time. Metallographic studies have beencarried out and models are being developed to predict microstructure and the long termproperties which depend on them. One key area of success in this effort has been thedevelopment of models predicting thermodynamic equilibria: MTDATA developed by NPL inthe UK and Thermocalc developed in Sweden. An alternative approach is the use of neuralnetwork modelling to assess the influence of changes in chemical composition and heattreatment. These tools offer the ability to reduce the number of trial melts to be assessed beforefinding an alloy meeting the objectives and they also offer support for longer term extrapolationof data, increasing confidence so that alloys may be exploited earlier in the development cycle.Nonetheless the models are not yet sufficiently accurate or robust to remove the need for long-term testing.

Even where long-term data already exists on alloys, it is possible that new applications require acycle of prototype demonstration and characterisation. For example the application of nickelbased alloys to steam turbine design and manufacture is supported to some extent by theexistence of long-term creep data on some of the candidate alloys. However, this data is derivedfrom product forms such as sheet and small diameter bars whereas turbine manufacture requirescomponents with sections in the range 100-1000mm and weighing many tons. The difference insize has a potentially very significant influence on the microstructures and thus properties whichare achieved. A greater potential for chemical segregation, greater difficulty in forging andcontrolling grain size and the much reduced heating and cooling rates during heat treatment allhave potentially significant effects on short and long-term properties.

In addition to development and long-term characterisation of the base alloy, development ofwelding procedures is also necessary, especially for casing materials. Thus development ofwelding consumables is essential together with long-term characterisation of the weld metal andof welded joints.

To date, the development of high temperature alloys has been dominated by the need forimproved creep strength. However, as target temperatures increase, the possibility that oxidationwill limit application temperatures becomes significant. Current development programmes arenow investigating oxidation resistance and it is already clear that some alloys are limited bytheir oxidation resistance. Alloys are being designed to improve this characteristic but analternative approach is the development of coatings for protection against steam oxidation.

56 of 108

In summary, the following are required to support materials development:

• Modelling of microstructural evolution during processing and in service, of mechanicalproperties, of oxidation and of the behaviour of oxidation-resistant coatings.

• Test capacity for short and long-term mechanical property characterisation: creep testing,low cycle fatigue and cyclic hold testing, fracture toughness testing, creep crack initiationand growth testing.

• Test capacity for environmental (steam oxidation) testing, including the influence ofthermal cycling on oxide layers and coatings.

• Manufacturing capacity for trial melts and more significantly for prototype componentsincluding weldments where appropriate.

• Capacity for development of welding consumables.• Capacity for coatings resistant to steam oxidation.

References for Section 3.2

1. K-H Mayer, Advanced heat resisting steels, from Advanced Energy Conversion Materials,published by Nova Science Publisher Inc, USA, 2001.

2. R. Viswanathan and W. T. Bakker, Materials for Ultra Supercritical Coal Power Plants Part2: Turbine Materials, from Power Plant Chemistry 2001, 3(8), pp446-451.

3. B. B. Seth, US developments in advanced steam turbine materials, from Advanced HeatResistant Steels for Power Generation, published by IOM Communications Ltd, Book 708(1999), pp 519-542.

4. D. V. Thornton and K-H Mayer, European high temperature materials development foradvanced steam turbines, ibid.

5. S. Kjaer, F. Klauke, R. Vanstone, A. Zeijseink, G. Weissinger, P. Kristensen, J. Meier, R.Blum, K. Wieghardt, The advanced super critical 700C pulverised coal-fired power plant,proceedings of Powergen Europe 2001, Brussels, May 2001.

6. K. C. Mitchell, Extending the life of steam turbine rotors by weld repair, proceedings of 9th

international conference on creep and fracture of engineering materials and structures,published as Institute of materials book 769, April 2001.

7. M. Staubli, K-H Mayer, T-U Kern, R. W. Vanstone, R. Hanus, J. Stief, K-H Schonfeld,COST 522 – Power generation into the 21st century: advanced steam power plant,proceedings of 3rd conference on advances in material technology for fossil power plants,published as Institute of materials book 770, April 2001.