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Therefore, the risk of sulphuric acid dew point attack is minimal as the dewpoint is well below the gas exit temperature. However, some HRSGs are fedwith exhaust gas from GTs burning a slightly sour gas, up to 2000 vppbsulphur equivalent. While operation at base load provided a gas exittemperature above the sulphuric acid dewpoint, operation at part load reducedthe gas temperature at the outlet of the condensate pre-heater to the pointwhere the dew point was breached and sulphuric acid deposition occurred(Figure 31). This particular plant cycled between base load and part load on adaily basis. The deposit layer was very highly concentrated sulphuric acid,which also attracted very fine particles of siliceous material and particles ofgas duct internal lagging. The fact that the sulphuric acid remained highlyconcentrated precluded corrosive attack on the tube or finning, while the plantwas in operation. Off load moisture ingress into the HRSG via the rain dampermobilised some of the acid deposits down the casing walls. One option beingconsidered to prevent further deposition is to bypass the preheater at low loads(a bypass line is fitted), although this would result in a further performancepenalty.

Figure 31: Condensate preheater deposits (Courtesy of Power Technology).

3.6 Control and Instrumentation Issues on HRSG Plant

Modern CCGTs are operated with a large degree of automation to minimisethe risk of plant trips and other damaging incidents. Automated sequences areused for common plant procedures such as start-up and shutdown, minimisingthe participation of the operator and hence the risk of error and variabilitybetween the actions of different personnel. However, these sequences can stoppartway due to failures on field devices such as limit switches andthermocouples. Moreover, control and instrumentation problems on someplants mean that a high level of spurious and consequential alarms may be

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initiated and presented to the operator. In this situation, there is a danger thatimportant alarms could be overlooked, leading to a higher risk of plant trips.

Some of these problems are related to the presence of poorly specifiedinstrumentation, particularly actuators and valves, and this means thatupgrading of such equipment is an ongoing process on new plant. It is knownthat the incidence of plant trips that are control and instrumentation relateddrops considerably in the first months and years of operation from levels thatcan be as high as 50% during commissioning. It is vital to eliminate spurioustrips due to faulty instrumentation early in a plant’s lifetime, as these are verydamaging. For example, calculations performed on a P91 superheater headerwith full penetration welds under an optimised hot-start/shutdown proceduredemonstrated that a hot restart following a unit trip is 41 times more damagingin terms of thermal fatigue damage than a hot start following a normalshutdown [51].

The level of detail provided on some sequence displays is often insufficient toidentify the plant condition preventing a sequence from progressing. Thesequence logic is often so complex that even minor faults can be difficult topinpoint and rectify, with sequences having to be overridden manually andstepped through to try and identify the sequence hold. It is usually essential tohave a member of staff proficient in control and instrumentation issuesavailable to deal with any automation related problems that may arise.

The start-up of a unit can be potentially influenced by a wide range of activeoperational constraints generated from within the GT itself and also from theHRSG and the ST. These constraints adversely affect the run-up process byinhibiting firing on the GT until the current active constraint has been relieved.This gives rise to the risk of variable run-up times for each start-up on eachunit and clearly becomes even more relevant in the event of moving theoperational regime away from base-load. Faults with field devices canexacerbate this, making it difficult to predict overall run-up and loading timeswith absolute accuracy. The above factors have become highly significantunder the New Electricity Trading Arrangements (NETA), where significantfinancial penalties can exist for not getting up to load on time.

3.7 Flexible Operation of HRSG Plant

To take economic advantage of fluctuations in the wholesale price ofelectricity, it has become advantageous within certain markets (particularly theUK) for generating plant to operate flexibly. This may involve regular ‘two-shifting’ where plant is taken off load for several hours overnight, shut downat weekends and/or fluctuations between full load and part load or minimumstable generation. In the UK, the volatility in gas price and increaseddominance of gas generation also means that companies with a portfoliocomprising generation reliant on more than one fuel source can make up theircontracted output as they see fit. These factors have resulted in many CCGTs(and hence HRSGs) designed for largely base-load operation being subjectedto a flexible operating regime, with many plants conducting daily starts for atleast part of the year. Many of the effects of flexible operation on HRSG

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components in terms of thermal fatigue damage, cycle chemistry andcontrol/instrumentation are described in Sections 3.3, 3.4, 3.5 and 3.6 above.As far as the HRSG is concerned, the effects of load fluctuation are smallcompared to those arising from plant shutdown/start-up where the temperaturedifferentials and ramp rates involved are much more damaging in terms offatigue life.

Power Technology’s approach to assessing the level of risk to HRSGcomponents under a flexible operating regime is to carry out a flexibleoperation study, which is conducted in three phases:

Phase 1 involves establishing the existing level of instrumentation on theHRSG and highlighting those that would be required for a series of monitoredflexible operation trials. The critical HRSG components at risk of earlyfailure/increased degradation or that could create operational problems under aflexible operation regime are also identified based upon station-specific HRSGcomponent materials and geometry, inspection results, previous flexibleoperation experience and known problem areas on the plant being studied. Thenumber and location of additional instruments (typically thermocouples onboiler headers and stubs) required for flexible operation trials are thenspecified, with their installation justified against the potential risks identified.Thermocouples can also be fitted to structural components such as expansionjoints, duct supports, casings and so on to quantify the temperaturedifferentials across them.

A desk study of the effects of flexible operation on water/steam chemistrywould also be completed and would typically review phosphate hideout and itscontrol, flow accelerated corrosion risk in low temperature / pressure circuits,water treatment plant capacity, steam quality at start-up, de-aeration capabilityon start-up and condenser integrity.

After the additional instrumentation required had been installed, a programmeof shutdown/start trials would be agreed with the station for Phase 2 and allplant data received would be processed and analysed. The extent of anydamaging transients (specifically ramp rates, through-wall temperaturedifferentials and peak temperatures) would be quantified and a detailedthermal fatigue stress analysis carried out on the worst affected components.The damage would be quantified with the results expressed in terms of impacton component life and the likelihood of any failure mechanisms. In addition,one or two starts would be observed on site to fully understand any operationalproblems being experienced at first-hand. Appropriate recommendations tomanage any issues identified would then be made. These might typicallyinclude enhanced, targeted non-destructive testing/visual inspections,proposed modifications to operating procedures to minimise impact on HRSGcomponents and/or changes to the cycle chemistry.

Phase 3 (if required) would explore in more detail with the station thefeasibility of any proposed modifications to operating procedures in order toreduce component damage and / or reduce start time. Where the requiredchanges are significant, it may be necessary to widen the scope of the study to

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include the gas and steam turbines and to investigate the implications forcontrol and instrumentation. Trials of the optimised two-shift procedure wouldthen be carried out and the extent of improvement assessed.

Many of the design features that determine how flexible a HRSG is aredescribed in Section 3.2. However, the quality of manufacture andconstruction and the operational procedures adopted also play a key role inensuring that the effects of flexible operation (predominantly thermal fatiguedamage) are minimised. Manufacturers are aware of the threats posed bycyclic operation, and have already started to address the issues raised by theflexible operation of power plant in response to customer demand.

Both vertical and horizontal gas flow designs can be equally suited to flexibleoperation providing sufficient measures are taken during the design stage.Horizontal gas flow designs tend to be more susceptible to flexible operationdamage due to lack of flexibility between the header systems (particularly ifbottom-supported), though this is being addressed on more modern designs.The use of serpentine tube banks on vertical gas flow HRSGs inherentlymakes them more mechanically flexible, although there can be difficultieswith drainage of the horizontal tube banks leading to the risk of off-loadcorrosion.

Relatively simple ways of improving the ability of an HRSG to withstand therigours of flexible operation include the correct sizing of drains and vents andthe use of bypass valves and recirculation systems. GT and control andinstrumentation reliability are important in avoiding trips, as hot re-starts areparticularly damaging to upstream HRSG components. More substantialfeatures such as the inclusion of a stack damper or the use of higher-gradealloys to reduce component thickness should be made at the design stage, asthese are much more expensive to retrofit later in the plant life.

3.8 HRSG Costs, Reliability and Maintenance

3.8.1 Capital Cost

Capital costs for new build CCGT plant are difficult to predict accuratelywithout going out to tender, and even then a wide spread of costs can bepossible at any given time. However the approximate total project cost for anew build CCGT in the UK [52] is estimated to be in the region of £425/kW.This includes not only the EPC (engineer/procure/construct) contract, but alsoother items such as project management, connection to gas/electricitynetworks etc. The HRSG it likely to account for around 10-15% of this total.This is still significantly lower than for other forms of fossil fuel generatione.g. the equivalent capital cost for a new build advanced pulverised fuel plantis around £800/kW [53].

CHP plant capital expenditure is generally more expensive at around £750/kW[52] with the HRSG likely to account for 10-15% of this total.

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3.8.2 Operating Costs

Fixed operating costs, excluding fuel, are estimated to be around £12/kWyearfor an existing CCGT plant [54], although this could be higher for the mostadvanced class of GT plant due to GT maintenance costs. Generally, though,this represents the lowest value across the range of fossil fuel plant, the nextlowest value being that of £14/kW for an existing coal fired plant withoutFGD. These CCGT fixed operating costs will again be dominated by the gasturbine, perhaps even more so than with the capital costs.

Taking into account all costs (fuel cost at 23p/therm, fixed operating cost andcost of capital), the estimated delivered energy cost for a CCGT in the UK isaround 2.2p/kWh [53].

3.8.3 Reliability

Reliability/availability will vary greatly depending upon the original buildquality and design of the HRSG, the operating regime and the maintenanceperformed. EPRI [55] predicted theoretical total availability of a drum typeHRSG to be 98.52% e.g. 1.48% availability loss. Powergen data from 1997-1999 [56] suggests a figure of around 0.2% average HRSG availability loss,which may be due to the relative youth of the plant and a fairly tight functionalspecification. The losses [56] appear to be mainly due to one of three causes;tube leaks, leaks from flange connections or trips due to incorrect (high orlow) drum level on start up.

A survey of the causes of tube leaks on Powergen CCGT and CHP plantindicates that around 50% are due to ‘wear out’ mechanisms such as flowaccelerated corrosion, fretting, long term overheating, on load corrosion, stubweld cracking etc. The remaining 50% can roughly be categorised as arisingeither from original manufacturing (usually weld) defects / previous siterepairs or of being of a miscellaneous nature [57].

3.8.4 Maintenance

As well as the scheduled routine maintenance (e.g. valve/pump maintenance,safety valve maintenance and testing, instrumentation checks, etc), typicalpreventative actions would include annual HRSG visual inspections of: -

• HRSG/duct supports, expansion and alignment.• HRSG/duct external framing & internal stiffeners.• HRSG/duct internal insulation (if fitted).• Bypass damper and stack.• Main HRSG stack.• Tube modules and headers.• Duct fabric expansion joints (including thermal imaging whilst on-load to

identify areas operating at above-design temperatures and areas of gasleakage).

• The condition and tightness of pipe penetration seals• The condition and movement of main feed and main steam pipe supports.

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The following measures are also typically taken during major outages toguarantee the continued integrity of the HRSG through its design life (whichmay range between 15 and 30 years): -

• Sample header / drum internal inspections for corrosion/debris, thermalfatigue, blockage and/or FAC of orifices.

• Measurement of creep pips (header diametrical measurements).• Sample header end-cap and butt weld inspections.• Pipework butt-weld inspections.• Tube sampling/thickness checks (for flow accelerated corrosion and off-

load corrosion).• Valve casting inspections.

3.9 Industrial HRSG Applications

HRSG applications are more diverse at the industrial scale and can be broadlyclassified as below.

3.9.1 Industrial Gas Turbine HRSGs

At the small scale, gas turbines may be used in smaller CHP schemes or toprovide shaft power e.g. for pumping stations on gas pipelines. In CHPschemes the demand is usually for process steam (e.g. for enhanced oilrecovery) and the generation of electricity by using a GT to burn the fuel andgenerate electricity rather than just burning it in a boiler is an economic bonus.Because the provision of steam to the process is usually the paramountconcern, an auxiliary burner is usually fitted to allow continuation of boileroperation even when the GT has tripped. In this case a fresh air inlet duct isneeded. Units may also be installed for marine use in gas turbine driven ships,floating production storage and offloading vessels (FPSO) and offshoreplatforms. GT based CHP schemes typically achieve an electrical efficiency ofaround 23% (GCV) and a heat efficiency of around 49% (GCV) [7].

In recent years a new breed of microturbines has been introduced, based onturbocharger rather than aero-derivative technology. These are usually in therange up to 0.5MWe, at which scale the aero-derivative type becomes moreeconomic. At present a typical microturbine unit from Bowman PowerSystems has an output of 80kWe and a thermal output of 130 – 260 kWth in anexhaust gas stream at a temperature of around 600°C [58]. Most units installedso far have recovered heat as hot water, but in some specialised applicationssteam has been generated.

3.9.2 Reciprocating Engine Exhaust Gas Boilers

Internal combustion engines may be used on a small scale for electricitygeneration and HRSGs may be added to run in combined heat and powermode. Low grade heat is usually recovered as hot water from the enginecooling circuit. Higher grade heat may be recovered from the exhaust assteam. Normally smoke tube design package units are used to generatesaturated steam. Engines may be run on liquid or gaseous fuels. Increasingly,alternative fuel sources are being used, such as landfill gas, coal mine methane

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and bio-gas from anaerobic digestion of sewage sludges, agricultural wastesand industrial wastes. Reciprocating engine based CHP schemes typicallyachieve an electrical efficiency of around 27% (GCV) and a heat efficiency ofaround 42% (GCV) [7].

3.9.3 Heat Recovery from Other Industrial Exhaust Gases

HRSGs are used to recover energy from the hot exhaust of other industrialprocesses such as: -

• Glass and metallurgical furnaces• Kilns (e.g. sponge iron plants): Coal based high temperature reduction of

iron ore produces a flue gas with a temperature in the range of 1000-1200°C and a dust load as high as 40gNm-3. The first stage of the heatrecovery system is a radiant section with water membrane panel wallswhere the gas is cooled to around 750°C to reduce the risk of slagdeposition on downstream heat transfer surfaces. This is followed by aplain tube superheater fitted with soot blowers and evaporator andeconomiser sections.

• Roaster based plants: a typical application is in roasting of pyrite ores.Pyrite ores are oxidised in a fluidised bed to produce the oxide required formanufacture of the primary metal. The flue gases contain sulphur dioxideand are at a temperature of around 900°C with a high dust load. TheThermax design [59] uses a water tube boiler to recover heat. A verticaltube alignment and a wide tube pitch are used to minimise problems ofdust deposition. A hammering device dislodges dust from the tubes intohoppers below from which it is continuously removed.

• Smelters and converters: for example in copper and zinc smelting. Thehigh temperature waste gas has a very high dust load. The heat isrecovered in two stages. In the first stage the gas passes through a largewater membrane walled radiant section where some of the dust and slag isallowed to settle. The partially cleaned and cooled gas then passes througha conventional convection section with vertical bare tubes, again fittedwith hammering devices to dislodge dust [59].

• Coke ovens• Solid / liquid / gas waste incinerators• VOC thermal oxidisers

3.9.4 Process Integrated HRSGs

Many process industries use HRSGs to recover heat from the necessarycooling of process gases. Industries include:

• Petrochemicals (e.g. in sulphur recovery units)• Sulphuric acid plants: The double conversion double absorption process

for the manufacture of sulphuric acid from elemental sulphur generatesconsiderable heat in the exothermic conversion of sulphur to SO2 and SO3

gases. The optimum working temperature for the V2O5 catalyst is about440°C, so it is essential to have a process integrated HRSG in the systemto cool the gas to this temperature.

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• Nitric acid / Caprolactum plants: nitric acid may be manufactured by thecatalytic oxidation of ammonia at around 950°C to give a gas rich innitrogen oxides. The next step of the process requires a gas temperature ofaround 250°C creating a requirement for a HRSG. Either water tube or firetube designs may be used – in either case the design needs to take intoaccount a typical gas side pressure of 5 – 7 barg.

• Ammonia plants• Hydrogen gas plants• Fluidised catalytic converter units

3.10 Conclusions

• Current state of the art utility scale HRSGs operate at HP steam conditionsof up to 124 bar/565°C and allow the associated CCGT to deliverelectrical power at a claimed net efficiency of up to 60%. They aregenerally two pressure or three pressure with reheat, and may be of eithervertical or horizontal gas flow.

• The capital cost of new-build CCGT plant is around £425/kW, with theHRSG accounting for 10-15% of this total. The estimated delivered energycost for a CCGT in the UK is around 2.2p/kWh.

• Current state of the art industrial HRSGs generally operate at lower steamconditions than utility scale plant, and are usually of single pressuredesign. They are integrated into a wide range of industrial plant and ofteninclude provision for supplementary or auxiliary (stand-alone) firing.Highly fired units may incorporate a water-cooled furnace. Lower pressureindustrial boilers are usually of shell rather than water tube design.Designs tend to be bespoke for particular process applications.

• The recent trend has been for CCGT plant to be built under turnkeycontract. Whilst this does have advantages to the user in terms ofaccountability, it does tend to mean that the user has less influence on thedetailed HRSG design.

• Operational experience with HRSGs indicates that inclusion of specificdesign features and attention to detail during fabrication are just asimportant as the overall HRSG design, and that non pressure parts can beas problematic as pressure parts.

• Key areas for improvement include build quality, access for in serviceinspection & maintenance, control & instrumentation and capability forflexible operation. Overall cycle chemistry philosophy also needs to bemore thoroughly considered at the design stage.

The current challenge for operational HRSGs, particularly in the UK, is theneed to cycle plant which has been designed for and/or previously operating atbase load. Many users are currently carrying out investigations/trials and plantmodifications.

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4 NEW AND DEVELOPING TECHNOLOGIES

4.1 Introduction

This chapter describes and reviews HRSG technologies which are envisagedas becoming available in the near and longer term. A number of HRSGsuppliers and users were consulted during the preparation of this report abouttechnological developments and the need for further research. The consensusof opinion amongst those consulted was that the technology is mature and thatlarge or revolutionary advances in technology are not expected. However,small incremental improvements are expected to continue. None of theindustrial scale companies consulted stated that they have research projects oftheir own going on currently. At the industrial scale, most businesses are notlarge enough to take on large R&D commitments. Developments at the utilityscale, such as the use of higher temperature materials, will cascade down tothe smaller industrial scale market eventually and give gradual advances. Anumber of new applications or small areas of technological advance wereidentified and the following specific categories have emerged:

• Developments in the design of HRSGs themselves.• Developments in other parts of combined cycle plant or the overall cycle.• New applications.

4.2 Developments in HRSG Design

4.2.1 Utility Scale Once Through HRSG Designs

In terms of components, the once-through steam generator is the simplestHRSG design for recovering heat from the exhaust of a gas turbine. Waterentering at the cold end of the gas-pass, moves through a serpentine tubebundle where heat absorption occurs and a phase change takes place, and exitsas superheated steam. The circulation ratio is one and there is no requirementfor circulation pumps.

Conventional (i.e. not once through), sub-critical HRSGs utilise drums inwhich steam and water from the evaporative part of the cycle are separated.The water is then recirculated within the evaporator with additional feedwaterwhile the steam passes to the superheater for further heating. Supercriticalpressure boilers cannot utilise this type of design as there is no distinctwater/steam phase transition above the critical pressure. A once-throughdesign is therefore required. The OTSG design also has advantages for flexibleoperation. The steam drum is the component in a conventional HRSG designwith the thickest wall section and is therefore the most prone to the occurrenceof stresses associated with differential thermal expansion. It is the limitingcomponent in setting maximum heat-up and cool-down rates and a design thateliminates the drum is therefore better for flexible operation.

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Once-through technology has in the past generally been limited to projectsbased on aero-derivative or small industrial gas turbines. However, designsthat can handle the larger frame gas turbines are now evolving.

With regards to utility HRSG applications in the UK, once-through technologyis currently at a demonstration stage with a full-scale once-throughdemonstration HRSG (supplied by Deutsche Babcock, now Babcock Borsig)currently in operation at Cottam Development Centre. This is a sub-criticalBenson design with superheater steam conditions of 580°C and 160 bar and isdescribed further in Section 7.3.1. This technology, which originated withSiemens, is currently licensed to a number of other companies includingNooter/Eriksen.

However in North America the commercial acceptance of once-throughtechnology is far more apparent. ABB have 7 once-through (sub-critical)industrial sized HRSG units in operation and a further 23 under constructionand are moving towards larger scale applications with a significant new 270MWe once-through HRSG built recently at Agawam in Massachusetts. Inaddition, Innovative Steam Technologies (IST) of Canada won a contract for aonce-through technology plant at Calpine’s Broadriver Energy Centre,although in this case the HRSG is only sized to provide steam for GTinjection.

Successful and extensive pilot trials have been undertaken by CockerillMechanical Industries (CMI) of Belgium in their Seraing works [60] with aview to achieving supercritical conditions in the once through HRSG.Indications are that HRSGs will gradually adopt once through technology andthen move to supercritical pressures as gas turbines become larger and exhaustgas temperatures continue to increase.

4.2.2 Industrial Scale Once Through HRSG Designs

The application of the OTSG design to CHP plants is sometimes limited bythe critical need for a continuous supply of steam for some users. In aconventional drum HRSG design there is a significant reservoir of steam andhot water in the drum. In the event of a GT trip, this will provide a buffersupply of steam to maintain the supply to the user’s plant while the auxiliaryburner starts up and reaches the necessary output. The only water in the OTSGis in the tubes, which does not provide such a large reservoir of steam. Forapplications where maintenance of a continuous steam supply is critical,provision of steam buffer capacity needs to be investigated. The higherpressure drop on the water side of the OTSG has been identified as a minordisadvantage of the design. The development of new balanced header designsthat distribute the flow evenly over all of the tubes will reduce this effect.

4.2.3 Reliability Improvements

Within the UK, as a direct result of the New Electricity Trading Arrangements(NETA) in England and Wales, generators and suppliers now have to contractdirectly with each other for the physical supply of power. The effect of thisand similar legislation throughout the world on the plants themselves, is that

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many existing combined cycle gas turbine plants need to move towards moreflexible operation than was initially envisaged at their design stage.

This move from what was initially a system engineered for base loading to onewith substantial requirement for two-shift operation has a detrimental impacton plant reliability, specifically with regards to the HRSG. For the plant, themain risk associated with the use of the HRSG under flexible operation is theimpact on the achievable lifetime of pressure part and non-pressure partcomponents such as tubes, headers, casing components etc. In general, areduction in lifetime is expected resulting from causes such as Low CycleFatigue (LCF), localised header stresses and flow accelerated corrosion (FAC)and from a combination of LCF and Stress Corrosion Cracking (SCC).

The challenge therefore faced by engineers is to design solutions that ensurethe reliability of the next generation of HRSGs to be installed and upgrade theexisting plants (by correctly sizing drains for example) before major problemsoccur.

In order to do this companies have had to invest heavily in effective transientthermal modelling capabilities that allow them to analyse thoroughly everycomponent of the HRSG and make design changes to limit thermal stresses.

One such example where new features have specifically been designed toprovide flexibility for the plant during thermal transients is with FosterWheeler’s Fort Meyers repowering project [61]. This novel feature is a “wetbypass” unit which is designed to absorb the instantaneous power loss of asteam turbine trip and enable the gas turbine to continue operating at a fullsimple cycle load. In the event of the steam turbine tripping, main steam isattemperated and its pressure reduced, before it is bypassed to the condenser.Reheated steam is either bypassed to the atmosphere, when the condenser isnot available or also attemperated and reduced in pressure before passing tothe condenser dump. Thermal fatigue of the steam headers is greatly reducedby this innovative process.

Likewise Alstom have adopted features specifically to reduce thermal stress atwelded joints albeit at a potential increase in capital outlay. Most naturalcirculation HRSGs use a multiple–row harp-shaped design, comprising of onehorizontal upper header and one horizontal lower header joined by two orthree rows of vertical tubes. Alstom maintains that, the temperature of theexhaust gas drops sufficiently as it passes through the multiple tube rows tocause the individual tube rows to operate at different temperatures, inducingdifferential thermal stress at the weld joints. Their solution is to form a singlerow of tubes between headers to remove these differential stresses. As a singlerow allows for smaller header diameters, circumferential temperaturegradients in the headers are also minimised. Alstom’s analysis concluded thatsmall-diameter headers reduce thermal stress by as much as 60% whencompared to headers used with multiple rows.

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4.2.4 Modularity and Improved Maintenance Features

One noticeable innovation with regards to HRSGs is the drive towardsmodular designs. Aalborg Industries Inc., Alstom, Mitsui Babcock andNooter/Eriksen are some manufacturers who have designed around theconcept of modularity in order to exploit it as a selling point for their HRSGs.

Aalborg’s rapid delivery of standard units in less than 90 days alongside quickfield erection of their pre-assembled, pressure-tested systems has won them aconsiderable HRSG business. This modularity extends to the point wheresome of the auxiliary features of the HRSG are already in place (e.g.feedwater systems, air and flue gas ducting, etc).

Nooter/Eriksen incorporate a modular design to increase shop fabrication andminimise field man-hours. Their flexible construction method and attention todetail allows setting of up to five modules per day.

Other manufacturers such as Foster Wheeler believe modularity to beadvantageous. Their approach has been to make modules as large as possibleleading to a requirement for fewer components to be assembled in the field.Foster Wheeler maintain that the increased “constructability” of their HRSGshelps reduce the risk of possible delays in the erection schedule and thefinancial penalties that may then result.

Other companies have patented design features such as enhanced accessibilityto their HRSGs. The manufacturer Deltak, for example, claims this veryfeature reduces repair time to half of the industry standard.

4.2.5 Control and Instrumentation

At the simple smoke tube design end of the industrial HRSG market, controltechnology is being improved. Up to date touch screen control technology isonly now being introduced to these ‘traditional’ designs in less demandingapplications.

4.2.6 Highly Fired HRSG Designs

An increasing number of industrial scale HRSGs are being used to supply on-site power and process steam requirements. In some instances the steamdemand substantially exceeds what can be supplied from the exhaust of a GTmeeting the on-site power demand, so a high degree of supplementary firing isrequired. This results in a very hot, high moisture content gas flow and a needto fire down to low oxygen levels while still meeting emission limits for COand NOx. Often the supplementary burners must be sized to maintain fullsteam output even if the GT trips. This creates design challenges for HRSGmanufacturers. More exotic materials are required for highly fired HRSGs andwater membrane walls are becoming more common in designs for theseapplications. These technologies are well established in fired boiler designsand are now being transferred across to HRSG designs.

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4.3 Improvements to Cycle and Other Plant Components

4.3.1 Steam Cooled Turbine Blades

For the gas turbine, the maximum allowable inlet temperature is governed byboth the materials available for the turbine blading and the cooling techniqueemployed.

Previous generations of gas turbines utilised air to cool turbine components inan open loop system. The cooling air was supplied from a bleed in the gasturbine compressor, and then ducted to the internal chambers of the turbineblades and discharged through small holes in the blade walls. This airprovided a thin, cool insulating blanket along the external surface of theturbine blade. As a result, there is a significant exhaust gas temperature dropacross the first stage nozzle and significant flow of air required to cool downthe relevant turbine stages. An integrated closed loop steam cooling systemsignificantly reduces this temperature drop in addition to eliminating therequirement for air bleed for the turbine cooling. This technology is envisagedas contributing around 2% points in thermal efficiency.

The thermodynamic advantage of utilising steam in cooling circuits wasrecognised in the early 90’s [6] (Figure 32). This has been developedaccordingly over the last decade to allow integration of the HRSG steam flowwith the gas turbine cooling loop to further enhance cycle performance. Theimplications of this on steam purity are significant if corrosion and fouling ofthe cooling passages is to be prevented. This is discussed further in Section3.5.9.

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Figure 32: Effect of gas turbine cooling methods on efficiency (Courtsey ofInnogy plc) [6].

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The world’s first operational steam cooled gas turbine, built by MHI, wascommissioned in Japan in 1998 and installed in Unit 4 at the Higashi NiigataPower Station. In the United States, it was not until early 2001 that Siemens-Westinghouse achieved commercial operation with a 360 MWe power plantlocated in Massachusetts followed immediately by a second 249 MWe plant inFlorida. The gas turbine installed in the American plants is considered“partially” steam cooled, with just the first stage vanes being incorporatedwithin a closed loop. Whilst specific teething problems were found duringstart up conditions of the W105G gas turbine, a cycle efficiency of ~58%(LHV) was achieved with this technology.

More recently General Electric installed their first H-class unit at the BaglanEnergy Park in South Wales. This unit, which features steam-cooled rotor andstator vanes, is currently under commissioning tests with engineers aiming tobreak the 60% (LHV) cycle efficiency barrier.

4.3.2 Fuel Heating

In the late 90’s methods of heating fuel prior to combustion in the gas turbinewere being introduced to the combined cycle in order to enhance efficiency.Preheating of the fuel results in a reduction in the amount of fuel needed toachieve a given firing temperature in the gas turbine. However, whilst theefficiency of the cycle improves, the plant power output is found to reduceslightly. This originates from the fact that when a gas turbine is fed warmerfuel, it requires less mass flow of that fuel to obtain the previous cold-fuelfiring temperatures, thus the exhaust mass flow and water vapour content ofthe combustion products is lower. Less power is therefore obtained from thecombustion gas expansion through the turbine. Furthermore the HRSGgenerates a little less steam from the decline in gas turbine exhaust mass flowand hence a drop in steam turbine power also occurs. However, the overallimprovement in the cycle efficiency results from the fact that the energydiverted from producing steam power is of relatively low grade, and is betteremployed as a heating medium for the fuel.

The fuel heating source may be either steam or water. For the case of steamthis can originate from the steam turbine bleed or directly from one of theHRSG pressure level circuits. For the case of water heating, the hot water isdrawn from the HRSG economisers.

There is a threshold at which the benefits associated with the increase inefficiency are found to be at the expense of the level of electrical powerproduced [62]. For example fuel heating to around 200°C from an intermediatepressure economiser exit water source on a typical three pressure reheatcombined cycle, results in a net heat rate gain of about 0.6% with acorresponding net power loss of about 0.3%. If the temperature of the fuelwas raised to around 300°C by a high pressure economiser exit water source,the loss of power becomes more evident at 0.75% whereas the noted increasein the heat rate gain is less apparent as it only rises to 0.8%.

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4.3.3 Gas Turbine Steam Injection for Power Augmentation

The injection of steam into a gas turbine for NOx control is well established.Steam injection into the combustor reduces combustion temperatures bydiluting both the level of oxygen in the combustion air and the heat generatedfrom combustion of the fuel. However the use of steam injection for poweraugmentation is considered to be somewhat under developed for larger heavyduty gas turbines.

Injecting large amounts of steam for power augmentation creates a fairlyefficient power only plant that effectively makes the steam turbine, condenserand cooling tower in a combined cycle redundant. Aero-derivative enginessuch as LM 5000 and the Alison 501 were proven in the mid 80s to be suitablefor steam injection power augmentation [63]. The LM 5000 can absorb all thesteam generated from the heat recovered from its own exhaust, and in doing soincrease its power output by up to 15%.

The reason for the aero-derivative engines success at power augmentation wasbecause aero-engines were initially designed to pick up load faster than heavyindustrial gas turbines and consequently have a greater surge margin whenoperating in an industrial application. Some of this surge margin can thereforebe exploited to accept steam injection.

However the limited electrical generation capacity of these gas turbines (<50MWe) means that the benefits of this application have been limited tomostly small scale industrial power supply uses. Although in some casesseveral of these aero-derivative gas turbines have been successfully combinedto form a reasonably sized utility plant (i.e. 7 x 50MWe). Currently no gasturbine greater than 50 MWe has been designed which allows for such heavysteam injection that the need for a separate steam turbine is removed (as is thecase for the LM5000).

However, elaborate arrangements where steam/water is injected into large gasturbines are in the development stage, albeit that relatively few have actuallybeen constructed. A current list and description of these proposals has beengenerated by Foster-Pegg [64]. Those which have reached demonstration statusinclude: -

• Simple Steam Injected Gas Turbine “SIGT” Cycle: this system involvesmoderate steam injection into the combustor of a standard large gasturbine and has been used to augment power under hot ambient conditions.

• Humid Air Turbine or “HAT” Cycle: this system involves evaporatingmoisture into the air flowing into a gas turbine and requires a special gasturbine in order to operate effectively. It has been highlighted asparticularly appropriate for gasification combined cycles.

The retrofit of gas turbine steam injection for power augmentation may beparticularly attractive in areas where there is existing industrial scale opencycle GT plant and a demand for greater generating capacity. A variety ofHRSG designs could be used in this application, but it is a developing

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application for which OTSGs may be particularly suitable. The OTSG can bedesigned to run dry at full exhaust temperature, removing the need for abypass stack and providing a more simple and robust system.

4.3.4 Gas Turbine Inlet Air Chilling

Air intake cooling technology is used to enhance combined cycle poweroutput and is particularly relevant for utility plant situated in warm climateswhere the air is dry and hot. The cooling of the air at the inlet results in anoticeable increase in mass flow through the gas turbine. This in turn results ina higher gas turbine power output as well as a slight increase in the steamproduction in the downstream HRSG.

The cooling of the inlet air is achieved by means of a refrigeration systemsimilar to the type employed in large building air conditioning units. The heatexchanger used to cool the incoming gas turbine air is formed from a coil offinned tubes located in the inlet housing of the gas turbine. Cooled water iscirculated through the tubes. The prior cooling of the water is achieved bychillers which are mass produced pieces of equipment and essentially fall intotwo categories:-

• Centrifugal chillers• Absorption chillers

In general, the absorption chiller delivers a lower gross plant power outputthan the centrifugal chiller due to the use of steam bleed from the HRSG todrive it. However in terms of plant net power outputs the two systems areapproximately the same. This is because the centrifugal chiller requires anelectric pump for circulation and therefore consumes a far greater amount ofauxiliary power as opposed to the steam driven circulation for the absorptionmethod. Further differences between these two systems are described ingreater detail by Elmasri [62].

Chilling the inlet of a large combined cycle allows extra power to be obtainedfrom a plant (~ 5% increase in the net kWe output). The cost of that additionalpower output is the additional expense of the capital and operational costs ofthe upstream chilling unit and other necessary modifications to the gas turbineitself. These have been estimated by Elmasri [62] at ~$250 per kWe of capacitygained above the initial hot design condition.

The small-scale OTSG design may also find application in poweraugmentation for existing open cycle GT plant by GT air inlet chilling, asdescribed above. A small OTSG unit can be added to an open cycle GT toprovide steam for an absorption chiller. Again the advantage of the OTSGdesign is that protection in the event of a boiler trip is not required as theOTSG may be designed to run dry at full exhaust temperature.

4.3.5 Increases in Gas Turbine Exhaust Temperature

The pursuit of higher efficiency CCGT plant has driven the rapid increases inGT exhaust temperature and mass flow rate imposed on HRSGs. The exhaust

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conditions of some established and more recently developed gas turbines areshown in Table 5 below:

Gas Turbine Turbine inlettemperature

(°C)

Turbine exhausttemperature

(°C)

Mass flow(kg/s)

Siemens/Westinghouse501G (a 60Hz machine)

1427 600 535

GE 9351FA 1327 606 636Alstom GT 26 1260 641 549GE 9001H 1427 621 685

Table 5: Turbine inlet/exhaust gas temperatures and mass flow rates on somemodern gas turbines [65].

The Alstom GT 26 (and GT 24) gas turbine uses sequential combustion in twoannular combustion chambers to achieve improved efficiency. This is differentto the conventional approach to gas turbine combustion, which is carried outin a single stage and requires increasingly high firing temperatures andcomplicated cooling technologies [66]. The exhaust temperature is the highestof any commercially available gas turbine.

The GE 9001H is designed to give a combined cycle thermal efficiency of60% and the first of its kind is being installed at Baglan Energy Park in SouthWales. The efficiency improvement is due to the high firing temperature,which is made possible by the use of large single crystal airfoils, superiorcomponent and coating materials and a closed-loop steam cooling system (seeSection 4.3.1) [67]. The implications of this type of cooling system for HRSGwater/steam chemistry are not trivial and are discussed in Section 3.5.9.

In general, the latest generation of gas turbines, with their increased gasturbine outlet conditions are not anticipated to be a major concern as far as theHRSG pressure parts are concerned, as materials issues at these temperatureshave been successfully tackled on conventional coal-fired plant.

For these increased temperatures, GT diffuser ducts, HRSG inlet ducts andcasings are likely to be internally insulated in the higher temperature regions.Currently used internal insulation liner materials can cope with these relativelysmall increases in temperature (internal insulation has been proven on CHPplant with supplementary firing up to around 850°C).

The most likely area to be impacted is that of non-cooled support components,particularly on vertical gas-flow HRSGs e.g. HP superheater/reheater tubesheets and support links. This may require more extensive use of higher gradealloys such as modified 9% chrome (P91) or stainless steel for supportcomponents. There may even be a need to employ water/steam cooled supporttubes for high temperature tube banks on vertical gas-flow HRSGs (akin to therear pass of a conventional coal fired boiler). This method of support haslargely been limited to supplementary fired vertical gas flow HRSGs in thepast.

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4.3.6 Supercritical Technology

Currently state-of-the-art supercritical pulverised fuel fired steam powergeneration plants exist and operate at up to nominally 300 bar and 600°Csteam output with net efficiencies of ~45% LHV [68]. Due to advances inmaterials technologies steam temperatures and cycle efficiencies havegradually improved and are set to continue to do so. Targets of final steamconditions of 650-700°C have been set for 2020 and associated cycleefficiencies of around 50-55% are expected.

The recognised advantages of adopting a supercritical steam cycle in additionto the obvious improvements to cycle efficiency are [68]:-

• CO2 emissions are reduced by about 15% per unit of electricity generatedwhen compared with typical existing sub-critical plant.

• Exceptionally good part load efficiencies are achievable, typical half thedecrease in efficiency exhibited by sub-critical plant.

• Plant costs are considered comparable with sub-critical technology.

Much of the technology surrounding supercritical technologies is not new anda great deal of development work was done in the 1950s and 1960s. At thistime countries such as the UK kept a predominantly sub-critical power basedue to the unreliability, expense and poor operational flexibility of these earlydesigns. However, elsewhere in Europe and in Japan, development andrefinement continued to the extent that supercritical steam is now consideredone of the leading clean coal technologies. Currently 10% of orders for newcoal fired power generation plant are for supercritical steam cycles and whilstfuture orders are difficult to predict, estimates suggest a steady rise in theadoption of this technology [68].

Supercritical steam cycles are not limited to coal fired plants exclusively. Intheory, supercritical steam cycles can be used for any technologyincorporating a steam cycle to generate electricity. Therefore the benefits areconsidered applicable to HRSGs within combined cycle gas turbine systems.

With advances in gas turbine technology, combined cycle units are now largerand HRSGs are operating at higher temperatures. Previously both these factorswere lacking and thus directly affected the commercial and technical viabilityof the supercritical HRSG.

4.4 New Applications for HRSGs

4.4.1 The Role of HRSGs in IGCC Plant

4.4.1.1 IGCC Plant Description

Whilst gas turbine technology has been applied previously in natural gas andoil fired combined cycle plants, the development of the Integrated GasificationCombined Cycle (IGCC) allows both solid and liquid fuels to be the main

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source of fuel for the plant. After several years of technology development anddemonstration operation, this power plant technology is approaching the statusof commercial operation.

The concept of an IGCC power plant incorporates an oxygen or air-blowngasifier operating at high pressure and producing a raw gas, which is cleanedof most pollutants and burned in the combustion chamber of a gas turbinegenerator set for power generation. The sensible heat of the raw gasproduction process along with the hot exhaust gas from its combustion in thegas turbine are used to produce steam. The steam, in turn, is then utilised togenerate additional electrical power through a series of steam turbines. Themain subsystems of an IGCC power plant are therefore:-

• Gasification plant including feedstock preparation system• Raw gas heat recovery system• Gas purification system with sulphur recovery• Air separation unit (ASU); required only for oxygen-blown gasification• Gas turbine with electrical generator• Heat recovery steam generator (HRSG)• Steam turbine system with electrical generator

The actual coal gasification process for IGCC power generation is classifiedinto three categories namely, stationary bed (Lurgi and British Gas Lurgisystems), fluidised bed (High Temperature Winkler, U-gas and Kellog-Rust-Westinghouse systems) and entrained-flow bed.

The entrained flow bed gasification process uses an oxygen blown gasifier andis the most proven technology for single unit with large capacity applications.The entrained flow bed gasifier has essentially five distinctive types accordingto manufacturer (Texaco, Destec, Prenflo, Shell and GazCobinat SchwarzePumpe). Of the five, two distinct categories are apparent:

• Wet feed processes such as Texaco and Destec utilise a coal slurry feed.• Dry feed process such as Prenflo, Shell and GazCobinat Schwarze Pumpe

(GSP) utilise a dry powder feed.

Generally the temperatures within the gasifiers are lower in the case of the wetfeed process than the dry feed process. Water-cooled walls, rather thanfirebrick are therefore necessary. Manufacturers claim that a dry powder feedgasifier has a slight advantage in terms of cycle efficiency over the coal slurrygasifier. Dry processes systems are however, considered to be morecomplicated than their counterpart. These complications are generallyassociated with reliability penalties. On the whole the unit investment for thedry feed gasifier is considered greater than the wet feed unit.

A schematic showing a typical IGCC utility plant layout is shown in Figure33. This figure illustrates the plant arrangement based on a Shell dry feedentrained-flow gasification process. The cycle is described in detail below:-

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Initially, the coal is pulverised in a roll mill and then conveyed to a dryer.Within the dryer the coal is flash dried in a stream of hot nitrogen which hasbeen supplied from an ASU and heated by low-pressure steam. The dried coalis separated in cyclones and the nitrogen cooled and the water removed. Thisprocess reduces the moisture content of the coal considerably. The coal is thenpressurised with additional nitrogen from the ASU and fed into the dry-feed,entrained flow, slagging gasifier through lock hoppers. In addition to thenitrogen, the ASU also provides a steady supply of oxygen into thegasification chamber.

The gasification pressure vessel is protected from the hot gasification productsby a tube wall construction in which intermediate pressure (IP) steam is raised.The gasifier operates at a pressure of 25bara and a temperature of 1400ºC andproduces a raw fuel gas, mainly composed of carbon monoxide (CO) andhydrogen (H2). Most of the coal ash forms a molten slag, which falls into awater bath at the bottom of the gasification chamber. Sensible heat isrecovered from the raw gas in a waste heat boiler situated at the top of thegasifier. This boiler evaporates water bled from the high pressure (HP) circuit.In addition, further heat is also recovered from a syngas cooler after exitingthe gasifier. To ensure that the fly ash is solid prior to entering the syngascooler, cooled raw gas is recycled from the outlet of the syngas cooler.

The syngas cooler heat exchanger consists of economiser and evaporatorsurfaces and generates IP steam supplied directly from the IP pump. Theremaining heat in the raw fuel gas is exchanged in a gas-to-gas heatexchanger. This exchanger utilises the raw fuel gas to re-heat the cleaned fuelgas after an acid gas removal process. The gas cleaning process itself is donein stages. Initially, the fly ash is removed by cyclones and by water scrubbers,which also absorb any hydrogen chloride (HCl) present. Heat is extracted forboiler feedwater heating and the cooled raw gas then passed to the purificationstage where sulphur-bearing compounds, mainly hydrogen sulphide (H2S) andcabonyl sulphide (COS), are removed in order to protect the gas turbine andalso to meet environmental legislation. These compounds are absorbed bycounter-current washing with Purisol solvent and are recovered from thissolvent in a series of flash columns. The solvent is recycled and the sulphur-bearing compounds are sent to the sulphur recovery plant. This plant is basedon a Claus design. Unreacted gases are treated in a SCOT tails gas recoveryunit. Heat generated in the Claus plant is used for boiler feed water heating.

The clean fuel gas is saturated with hot water in a humidifier, which helps toreduce the NOx formation in the gas turbine combustor. Prior to entry to thecombustor, the fuel gas is further heated by an exchanger using a bleed fromthe high-pressure, high-temperature (HP/HT) economiser. At the combustor,the clean fuel gas is mixed with air supplied directly from the GE 9FA turbinecompressor alongside compressed nitrogen, the original nitrogen source beingair from the gas turbine compressor which has been separated in the ASU.

From the gas turbine, the hot flue gas passes to the HRSG where steam israised at two pressure levels (NB the IP stream is only superheated within the

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HRSG, the steam itself is originally raised within the gasifier). The cooledgases are then exhausted via the stack to atmosphere.

The condensate from the low pressure LP steam turbine is passed through acondensate preheater prior to entry to the deaerator. Here the incoming wateris heated by direct contact with steam. From the deaerator, there are threesupply lines to the HRSG, namely the HP, IP and LP lines.

The LP pump supplies feedwater directly to an LP evaporator within theHRSG. Following evaporation, some saturated steam is extracted after the LPevaporator and used in the dryer to remove moisture from the incomingpulverised fuel (PF). The remaining saturated steam from the evaporator feedsinto the LP superheater. After being superheated, the LP steam is split into twolines. One line supplies the superheated LP steam to the LP turbine anotherrecirculates the LP superheated steam back to the deareator.

The IP pump supplies feed water to the syngas cooler and gasifier membranewall where the heat from the gasification process is utilised to generate IPsteam as previously described. Some steam is also bled off and fed to thegasifier itself as part of the gasification process. The IP steam from the gasifieris then fed into the HRSG for superheating. Following superheating, the IPsteam is added to the exit line from the HP turbine. These lines combine andare reheated in the HRSG before entering the IP turbine.

The HP pump supplies feedwater to the high-pressure, low-temperature(HP/LT) economiser and then on to the HP/HT economiser. Upon leaving theHP/HT economiser, feedwater is extracted to supply the waste heat boilerwithin the gasifier (see above) as well as supplying a source of heat for theclean fuel gas line. Saturated steam is therefore produced from both the HPevaporator within the HRSG and the waste heat boiler within the gasifier. Thetwo steam lines then recombine to be superheated within the HRSG. Thesuperheated HP steam is then fed to the HP turbine for power generation.

The IP turbine steam supply consists of the HP turbine exit flow combinedwith the HRSG IP line. The LP turbine steam supply consists of the IP turbineexit flow combined with the HRSG LP line.

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Figure 33: Diagram of a typical IGCC plant with dry feed gasifier (Courtesy of Mitsui Babcock Energy Ltd)

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4.4.1.2 IGCC Plant Performance

As can be seen from Figure 33 and the description above, in order to enhancethe plant efficiency, the steam cycle of the HRSG in an IGCC plant is verymuch integrated with other plant components such as the gasifier. For suchplant, in general, overall cycle efficiencies of around 43% can be achieved.

The efficiency of an IGCC plant is however still essentially lower than that ofa typical gas fired combined cycle plant. In addition to the loss of chemicalenergy from the removal of sulphur and other combustible contaminants, thehot gas leaving the gasifier must be cooled in order to allow effective chemicaland ash removal. Therefore the combination from both gasification and the gascooling are responsible for the lower overall cycle efficiency [69].

Since the 1950’s there have been 24 IGCC plants constructed or planned forconstruction throughout the world. These are based on several differentvariations of the gasification process. Of these 24, some 3 are dismantled, 17are in operation and the remaining are either at the planning, engineering orconstruction stage.

In recent years the numbers of large Utility IGCC plants have been growingand in both the USA and Europe IGCC plant have reached thecommercialisation stage. In Europe three large scale IGCC (>250MWe) plantsbased on combining state-of-the-art gasifier technology and a high degree ofHRSG process steam integration have been constructed and successfullyoperated during the last few years. Two of these, Buggenum (Netherlands) andPuertollano (Spain) employ coal as the main fuel source whilst Priola Gargallo(Italy) utilises refinery residues. In both coal based plants dry feed entrained-flow gasifiers were selected and in the case of the refinery residues-basedplant the wet feed entrained-flow gasifier process was chosen.

In the USA there are currently two IGCC units generating electricitycommercially - the United States Tampa Electric unit at Polk Power (250MWe) station and the Cinergy owned (260 MWe) plant at Wabash River.Characteristics of these key plants [69] are outlined in Table 6 alongside thoseof other IGCC plant world-wide.

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Plant Country Start Fuel Process MWe StatusSteag F.R. Germany 1952 Coal Lurgi 50 DismantledSteag F.R. Germany 1959 Coal Lurgi 150 DismantledCoolwater USA, Cal. 1984 Coal Texaco 100 DismantledPlaquemine USA, La 1986 Coal Destec 220 OperatingDemkolec Netherlands 1993 Coal Shell 250 OperatingTampa,Polk USA, Florida 1996 Coal Texaco 250 OperatingEldorado USA, Kansas 1996 Coke Texaco 40 OperatingWabash USA, Indiana 1996 Coal Destec 262 OperatingSchwarze-Pumpe

F.R. Germany 1996 Coal/Oil Shell 40 Operating

Pernis Netherlands 1997 HeavyOil

Shell 127 Operating

Pinon Pines USA, Nevada 1998 Coal KRW 80 OperatingPuertallano Spain 1998 Coal Prenflo 300 OperatingI.S.A.B Italy 1998 Asphalt Texaco 540 OperatingSaras Italy 1999 Tar Texaco 550 OperatingStar USA, Del. 1999 Coke Texaco 240 OperatingA.P.I. Italy 1999 Tar Texaco 250 OperatingFife Power UK, Scotland 1999 Coal BGL 120 OperatingI.B.I.L India 2000 Lignite Tampella 60 OperatingG.S.K Japan 2000 Tar Texaco 540 OperatingFife Power UK, Scotland 2000 Coal/Rdf BGL 400 OperatingZuv Czec Rep. 2000 Coal HTW 400 PlanningS.P.C.C. China, Yantai 2003/4 - - 2x400 PlanningK.P.E USA,

Kentucky2003/4 - - - Planning

GlobalEnergy

USA, Ohio 2003/4 - - 580 Planning

Table 6: IGCC plants world-wide.

Two main disadvantages which are usually associated with IGCC are thereliability / availability of these combined cycles and the initial significantcapital outlay [70]. Whilst the reliability/availability factor is believed to beimproving as is illustrated from the efficient running of the Pernis plant in theNetherlands [71], the cost of an IGCC plant still remains relatively higher than aPF plant with a flue gas desulphurisation system installed.

However, the main benefit of an IGCC plant is its ability to allow coal to befired in a clean and efficient manner. The removal of contaminants during thegas clean up results in a process which is potentially the cleanest type of coal-fired power plant in operation. Whilst coal remains the largest unused sourceof fossil fuel in the world, it makes environmental sense to developtechnologies that allow it to compete with its “naturally cleaner” counterpartsand therefore reduce the rate of consumption of premium liquid and gaseousfuels.

4.4.2 Biomass Integrated Gasification – Combined Cycle

Biomass IGCC applications tend to be sized at the industrial rather than theutility scale due to the logistics of fuel supply. They are unlikely to reachutility scale, even once the technology is mature, due to the low energy density

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of biomass fuels and the land area and fuel supply infrastructure required tosupport even a relatively small plant.

There are a variety of approaches to biomass gasification including fixed bed,rotary kiln, pressurised circulating fluidised bed (CFB), atmospheric CFB andthe Batelle process [72]. The air blown CFB, fixed bed and rotary kilnapproaches produce a low calorific value (typically 5-6MJNm-3) ‘syngas’while the Batelle process by excluding air and using steam as the gasifyingmedium produces a medium calorific value gas (~15 MJNm-3). The ‘syngas’from all of these processes can be burnt in a GT or a reciprocating engine withexhaust heat recovery. If syngas is to be burnt in an engine, it must be cleanedfirst to remove particulates and in some cases ‘tars’ as well. Current gas cleanup technology requires that the gas be cooled from the gasificationtemperature (typically 850 - 950°C) before filtration. There are therefore twoHRSGs in the system, one to recover heat from the hot process gas prior tofiltering and the second to recover heat from the engine exhaust. The ‘syngas’cooler HRSG will be exposed to carry over of bed material and ash. Biomassfuels may be rich in alkali metals which increase the potential for tube fouling.This needs to be taken into account in the design.

Very few BIG-CC projects have yet been successfully developed. If BIG-CCtechnology can be made to operate reliably and economically it will open up anew market for industrial scale HRSGs.

4.4.3 Microturbines

In general, microturbines are unlikely to be coupled with HRSGs. Therelatively low exhaust temperature (if recuperated as most are) and flow arenot normally sufficient for economic steam generation at useful steamconditions. However, microturbine suppliers are working on scaling up theirunits. Bowman Power Systems expect to release a 200kWe unit soon andbelieve that microturbines up to 500kWe are feasible. At the larger sizes theyare more likely to be coupled to HRSGs to provide steam flows for smallerconsumers in some specialist applications. It is possible that they could beused for air pre-heating or provide heat for an LP circuit as part of a largerboiler system.

4.5 Conclusions

• Future increases in HRSG operating conditions will largely be dictated byincreases in GT exhaust temperature.

• One area of significant interest is once through design. The main benefit ofthis technology at present is its suitability for flexible operation. In thelong-term future, it should pave the way for supercritical cycles with evenhigher thermal efficiencies.

• Another area of significant interest is the use of HRSG steam for GT bladecooling in the latest class of GTs. This presents significant challenges forHRSG design in attaining the high steam qualities required.

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• The use of HRSGs within IGCC plant is now approaching the status ofcommercial operation, although the costs still remain relatively high.

• Other development areas include modular design to reduce build costs,improving reliability, and improving access. The latter two items addressspecific problems experienced by plant operators. Improvements in theseareas are perceived to provide product differentiation in an extremelycompetitive market place.

• Industrial scale HRSG technology is relatively mature. Most developmentcomes from the integration of HRSGs within new processes, and thetrickling down of technology from utility scale HRSGs. One exception isthe use of once through technology which is already standard practice forone HRSG supplier.

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5 WORLD-WIDE ACTIVITIES

5.1 Introduction

This chapter reviews the current trends in the Global HRSG market. The mainsources of HRSG supply and the countries responsible for purchasing HRSGsare highlighted, alongside capabilities of the key players in the Global HRSGmarket.

Two approaches were taken to finding information for this section of thereport. An internet search was carried out to try to identify as many companiesas possible that are active in the field. Appendix A shows a list of thecompanies identified and a summary of their capabilities. A briefquestionnaire was sent to each of these, but the response to this survey wasdisappointing, with only thirteen complete responses received. The secondapproach was to examine published data. McCoy Power Reports [73] provides asuitable source, but is focussed on the utility sector of the market.

5.2 Survey Responses

The capabilities of the companies that responded are summarised in Table 7below.

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Company

Als

tom

Apr

ovis

Eri

e

Inno

vati

ve S

team

Tec

hnol

ogie

s

M E

Eng

inee

ring

Mit

sui B

abco

ck

NE

M

Noo

ter/

Eri

ksen

SF

L

TB

W

The

rmax

Wel

lman

n R

obey

Vog

t-N

EM

TE

I G

reen

s

TurnoverRange (M $)

>100 1-5 10-50 50-100 0.5-1 10-50 >100 >100 50-100 1-5 >100 1-5 50-100 1-10

Application Utility Combined Cycle X X X X X X X X X XBIG-CC X XPetrochemicals X X X X X X X X XOther chemical / process X X X X X X X XIron, steel & coke X X X X X XFurnaces / Kilns X X X X X XWaste incineration X X X XIndustrial GT exhaust X X X X X X X X X X X XDiesel engine X X X XGas engine X X X X

Scale 1-5 X X X X5-10 X X X X X X10-20 X X X X X X20-50 X X X X X X X X X X X50-100 X X X X X X X X X>100 X X X X X X X X X

Capabilities Consult X X X X XDesign X X X X X X X X X X X X X XManufacture X X X X X X X X X X X X X XCommission X X X X X X X X X X X X XOperate X X

Technologies Smoke tube X X X X X X X XWater tube X X X X X X X X X X X XOTSG X X X X X X X X

Table 7: Summary of capabilities of companies responding to survey

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5.3 Utility Scale Market – Published Information

5.3.1 Source of Market Information

McCoy’s data was gathered through a written survey of US and non-USsuppliers of electric power generating equipment and engineering services. Asdata from each power plant are cross-checked from various sources, it isbelieved that McCoy provides the most complete and accurate informationfrom an independent organisation. The calculations are based on the steamturbine MWe output in combined cycle applications and half the gas turbineoutput in cogeneration, (non combined cycle) projects. The final figuregenerated for total installed electrical capacity is therefore somewhatconservative by this method, however, the data provides an excellentindication of trends within the market (Section 5.3.2) and major marketplayers (Section 5.3.3).

5.3.2 The HRSG Buyers

In terms of geographical distribution, it is apparent that over the past ten years(1992-2001), the biggest buyers by far of HRSGs have been in the US. Amassive 48% of all world-wide purchases have been made by operators in theUS. Next to the US the United Kingdom and Japan are the joint closest interms of purchases over this period, however, at just 4% of the total ten yearsales the sheer size and domination of the US market is obviously apparent.In terms of customer type three categories emerge. These are classed as:

• Non-Utility Generators (NUGs)• Electricity Utility Power Generators (EUPGs)• Industrial Power Generators (IPGs).

The NUGs account for some 81% of orders over the past ten years in the USmarket and some 49% of orders for the rest of the world. Over the same tenyear period, EUPGs account for some 17% of the orders in the US alone andsome 44% of the non-US market.

5.3.3 The HRSG Manufacturers

With respect to the outlined ten year period, the key manufacturers on anindividual company basis were identified as Alstom Power (14.2%),Nooter/Eriksen (12.6%), Deltak (9.5%), NEM (7.7%) and Aalborg Industries(7.5%). Companies outside this top five, in the 1-7% share of the marketincluded Foster Wheeler Energy (6.4%), Mitsubushi Heavy Industries (4.3%),Doosan Heavy industries (4.0%) and Mitsui Babcock Energy Limited (1%).Below the 1% threshold, some 50 companies, partnerships or joint venturescompete for the remaining market share.

It is worth noting that many companies are involved in various types ofcommercial agreements with related companies throughout the world,therefore if all related companies, joint projects and licensee relationships are

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considered the top ranking is altered with NEM taking first place followed byNooter/Eriksen and then Alstom Power.

5.4 Conclusions

• Over the past ten years (1992-2001), the biggest buyers by far of utilityscale HRSGs have been in the USA, with 48% of all world-widepurchases. Next are the United Kingdom and Japan with 4% of the totalsales.

• Key manufacturers in the above period were Alstom Power (14.2%),Nooter/Eriksen (12.6%), Deltak (9.5%), NEM (7.7%) and AalborgIndustries (7.5%). Companies outside this top five in the 1-7% share of themarket included Foster Wheeler Energy (6.4%), Mitsubishi HeavyIndustries (4.3%), Doosan Heavy industries (4.0%) and Mitsui BabcockEnergy Limited (1%).

• For industrial scale HRSGs, there were around 33% of sales in each of theUSA and Europe, with the other leading market being Asia and Australasia(excluding China) with 19%.

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6 MARKET POTENTIAL

6.1 Introduction

This chapter discusses the potential of various world-wide markets. The viewsexpressed are derived from internal consultations amongst the project partnersand consultation with other organisations [74]. The external consultationincluded the completion of a questionnaire by a number of companies, whichincluded information about their geographical market breakdown by value.The chapter focuses on the US and China as two main areas with significantpotential for development within the global market for utility HRSGs, and onthe home market in the UK. Non- technical barriers to future success withinthese markets are identified and discussed.

6.2 Market Survey

The results of the questionnaire survey have been used to give an idea ofwhich markets are most active. The small response to the survey means thatconfidence in the results is low.

The geographical market share averaged over the thirteen questionnaireresponses received are shown in Figure 34 below:-

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Figure 34: Average percentage of business by geographical market.

Looking at the industrial scale sector alone, a breakdown of 68 enquiriesreceived by M E Engineering over the last 18 months is shown in Figure 35below:-

Figure 35: Percentage of enquiries coming from geographical market(Courtesy of ME Engineering Ltd).

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10 respondents provided a breakdown of the proportion of the HRSGs theysupply (by value) in each of 6 size categories. The averaged information isshown below:-

Figure 36: Average percentage of business by HRSG size.

This simply shows that there is activity at all scales. It is based on a simpleaverage of the percentage of units (by value) that each company supplies.Since the companies that supply the larger units also have far larger turnover,in value terms the market is dominated by the large units.

6.3 Market Perception amongst Consultees

Consultees in the US suggest that the market for utility scale HRSGs is verypoor currently. Prior to the last year or so, the market in the US was buoyant.HRSG companies had expanded to meet a demand for new utility scale powerplant. However the market is now largely saturated and there is generationover-capacity. Transmission and distribution networks are close to fullcapacity and finance for merchant plant cannot be obtained in the currenteconomic climate. Siemens [10] expect the US HRSG market to slumpconsiderably over the next few years. Consolidation amongst HRSGcompanies in the US is expected. At the industrial scale there is more activity.There are opportunities for the development of CHP schemes on industrialsites, largely driven by security of price and supply issues in the volatilederegulated electricity market. Concern over climate change is not yetperceived as a significant influence on policy or the market in the US.However, the Clean Air Act is having an influence at the industrial scale.Consents are specifying lower NOx emission levels and rather than retrofittinglow NOx boilers and selective catalytic reduction (SCR) some companies areopting to switch to a completely new CHP scheme.

One consultee identified Russia as a good current market due to the need toreplace ageing and inefficient plant. The same is true of Central and Eastern

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European (CEE) countries. The market in CEE countries is likely to beenhanced as the EU enlarges as trade with them will become easier and theywill be striving to meet EU environmental standards. Turkey was identified asa good market due to low gas prices and a large demand for electricity. TheMiddle East was identified as a market with good potential due to theabundance of open cycle gas turbine plant that could be retrofitted withHRSGs for improved efficiency by operating in combined cycle mode or forpower augmentation by turbine inlet chilling. One consultee identified Italyand Spain as good markets for oil replacement plant and the Middle East fordesalination plant.

The market in China is expanding rapidly, but is viewed as a difficult place todo business. This is due to the bureaucracy of complying with the local codesand standards and the fierce competition from local manufacturers. Themarket in Indonesia is also apparently growing, but competition from Chinesemanufacturers is stiff here too.

A number of other markets were identified by consultees as still being active,despite the general depression of the CHP market throughout Europeassociated with falling electricity prices and rising gas prices. Within Europethe markets in France, Spain, Italy, Germany and Scandinavia are perceived asbeing most active for the development of CHP projects. German andScandinavian markets are seen as being more highly regulated still (lesscompetitive pressure on wholesale electricity prices) and there is price supportfor CHP schemes in Germany for a limited period. Some new CHP schemes inGermany benefit from a guaranteed feed in price. France, Spain and Italy alsohave support mechanisms in place for CHP.

6.4 UK Market

The UK electricity generator market has essentially two sub-sectors, utilityCCGT / CHP and industrial CHP as outlined in Table 8.

DISTRIBUTION BY MWe

+1 MWe +10 MWe +40 MWe +500 MWe

UtilityCCGT/CHP

60 20

IndustrialCHP

200 80 20

Table 8: UK power generation market sectors.

Utility CCGT/CHP are required to compete with conventional plant under theNew Electricity Trading Arrangements (NETA). Industrial CHP plants arestruggling under NETA trading conditions and most are currently operatingtheir steam and power supply contracts at a loss. There is therefore a degree ofturmoil within the market with attrition expected amongst some of the players.However despite competition problems both sectors cannot ignore the need toconsider widespread integrity and performance improvements to meet NETAmarket and client contractual demands.

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6.4.1 Non-Technical Barriers in the UK Utility HRSG Market

In terms of sustaining a profitable business based on the internal UK utilityHRSG market certain barriers currently exist:

6.4.1.1 Current Surplus of Generating Capacity in the UK

The electricity market in the UK is currently oversupplied, with the ‘SevenYear Statement’ published by the National Grid Company in 2002 [75] statingthat the capacity available for the 2002/3 winter is 67564MW. This capacity ismade up as shown in Figure 37 below, with CCGTs contributingapproximately 32.5% to the overall generation mix. Electricity demand inextreme winter weather conditions is expected to reach 55306MW, giving asurplus plant margin of 22.2%. However, in normal weather conditions, thepeak demand is projected to be 52500MW (this was the peak demand duringthe winter of 2001/2), resulting in an even higher plant margin. This isattributed to the fact that governmental responsibilities for sufficient andreliable power generation in the past have led to capacity above actual need.

Figure 37: UK generation capacity available for the 2002/3 winter.

Although a reasonable margin on plant capacity is obviously a necessity, theUK remains oversupplied and, as a consequence, energy prices are very lowand are likely to remain so for the foreseeable future. This means that althoughCCGTs are relatively cheap to build and operate (see Sections 3.8.1 and3.8.2), they remain economically unviable under current market conditions.This, coupled with the high price of natural gas (see below) not only makesthe building of new, utility-scale HRSGs unlikely, but has also resulted in therecent mothballing of some UK CCGT plant.

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6.4.1.2 Fluctuations in the Price of Natural Gas

Recently investors have been dissuaded from investing in CCGT plant by thevolatility in the price of natural gas. Price volatility results in difficulties inreliably forecasting the overall costs occurred over the entire operating life ofthe combined cycle plant.

6.4.1.3 Current Unpredictability of the UK Retrofit Market

With little in the way of large new-build utility plants in the UK, the marketfor upgrading existing facilities within the country must be the primary focus.The effects of flexible operation are becoming more and more apparent tooperators, so the potential for upgrade opportunities is large. However withflexibility upgrades on drainage, pressure parts and casings expected to bebetween £100k and £400k per HRSG, the depth of the market remainsuncertain. Factors within the operators market as a direct result of deregulationsuggest that the availability of finances to fund these upgrades is questionable.

6.4.2 UK Industrial CHP Market

The annual Directory of UK Energy Statistics (DUKES) for 2001 givesvarious data for CHP schemes in the UK. The data is gathered through theGovernment’s CHP quality assurance scheme. The majority of schemes arefuelled with natural gas (61%), with fuel oil accounting for 7%, 2% fromrenewables and the balance from various process exhausts or by-product fuels.The majority of the 1573 schemes are small, but generating capacity isdominated by the minority of larger schemes.

Electrical capacity sizerange

% of total number ofschemes

% of total generatingcapacity

< 100 kWe 43.2 0.9100 kWe – 999 kWe 40.1 3.21 MWe – 9.9 MWe 12.1 16.2

> 10 MWe 4.6 79.7

Table 9: CHP Schemes by size, 2001.

Figure 38 below shows the installed CHP capacity in the UK for the last 5years.

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Figure 38: Installed CHP capacity in the UK 1997-2001.

The chart shows that through the 1990s the pace of addition of CHP capacitywas accelerating with the rate peaking in 2000 with 844MW of plant beingcommissioned, a 22% increase on the previous year. However in 2001 only 38MW of capacity was added. As part of this study the Combined Heat andPower Association and a number of companies involved in the supply andinstallation of CHP schemes were consulted. All of these reinforced the viewof the market given by the DUKES statistics. The market for CHP schemeswas buoyant towards the end of the 1990s but then collapsed. The reasons forthe current depressed state of the market are discussed below. The trend ismirrored in the figures for electrical export from CHP schemes. In 2000 8482GWh were exported. In 2001 the figure had dropped to 5960 GWh. Similarproblems with the CHP market apply elsewhere in the EU, such as in theNetherlands and Germany [76].

6.4.2.1 Stricter Consents Policy

In 1998 the Government introduced a ‘stricter consents policy’ on gas fuelledelectricity generation plant. Under this policy, consent for the development ofany gas fired power plant of generating capacity greater than 10MW wasrequired from the Government. The measure was introduced because ofconcern that the electricity market was being distorted and coal fired plant wasbeing unfairly penalised by this. The policy was kept in force while a reviewof electricity arrangements was carried out. It ended in 2000 with theintroduction of the New Electricity Trading Arrangements (NETA). The onlyplants granted consents during this period were CHP plants. The stricter

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consents policy had the effect of concentrating attention on the developmentof CHP projects.

6.4.2.2 Natural Gas Prices

Most CHP plant is fuelled with natural gas. The interconnection of the UK gasgrid with that of continental Europe via the Bacton-Zeebrugge pipeline wasaccomplished in October 1998. This has exposed the UK to the higher pricesof the continental European market and UK natural gas prices haveconsequently risen from a low of under 14p/therm in 1999 to 19p/therm in2001 [77].

6.4.2.3 New Electricity Trading Arrangements

The New Electricity Trading Arrangements (NETA) were brought into forcein March 2001. NETA introduced new regulations governing the deregulatedelectricity market in the UK. Previously the pool price at any one time waspaid to all generators supplying power at that time and the price was set by themost expensive generator. Under NETA, most wholesale electricity salesbetween generators and retailers are now concluded well in advance with thetiming, volume and price of supply fixed. A balancing mechanism provides ameans of meeting short term demand fluctuations. Fierce competition sincethe liberalisation of the market has driven down the prices at which contractshave been concluded. Since 1998, when NETA was first proposed, electricitywholesale prices have fallen by 40%. Between April 2001 and February 2002baseload prices have fallen by 20% and peak prices by 27% [78].

What is more, CHP schemes are unlikely to get the best prices. CHP schemesare generally small compared to utility scale plant so have little marketinfluence. Penalty payments are levied if a generator fails to meet itsscheduled supply profile. Many grid connected CHP schemes tend to run tomeet the heat or steam demands of its customer, rather than an electricitysupply profile, and the electrical output is therefore not entirely predictable.The CHP scheme is exposed to a potential mismatch between the heat andelectrical demand profiles that it is trying to meet. This results either in NETApenalties or running at lower efficiency than the design point.

6.4.3 Other Barriers for UK Firms

The grid has evolved to distribute electricity from a small number of largegenerators. A substantial amount of power is wasted in the form oftransmission losses. In 1999 it is estimated that transmission and distributionlosses accounted for 1336 TWh, equivalent to 11.6% of the World’s finalelectricity demand [79]. CHP plants are generally connected to local gridnetworks and the separation between generator and consumer is smaller,resulting in lower transmission and distribution losses. Decentralised orembedded generation can also have benefits in strengthening the local grid andimproving power quality. These benefits of embedded generation are currentlynot fully reflected in the sale price of electricity from CHP schemes. Howeverthe connection of a large number of smaller generators may also causedifficulties for the grid system relating to fault levels, islanding and power

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quality. Where substantial modifications are required to the grid to allowconnection, the cost to the scheme developer may be prohibitive, especiallyfor smaller schemes. The cost and complexity of grid connection is currently abarrier to the development of smaller CHP schemes.

Anecdotal evidence suggests that banks are not willing to invest in energyprojects at present due to the risk associated with price volatility anduncertainties within energy markets. The market is in such a poor state that themajor CHP developers have disbanded their development teams. The onlyprojects that may go ahead currently are either ones where all of the powerwill be consumed on site or that have another factor driving them, such asavoided grid connection strengthening costs.

One UK consultee identified the diversity of European standards as being aproblem for companies trying to export to other EU countries. A commonEuropean standard for shell boiler design is being introduced (EN12953), butthe consultee was concerned that oversees clients will continue to specify theirown national standards.

The current strength of sterling was also identified as a problem for UK HRSGsuppliers. There is strong competition in the market place and other Europeansuppliers can undercut UK companies, even in the UK despite their highertransport costs.

6.4.4 Future Industrial CHP Market Potential in the UK and MainlandEurope

The European Commission sponsored ‘Future Cogen’ study assessed thepotential for the expansion of CHP within EU member states and Central andEastern European (CEE) states. It modelled the growth of CHP under fourscenarios ranging from the pessimistic ‘deregulated liberalisation’ scenario tothe optimistic ‘post Kyoto’ scenario. In the ‘deregulated liberalisation’scenario EU CHP capacity grew by only 16 GW from a base level of 65GW to81GW in 2020. In contrast, under the ‘Post Kyoto’ scenario installed capacitygrew by 130GW to 195GW by 2020. Under the ‘Post Kyoto’ scenario, CHP inthe UK would grow from a base level of 3453GW to 27215GW in 2020. Notall of this growth would come from CHP schemes involving steam generationbut it would represent a substantial opportunity for growth in the HRSGindustry[80].

At present CHP opportunities in the UK are limited to those that have specificdriving factors other than just more efficient use of fuel. The UK governmenthas set a target of achieving an installed CHP capacity of 10GW by 2010,compared to the current capacity of 4801MW (2001). Some policy measureshave been introduced to stimulate the CHP market. Fuels used in CHP areexempted from the Climate Change Levy (CCL). In the April 2002 budget itwas announced that electricity exported from CHP schemes will also beexempted from the CCL (subject to approval under EU state aid rules).Enhanced capital allowances (ECAs) are allowed on some items of CHP

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equipment, increasing the opportunities for investment in CHP. HoweverECAs are not yet available on all items in a complete installation.

The EU target is to double CHP capacity as a fraction of total electricitygeneration capacity from 9% (1994) to 18% in 2010. In order to achieve thistarget the EU have proposed a CHP directive[81]. The key points of thedirective are:-

• The introduction of a common definition of cogeneration;• Targeting of support at schemes with an electrical capacity of up to 50MW

(or at the first 50MW of larger schemes);• Providing a guarantee of the origin of electricity from cogeneration;• The establishment of efficiency criteria for cogeneration;• An obligation on member states to establish their national potential for

cogeneration;• Allowing national support schemes for cogeneration in the short to

medium term (under state aid rules);• The establishment of objective, transparent and non-discriminatory rules

for grid connection and reinforcement;• A requirement for member states to review legislative frameworks with a

view to reducing barriers to cogeneration.

These actions should enhance the European HRSG market.

The Kyoto agreement sets binding targets for greenhouse gas emission cuts forsignatory countries. CHP has been identified as one of the most cost-effectivemethods of cutting CO2 emissions. Joint Implementation and EmissionsTrading mechanisms can potentially be harnessed to help develop CHPschemes. In ‘Annex II’ countries, the Clean Development Mechanism mayoffer opportunities to help develop CHP schemes.

6.4.5 Action to Stimulate the UK Market / Support the UK Industry

A common view was expressed by all UK consultees: there is no problem withthe product but huge problems with the market. No need for DTI fundedresearch was identified – the technology is essentially mature. However theGovernment does need to act to stimulate the UK market. The combination ofNETA and a high natural gas price has dramatically reduced the market forCHP and the climate change levy is not seen as being an adequate incentive toinvest in new HRSGs / CHP schemes. Enhanced support for CHP is requiredfrom government and a ‘CHP obligation’ seems to be the preferredmechanism in the industry.

The current pessimistic industry view is supported by a report by Forum forthe Future / Cambridge Econometrics commissioned by the Combined Heatand Power Association and released in October 2002. This predicted that totalinstalled capacity would only reach 6.6 GWe by 2010 and 8.6 GWe by 2020under current conditions, compared to the government target of 10 GWe by2010.

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The Combined Heat and Power Association has therefore identified thefollowing steps as means of improving the situation for the development ofCHP projects:-

• Introduction of a CHP obligation, similar in form to the RenewablesObligation but with a lower buy-out price, to provide an underpinningmarket mechanism

• A proactive planning and communication strategy• Adequate resourcing within government• Full implementation of existing support mechanisms for CHP• Action to address existing and emerging barriers to CHP• Delivery of effective support to emerging technologies

6.5 North American Market

The North American market at present is considered by some to be expandingsignificantly, in contrast to the opinions expressed by some consultees (seeSection 6.3 above). In the year 2001 according to Power Magazine [61] aninstallation record of 48.6 GWe in total was established for new gas turbinebased power plants. This figure surpasses the 1974 record of 43 GWe for newinstallations. However, the 2001 record is envisaged as being short lived as aresult of the 66 GWe for 2002 and 69 GWe for 2003 announced or underconstruction [61]. Whilst mid-sized aero-derivative gas turbines are part of thesales surge, the vast majority of this increased capacity has been, and no doubtwill continue to be in large, utility scale machines.

When it is considered that just 27 GWe of new capacity came on line in theyear 2000, the extent of the rapid growth within the North American market isclearly apparent.

Whilst the size of the North American market is clearly large, there areobvious signs of the high level of competition existing in this potentiallylucrative business sector. Evidence of this rivalry can be found from theundisputed fact that in recent years the market has attracted the attention ofseveral new competitors, all contending for their share of the profits.Furthermore this additional competition has emerged from both internationalmanufacturers winning American based contracts and American basedcompanies with previously limited interests in the HRSG market suddenlyexpanding their involvement.

From what was essentially a US supplier only market, there has been a recentspate of key contracts awarded to non-US manufactures such as Toshiba(Tokyo, Japan), CMI (Brussels, Belgium) and Hitachi (Tokyo, Japan). FosterWheeler is a prime example of an American company expanding its activitiesin the HRSG market. Prior to 1997 its HRSG interests were considered not tobe a prime business within the company. However, the company claims thathaving recognised the huge potential for rapid combined cycle power plantexpansion, it strategically expanded into this area from its traditional businessof solid-fuel boiler fabrication. The end result is that in just 5 years its HRSGbusiness has now grown from a minor business sector to its largest one.

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6.5.1 Possible Non-Technical Barriers to Development of Combined CycleTechnology within the USA

Some analysts [82, 83] are sceptical about the future of the North Americanmarket and predict as much as 50% of the announced future projects in thestates will not make it further than the drawing board. The main reasons citedare:-

• Inadequate supplies of natural gas: Natural gas is the fuel of choice for atleast 95% of the projects. The US Energy Information Administrationestimates that natural gas production and delivery would have to rise 40-50% over the next 15 to 20 years to supply the projected combined cycledevelopments. This is viewed as a somewhat heroic task based on the agedstate of the nation’s gas fields and requirement for extensive new pipelinesfor gas delivery.

• Price of Gas: Market forces are also at play with the high price of gasdissuading investors in gas turbine technology and looking towards coal,nuclear and hydro power for their energy solutions. The use of gasificationcombined cycles is still however a possible lucrative market that shouldnot be ignored.

6.5.2 The US CHP Market

In the US, the Assistant Secretary for Energy Efficiency and RenewableEnergy has issued a CHP challenge calling for industry and government towork together to double the capacity of CHP in the US by 2010. According tothe US Combined Heat and Power Association (USCHPA), the currentinstalled capacity is around 65GW, on the way from 46GW in 1998 to the goalof 92GW in 2010. However measures to support this target are limited. Thereare federal programmes supporting awareness raising, research anddemonstration. A 10% investment tax credit for CHP was included inproposed legislation passed by both houses of Congress in the last two years,but it was not enacted into law due to disagreements over other provisions ofthe law. In order to avoid revenue loss, the same provision would havestretched out CHP asset depreciation for tax purposes, so it was consideredsomething of a neutral measure by the CHP industry. There are federalrequirements that CHP operators achieving certain levels of efficiency cancompel utilities to purchase their power at the utilities' avoided costs. This wasa strong incentive for CHP in earlier times when incremental power generationcosts were quite high, but motivates fewer projects now, according to theUSCHPA. Few states have introduced mechanisms to support CHP orequitable rules to govern the connection of CHP schemes to the grid.

6.6 Chinese Market

In terms of future world markets the People’s Republic of China is significant.Currently the installed power generation capacity in China is the secondlargest in the world, with the United States being in first position. However theper capita electric power utilisation level in China is still low. China expectsits economy to grow at an average rate of 7% or more per year over the nextdecade. Therefore if a constant ratio of primary energy to gross domestic

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product is assumed for this period the primary energy consumption wouldnearly double. Thus the electric generating capacity for the nation will berequired to increase dramatically.

China is a large coal production country with coal as its main source of powergeneration. This situation is envisaged as remaining unchanged in China forthe foreseeable future. Of the ~300GWe of installed capacity at the end of1999 fossil fuel capacity was almost 75%. Coal fired units account for morethan 95% of the fossil fuel fired capacity. China is therefore actively pursuingClean Coal Technologies (CCTs) as a means of meeting their future energyrequirements with integrated gasification technology (IGCC) and supercriticalboilers attractive options for the 21st Century.

China has made a decision to build a large-scale IGCC demonstration powerplant and is currently conducting preparatory research for such a project.Yantai power plant in Shandong province has been proposed as the host sitefor this demonstration for which two 400MWe IGCC units are beingconsidered.

Assuming that the Yantai IGCC project proceeds, it could be in commercialoperation by the end of year 2005. Wider deployment of IGCC could,therefore, be forecast for the period beyond 2005-2010. The potential rise ofIGCC within the market place over a 15-year period is predicted as resultingin a 17% share in the coal-powered generation market by the end of 2025.With the HRSG being an integral component of the IGCC plant (as outlined inSection 4.4.1) the knock on effect of HRSG sales in the Chinese market placemay well be significant. However, it is apparent that the final market size willdepend entirely on the success of the demonstration and the cost reductionsachieved.

In addition, the air blown gasification combined cycle (ABGC) has beenproposed as another possible contributor to China’s future energy generation.This cycle also is dependent on the use of the HRSG to enhance overallperformance. Essentially the ABGC is a hybrid combined cycle powergeneration technology based on the partial gasification of coal [84]. Thecombustion of the fuel-gas is undertaken within a gas turbine. The combustionof the remaining gasifier char is carried out in a circulating fluidised bedcombustor where steam is generated to drive a steam turbine. A key feature ofthe ABGC process is its potential to achieve high cycle efficiencies with lowenvironmental emissions.

ABGC development is estimated at being around five years behind IGCC.However, its main attractiveness stems from the fact that it is well suited topoor quality high sulphur coal which is in abundance in the developingcountries of China and also India.

Predictions indicate that on the basis that a working plant could be establishedwithin the period 2005-2010, then within 15 years some 10% of the marketshare of coal fired power generation could be supplied via ABGC.

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Detailed studies of CCTs within the Chinese market place have beenundertaken by Mitsui Babcock [70, 84, 85] along with various Chinese researchinstitutions. This previous work has been undertaken with the financialsupport of the DTI.

6.6.1 Possible Non-Technical Barriers to Development of Combined CycleTechnology within China

The specific market for HRSGs within China is clearly dependent on theChinese Authorities’ adoption of a positive policy on cleaner coaltechnologies. In general the Chinese market is seen as being hindered by sevenfactors listed below.

6.6.2 Complex Administrative Procedures

China is in the process of government and administration reform andenormous changes have been made in recent years. In 1998, the State PowerCorporation (SPC) replaced the Ministry of Electric Power and thegovernment's administrative responsibility for the power industry wastransferred to the State Economic and Trade Commission (SETC).

Traditionally, the State Development and Planning Commission (SDPC) is thetop authority responsible for approving new power plant projects. The StateEconomic and Trade Commission (SETC) is the top authority responsible forapproving renovation projects. These two commissions are the most powerfulgovernment agencies in terms of applying for and receiving approval forcleaner coal technology projects.

The first step in influencing the SDPC and SETC is to inform them of thetechnology, the history of development, the current situation, technical andeconomical features, advantages and disadvantages. Providing them withdocuments, inviting them to attend a workshop, or visit research facilities ordemonstration sites therefore allows this interaction to take place. Secondly, ifa project is being prepared, a feasibility study report with favourable financingarrangements such as a soft loan or a grant from international organisationswill certainly have a positive influence on the approval process.

6.6.3 Low Institutional Capability

The lack of collaboration between design institutes, research institutes andmanufacturers acts as a key barrier to international technology transfer. MostR&D for cleaner coal technologies requires a multidisciplinary approach. Inaddition, China’s state-owned manufacturing enterprises have not developedcommercial or innovative skills and there is a lack of market pressure onChinese enterprises. With the deepening of economic reform and systemrestructuring, however, all state-owned enterprises and research institutes willaccelerate the process of upgrading management and technology in order toimprove competitiveness.

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6.6.4 Environmental Emission Controls

With China being a developing country, the standards relating toenvironmental protection are still much lower compared to those in fullyindustrialised countries. The regulations on emissions from thermal powerplants, for example, are not so stringent. This situation does not put enoughpressure on industry to create a demand for cleaner coal technology hardwareand services. In addition, the implementation of these standards is sometimes,and in some places, poor and inconsistent. The lack of enforcement andmonitoring therefore also has a negative influence on environmentalinvestment. Environmental protection, however, is one of China’s basicnational policies for sustainable development. With the rapid economicdevelopment and improvement of living conditions environmental policy isbeing given a higher priority and becoming more stringent.

6.6.5 Financial Issues

Lack of finance is often an important barrier to cleaner coal technologytransfer. The following measures will enhance the possibilities for technologytransfer:

(i) Both government and international organisations will devise morefavourable policies and offer concessional finance for the introduction ofadvanced cleaner coal technologies in the form of soft loans, capital subsidiesor grants.(ii) Cleaner coal projects will become economic if the issue of pollutioncosts is addressed. This issue is linked to the reform of the pollution levysystem.(iii) The cost of cleaner coal equipment manufactured in China is muchlower than the cost of imported equipment. Hence, there is a strong economicand financial incentive to maximise the local manufacture of equipment. Thiscan only be realised with technology transfer.

6.6.6 Maturity of the Technology

As end users, power companies will only employ mature technologies. It isgenerally deemed to be crucial that at least two reference plants of the same orcomparable size should be operating. For newly developed technologies ademonstration project of relevant size and parameters is important.

6.6.7 Issue of Intellectual Property

Gradually, the move to commercialise state-owned industries is strengtheningrespect for intellectual property rights. Furthermore, the move to a competitivemarket will eventually bring about a situation in which companies in Chinawill have less incentive to share information with each other.

6.6.8 Long-Term Collaboration

Joint ventures between Chinese and foreign firms or involving technologylicensing agreements can potentially facilitate the transfer of the wider

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knowledge, expertise and experience necessary for managing technologicalchange. Joint ventures in particular have one important feature which can helpcollaborative relationships in China to be successful: a relationship that givesboth sides a stake in the future success of the product or service concerned,and allows the build up of trust.

6.7 Conclusions

• Whilst the utility scale HRSG market has been healthy in recent years,there is a predicted sharp downturn in the HRSG market in the short-medium term due to plant over capacity. The situation is not expected topick up again until around 2007-2011. Key future HRSG markets are seenas the USA and China (via IGCC). Non technical barriers in these twomarkets include the price/availability of gas in the USA andadministrative/financial issues in China.

• For industrial scale HRSGs, the European market is depressed due tofalling electricity prices and rising gas prices. However potential marketsinclude Russia, Central and Eastern European (CEE) countries, Turkeyand the Middle East. In the USA, despite problems on the utility scale,there are still opportunities for development of CHP schemes on industrialsites, largely driven by security of price and supply issues in the volatilederegulated electricity market.

• The current surplus of generating capacity in the UK and fluctuations inthe price of natural gas have led to a low requirement to build large scalepower generation plant within the UK. The only plus side is that with theeffects of flexible operation becoming more apparent, plant performanceupgrade opportunities are present.

• The combination of NETA and a high natural gas price has dramaticallyreduced the UK market for CHP and the climate change levy is not seen asbeing an adequate incentive to invest in new HRSGs / CHP schemes.Enhanced government support for CHP is required if the target of 10 GWe

by 2010 is to be met.

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7 UK ACTIVITIES

This chapter reviews the prospects of UK manufacturers in the global HRSGmarket, and their capabilities. Areas of current research, development anddemonstration (RD&D) which are being undertaken in the UK are indicatedalongside recommendations of areas of significant future focus.

7.1 Prospects of UK Suppliers and Manufacturers in the Global Market

Large, new build HRSG manufacture, as with many other heavy engineeringmanufacturing business within the UK, is finding it increasingly difficult tocompete with the low costs associated with both European competition basedon the continent (e.g. in Italy and Spain) and the significantly reduced outlayincurred by manufacturing in East Asia.

With more modular HRSG designs becoming commonplace, the future of UKHRSG companies in the new-build market lies in the ability to sell, supply andassemble HRSGs, based on their own designs and advanced technologies,albeit that the standard components may not necessarily have beenmanufactured inside the country.

Within such an environment, licensing agreements and collaborativepartnerships are therefore deemed essential in order for companies to maintainthe ability to compete in the global market.

In order to form such alliances, UK companies must be in a position to offersomething in return. Under such conditions the requirement to be continuallydeveloping new technologies becomes vital. Therefore to guarantee futurelong-term prospects for UK suppliers and manufacturers in the global market,its knowledge and development of leading edge technologies must bemaintained.

7.2 UK Capabilities in HRSG Design, Manufacture and Supply –Utility-Scale

In terms of UK based large utility HRSG manufacture and design, MitsuiBabcock has a significant presence within the UK.

Mitsui Babcock is a major energy engineering company incorporated in theUK and since 1995, a wholly owned subsidiary of Mitsui Engineering &Shipbuilding of Japan. The company is a technology leader in large fossil fuelsteam generating plant, and specialises in the design, engineering,manufacture, construction, commissioning and after sales servicing of highefficiency, high availability coal, oil, and gas fired boilers for the powerstations of electricity generating companies world wide. The company is also amajor manufacturer and supplier of heat recovery steam generating plant,industrial fluidised bed and other clean burn coal fired boilers, coal millingplant, flue gas desulphurisation plant and low NOx technologies.

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Up until the mid 1990’s and operating at the time as Babcock Energy, MitsuiBabcock was one of the worlds foremost suppliers of HRSGs. In 1993 MitsuiBabcock were nominated as the “worlds leading supplier of HRSGs” and werewinners of the coveted Power Engineering International “project of the yearaward”. To date the company has won contracts in some 23 differentcountries. However by the mid 1990s the HRSG market suffered a severedownturn with limited opportunities and reduced margins. To compound this,the market was migrating from assisted circulation to natural circulationdesigns and the company’s specific technology offering became lesscompetitive. However with a recent upturn in the fortunes of the HRSGmarket particularly in America, Mitsui Babcock have enhanced their productrange by concluding a licensing agreement with Babcock Hitachi KK fornatural circulation designs. Significant orders for utility plant HRSG supplysuch as the natural circulating HRSG for Naco Nogales power plant in Mexicoand the assisted circulated HRSG employed at Blackpoint power station inChina have been completed.

Mitsui Babcock employs approximately 3000 people in its various operationsin the UK and abroad. Its headquarters are at Crawley in the UK but operateslocally with regional operations elsewhere in the UK and around the world.

The company’s strengths lie in its depth of engineering capabilities, itstechnology base, its extensive manufacturing facilities, its considerableexperience in site erection, commissioning and servicing of major power plantin countries across the world and its ability and experience in managing verylarge multi-disciplinary projects. The company’s combination oftechnological, financial and skill resources enable it to deliver projects in arange from £10 million to £400 million, anywhere in the world.

Thermal Engineering International Ltd – Greens is the largest independentmanufacturer of utility HRSG’s in the UK. Originally known as E Green &Son the Wakefield based company has amassed over 150 years of experiencein the field of heat recovery since its founder Edward Green invented andpatented the world’s first economiser which he patented in 1845.

TEI Greens has manufactured Utility HRSG’s for most of the world’s leadingboiler designers/makers as many no longer support their own manufacturingfacilities. TEI Greens has been successful in manufacturing HRSG’s fordomestic and export projects and has a wide experience of different designsincluding vertical and horizontal gas types and once through designs.Currently, around 40% of all the UK’s utility HRSG’s have beenmanufactured by TEI Greens.

TEI Greens are holders of the ASME S & U stamps and have a large facilityof over 100,000m2 with extensive workshops. It has 3 x High FrequencyFinning machines in its Wakefield Factory (10 worldwide) for themanufacture of high frequency welded helical fin tubes as used in modernHRSG’s. The facility is capable of producing over 120,000 tubes and 10 majorHRSG’s per annum.

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There is also a number of major utility-scale HRSG turnkey contractorsoperating within the UK, although their headquarters and manufacturingfacilities are generally based overseas or manufacture is sub-contracted.Alstom Power, Foster Wheeler Energy Ltd, Mott Macdonald, Nooter/Eriksen-CCT Ltd and Siemens KWU all fall within this category.

7.3 UK Capabilities in HRSG Design, Manufacture and Supply –Industrial-Scale

Wellman Robey and BIB Cochran both manufacture and supply smoke tube(shell boiler) type HRSGs. Wellman Robey is owned by the Wellman Groupof the UK and BIB Cochran is owned by the Mechmar Corporation ofMalaysia. Wellman Robey supply units in the 5-10MW range for use inexhaust heat recovery behind GTs; gas and diesel engines; incinerators, kilnsand furnaces; and process integrated units in petrochemical, other chemicaland iron and steel industries. It has its own manufacturing capabilities at itsfactory in Oldbury, and also offers contract manufacturing services. BesidesHRSGs, Wellman Robey supplies a range of fired package boilers and offersafter sales support and maintenance. BIB Cochran similarly supplies units fora range of exhaust heat recovery and process integrated applications. Itmanufactures its products at its factory in Dumfries and Galloway and itsproduct range also includes a range of fired package boilers. It hasrepresentation in many counties in eastern and western Europe, the MiddleEast, south east Asia, India and the Americas. It also provides various aftersales services.

M E Engineering is owned by the Thermax group of India. It only suppliesbespoke units rather than package units. It has a range of water tube designsfor exhaust heat recovery and process integrated applications. In GT exhaustheat applications, the range of GTs served is from 5MWe to around 70MWe.Besides heat recovery systems the company can supply boilers for a widerange of solid, liquid and gaseous fuels. The company does not have its ownmanufacturing facilities, but uses either the factory of its parent company inIndia or sub-contract manufacture.

Industrial HRSG’s are designed and manufactured in house by TEI Greens.These may be of a water tube or smoke tube design and may incorporatesupplementary or auxiliary firing where required.

The UK arm of Nooter/Eriksen also supplies industrial HRSGs although itsdesign capability is based in the US and manufacture is sub-contracted.

Details of each of the companies described above are summarised in Table 10below.

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Company UltimateParent

Company

HRSGBusinessAnnual

Turnover(range)

HRSG Designs Scale Applications Capabilities Other Products

BIB Cochran MechmarCorporationMalaysia

- Smoke tube,Package,Optionalsupplementaryfiring

Up to 35 tph steam atup to 35 barg

CHP, GT exhaust,reciprocating engineexhaust, incineratorflue gas,petrochemical, otherprocess industry

Site surveys,Design,Manufacture in house,Installation,Commissioning,Training,Service,Repair and maintenanceSpares supply

Gas burners,Package units:‘Thermax’, ‘Clansman’ and‘Calpac’ hot water boilers‘Wee Chieftan’, ‘Thermax’single and double furnace,‘Borderer’ and ‘Coalmaster’steam boilers

WellmanRobey

WellmanGroup, UK

$1-$5M Smoke tube,Package,Optionalsupplementaryfiring

5-10 MW or up to20MW ifsupplementary fired.Up to 40 tph steam atup to 35 barg and360°C, saturated orsuperheated

CHP, GT exhaust,reciprocating engineexhaust, incineratorflue gas,petrochemical, otherprocess industry, iron& steel

Design,Manufacture in house,Commissioning,Training,Operation,Service,Repair and maintenance,Spares supply

Pressure vessels,Sub-contract manufacture,Package units:‘Robey’ low NOx boilers,‘STONE’ steam generators,‘Ygnis’ hot water and steamboilers

M EEngineering

ThermaxGroup, India

$0.5-$1.0M Smoke tube,Water tube,Optionalsupplementaryfiring

Up to 55 tph steam atup to 60 barg and450°C, saturated orsuperheated

CHP, CHP & cooling,GT exhaust,reciprocating engineexhaust, incineratorflue gas (clinical,municipal),petrochemical, otherprocess industry,biomass IGCC, iron& steel, offshore oilproduction

Design,Contract manufacture localto project or at parentcompany factory in India,Installation,Commissioning,Training,Repair and maintenance

Biomass & fossil solid fuelboilers (travelling , dumpingand pinhole grates, fluidisedbeds) up to 100 tph evaporation,Liquid / gas fired single / bidrum water tube boilers up to300 tph evaporation,Fired once through coil boilersup to 50 tph evaporation and200 barg

Re-tubing, air-preheaters,economisers,Heat recovery to water,

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water/glycol, thermal oil,Absorption cooling

TEI Greens ThermalEngineeringInternational

$1-10M Smoke tube,Water tube,Optionalsupplementaryfiring or auxiliaryfiring

Various from industrialto utility scale.

Waste heat recoveryfrom boiler andprocess flue gasstreams in powergeneration (CHP &CCGT), refining,chemical, process andgeneral industries.

Design,Manufacture in house,Unit build,Erection,Commissioning

Helical finned tube manufacturein both solid and serrated finprofiles.Utility-scale HRSGmanufacture in house, unitbuild, erection andcommissioning (but not design)

Nooter/Eriksen– CCT Ltd

CIC GroupInc.

- Smoke tube,water tube,optionalsupplementary orauxiliary firing.

Various from industrialto utility scale.

Power generation(CHP & CCGT),designs for wasteincineration andprocess industryapplications.Inclusion of catalystspossible.

Design (overseas),Manufacture (sub-contracted),Unit build, erection,commissioning.

Optimised designs for cyclingand constructability.Enhanced Oil RecoveryOTSG’s for 80% quality steam.

Table 10: Capabilities of UK industrial HRSG suppliers.