(70) Therefore, the risk of sulphuric acid dew point attack ... - DTI Home
(70) Therefore, the risk of sulphuric acid dew point attack ... - DTI Home
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<strong>Therefore</strong>, <strong>the</strong> <strong>risk</strong> <strong>of</strong> <strong>sulphuric</strong> <strong>acid</strong> <strong>dew</strong> <strong>point</strong> <strong>attack</strong> is minimal as <strong>the</strong> <strong>dew</strong><br />
<strong>point</strong> is well below <strong>the</strong> gas exit temperature. However, some HRSGs are fed<br />
with exhaust gas from GTs burning a slightly sour gas, up to 2000 vppb<br />
sulphur equivalent. While operation at base load provided a gas exit<br />
temperature above <strong>the</strong> <strong>sulphuric</strong> <strong>acid</strong> <strong>dew</strong><strong>point</strong>, operation at part load reduced<br />
<strong>the</strong> gas temperature at <strong>the</strong> outlet <strong>of</strong> <strong>the</strong> condensate pre-heater to <strong>the</strong> <strong>point</strong><br />
where <strong>the</strong> <strong>dew</strong> <strong>point</strong> was breached and <strong>sulphuric</strong> <strong>acid</strong> deposition occurred<br />
(Figure 31). This particular plant cycled between base load and part load on a<br />
daily basis. The deposit layer was very highly concentrated <strong>sulphuric</strong> <strong>acid</strong>,<br />
which also attracted very fine particles <strong>of</strong> siliceous material and particles <strong>of</strong><br />
gas duct internal lagging. The fact that <strong>the</strong> <strong>sulphuric</strong> <strong>acid</strong> remained highly<br />
concentrated precluded corrosive <strong>attack</strong> on <strong>the</strong> tube or finning, while <strong>the</strong> plant<br />
was in operation. Off load moisture ingress into <strong>the</strong> HRSG via <strong>the</strong> rain damper<br />
mobilised some <strong>of</strong> <strong>the</strong> <strong>acid</strong> deposits down <strong>the</strong> casing walls. One option being<br />
considered to prevent fur<strong>the</strong>r deposition is to bypass <strong>the</strong> preheater at low loads<br />
(a bypass line is fitted), although this would result in a fur<strong>the</strong>r performance<br />
penalty.<br />
Figure 31: Condensate preheater deposits (Courtesy <strong>of</strong> Power Technology).<br />
3.6 Control and Instrumentation Issues on HRSG Plant<br />
Modern CCGTs are operated with a large degree <strong>of</strong> automation to minimise<br />
<strong>the</strong> <strong>risk</strong> <strong>of</strong> plant trips and o<strong>the</strong>r damaging incidents. Automated sequences are<br />
used for common plant procedures such as start-up and shutdown, minimising<br />
<strong>the</strong> participation <strong>of</strong> <strong>the</strong> operator and hence <strong>the</strong> <strong>risk</strong> <strong>of</strong> error and variability<br />
between <strong>the</strong> actions <strong>of</strong> different personnel. However, <strong>the</strong>se sequences can stop<br />
partway due to failures on field devices such as limit switches and<br />
<strong>the</strong>rmocouples. Moreover, control and instrumentation problems on some<br />
plants mean that a high level <strong>of</strong> spurious and consequential alarms may be<br />
(<strong>70</strong>)
initiated and presented to <strong>the</strong> operator. In this situation, <strong>the</strong>re is a danger that<br />
important alarms could be overlooked, leading to a higher <strong>risk</strong> <strong>of</strong> plant trips.<br />
Some <strong>of</strong> <strong>the</strong>se problems are related to <strong>the</strong> presence <strong>of</strong> poorly specified<br />
instrumentation, particularly actuators and valves, and this means that<br />
upgrading <strong>of</strong> such equipment is an ongoing process on new plant. It is known<br />
that <strong>the</strong> incidence <strong>of</strong> plant trips that are control and instrumentation related<br />
drops considerably in <strong>the</strong> first months and years <strong>of</strong> operation from levels that<br />
can be as high as 50% during commissioning. It is vital to eliminate spurious<br />
trips due to faulty instrumentation early in a plant’s lifetime, as <strong>the</strong>se are very<br />
damaging. For example, calculations performed on a P91 superheater header<br />
with full penetration welds under an optimised hot-start/shutdown procedure<br />
demonstrated that a hot restart following a unit trip is 41 times more damaging<br />
in terms <strong>of</strong> <strong>the</strong>rmal fatigue damage than a hot start following a normal<br />
shutdown [51] .<br />
The level <strong>of</strong> detail provided on some sequence displays is <strong>of</strong>ten insufficient to<br />
identify <strong>the</strong> plant condition preventing a sequence from progressing. The<br />
sequence logic is <strong>of</strong>ten so complex that even minor faults can be difficult to<br />
pin<strong>point</strong> and rectify, with sequences having to be overridden manually and<br />
stepped through to try and identify <strong>the</strong> sequence hold. It is usually essential to<br />
have a member <strong>of</strong> staff pr<strong>of</strong>icient in control and instrumentation issues<br />
available to deal with any automation related problems that may arise.<br />
The start-up <strong>of</strong> a unit can be potentially influenced by a wide range <strong>of</strong> active<br />
operational constraints generated from within <strong>the</strong> GT itself and also from <strong>the</strong><br />
HRSG and <strong>the</strong> ST. These constraints adversely affect <strong>the</strong> run-up process by<br />
inhibiting firing on <strong>the</strong> GT until <strong>the</strong> current active constraint has been relieved.<br />
This gives rise to <strong>the</strong> <strong>risk</strong> <strong>of</strong> variable run-up times for each start-up on each<br />
unit and clearly becomes even more relevant in <strong>the</strong> event <strong>of</strong> moving <strong>the</strong><br />
operational regime away from base-load. Faults with field devices can<br />
exacerbate this, making it difficult to predict overall run-up and loading times<br />
with absolute accuracy. The above factors have become highly significant<br />
under <strong>the</strong> New Electricity Trading Arrangements (NETA), where significant<br />
financial penalties can exist for not getting up to load on time.<br />
3.7 Flexible Operation <strong>of</strong> HRSG Plant<br />
To take economic advantage <strong>of</strong> fluctuations in <strong>the</strong> wholesale price <strong>of</strong><br />
electricity, it has become advantageous within certain markets (particularly <strong>the</strong><br />
UK) for generating plant to operate flexibly. This may involve regular ‘twoshifting’<br />
where plant is taken <strong>of</strong>f load for several hours overnight, shut down<br />
at weekends and/or fluctuations between full load and part load or minimum<br />
stable generation. In <strong>the</strong> UK, <strong>the</strong> volatility in gas price and increased<br />
dominance <strong>of</strong> gas generation also means that companies with a portfolio<br />
comprising generation reliant on more than one fuel source can make up <strong>the</strong>ir<br />
contracted output as <strong>the</strong>y see fit. These factors have resulted in many CCGTs<br />
(and hence HRSGs) designed for largely base-load operation being subjected<br />
to a flexible operating regime, with many plants conducting daily starts for at<br />
least part <strong>of</strong> <strong>the</strong> year. Many <strong>of</strong> <strong>the</strong> effects <strong>of</strong> flexible operation on HRSG<br />
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components in terms <strong>of</strong> <strong>the</strong>rmal fatigue damage, cycle chemistry and<br />
control/instrumentation are described in Sections 3.3, 3.4, 3.5 and 3.6 above.<br />
As far as <strong>the</strong> HRSG is concerned, <strong>the</strong> effects <strong>of</strong> load fluctuation are small<br />
compared to those arising from plant shutdown/start-up where <strong>the</strong> temperature<br />
differentials and ramp rates involved are much more damaging in terms <strong>of</strong><br />
fatigue life.<br />
Power Technology’s approach to assessing <strong>the</strong> level <strong>of</strong> <strong>risk</strong> to HRSG<br />
components under a flexible operating regime is to carry out a flexible<br />
operation study, which is conducted in three phases:<br />
Phase 1 involves establishing <strong>the</strong> existing level <strong>of</strong> instrumentation on <strong>the</strong><br />
HRSG and highlighting those that would be required for a series <strong>of</strong> monitored<br />
flexible operation trials. The critical HRSG components at <strong>risk</strong> <strong>of</strong> early<br />
failure/increased degradation or that could create operational problems under a<br />
flexible operation regime are also identified based upon station-specific HRSG<br />
component materials and geometry, inspection results, previous flexible<br />
operation experience and known problem areas on <strong>the</strong> plant being studied. The<br />
number and location <strong>of</strong> additional instruments (typically <strong>the</strong>rmocouples on<br />
boiler headers and stubs) required for flexible operation trials are <strong>the</strong>n<br />
specified, with <strong>the</strong>ir installation justified against <strong>the</strong> potential <strong>risk</strong>s identified.<br />
Thermocouples can also be fitted to structural components such as expansion<br />
joints, duct supports, casings and so on to quantify <strong>the</strong> temperature<br />
differentials across <strong>the</strong>m.<br />
A desk study <strong>of</strong> <strong>the</strong> effects <strong>of</strong> flexible operation on water/steam chemistry<br />
would also be completed and would typically review phosphate hideout and its<br />
control, flow accelerated corrosion <strong>risk</strong> in low temperature / pressure circuits,<br />
water treatment plant capacity, steam quality at start-up, de-aeration capability<br />
on start-up and condenser integrity.<br />
After <strong>the</strong> additional instrumentation required had been installed, a programme<br />
<strong>of</strong> shutdown/start trials would be agreed with <strong>the</strong> station for Phase 2 and all<br />
plant data received would be processed and analysed. The extent <strong>of</strong> any<br />
damaging transients (specifically ramp rates, through-wall temperature<br />
differentials and peak temperatures) would be quantified and a detailed<br />
<strong>the</strong>rmal fatigue stress analysis carried out on <strong>the</strong> worst affected components.<br />
The damage would be quantified with <strong>the</strong> results expressed in terms <strong>of</strong> impact<br />
on component life and <strong>the</strong> likelihood <strong>of</strong> any failure mechanisms. In addition,<br />
one or two starts would be observed on site to fully understand any operational<br />
problems being experienced at first-hand. Appropriate recommendations to<br />
manage any issues identified would <strong>the</strong>n be made. These might typically<br />
include enhanced, targeted non-destructive testing/visual inspections,<br />
proposed modifications to operating procedures to minimise impact on HRSG<br />
components and/or changes to <strong>the</strong> cycle chemistry.<br />
Phase 3 (if required) would explore in more detail with <strong>the</strong> station <strong>the</strong><br />
feasibility <strong>of</strong> any proposed modifications to operating procedures in order to<br />
reduce component damage and / or reduce start time. Where <strong>the</strong> required<br />
changes are significant, it may be necessary to widen <strong>the</strong> scope <strong>of</strong> <strong>the</strong> study to<br />
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include <strong>the</strong> gas and steam turbines and to investigate <strong>the</strong> implications for<br />
control and instrumentation. Trials <strong>of</strong> <strong>the</strong> optimised two-shift procedure would<br />
<strong>the</strong>n be carried out and <strong>the</strong> extent <strong>of</strong> improvement assessed.<br />
Many <strong>of</strong> <strong>the</strong> design features that determine how flexible a HRSG is are<br />
described in Section 3.2. However, <strong>the</strong> quality <strong>of</strong> manufacture and<br />
construction and <strong>the</strong> operational procedures adopted also play a key role in<br />
ensuring that <strong>the</strong> effects <strong>of</strong> flexible operation (predominantly <strong>the</strong>rmal fatigue<br />
damage) are minimised. Manufacturers are aware <strong>of</strong> <strong>the</strong> threats posed by<br />
cyclic operation, and have already started to address <strong>the</strong> issues raised by <strong>the</strong><br />
flexible operation <strong>of</strong> power plant in response to customer demand.<br />
Both vertical and horizontal gas flow designs can be equally suited to flexible<br />
operation providing sufficient measures are taken during <strong>the</strong> design stage.<br />
Horizontal gas flow designs tend to be more susceptible to flexible operation<br />
damage due to lack <strong>of</strong> flexibility between <strong>the</strong> header systems (particularly if<br />
bottom-supported), though this is being addressed on more modern designs.<br />
The use <strong>of</strong> serpentine tube banks on vertical gas flow HRSGs inherently<br />
makes <strong>the</strong>m more mechanically flexible, although <strong>the</strong>re can be difficulties<br />
with drainage <strong>of</strong> <strong>the</strong> horizontal tube banks leading to <strong>the</strong> <strong>risk</strong> <strong>of</strong> <strong>of</strong>f-load<br />
corrosion.<br />
Relatively simple ways <strong>of</strong> improving <strong>the</strong> ability <strong>of</strong> an HRSG to withstand <strong>the</strong><br />
rigours <strong>of</strong> flexible operation include <strong>the</strong> correct sizing <strong>of</strong> drains and vents and<br />
<strong>the</strong> use <strong>of</strong> bypass valves and recirculation systems. GT and control and<br />
instrumentation reliability are important in avoiding trips, as hot re-starts are<br />
particularly damaging to upstream HRSG components. More substantial<br />
features such as <strong>the</strong> inclusion <strong>of</strong> a stack damper or <strong>the</strong> use <strong>of</strong> higher-grade<br />
alloys to reduce component thickness should be made at <strong>the</strong> design stage, as<br />
<strong>the</strong>se are much more expensive to retr<strong>of</strong>it later in <strong>the</strong> plant life.<br />
3.8 HRSG Costs, Reliability and Maintenance<br />
3.8.1 Capital Cost<br />
Capital costs for new build CCGT plant are difficult to predict accurately<br />
without going out to tender, and even <strong>the</strong>n a wide spread <strong>of</strong> costs can be<br />
possible at any given time. However <strong>the</strong> approximate total project cost for a<br />
new build CCGT in <strong>the</strong> UK [52] is estimated to be in <strong>the</strong> region <strong>of</strong> £425/kW.<br />
This includes not only <strong>the</strong> EPC (engineer/procure/construct) contract, but also<br />
o<strong>the</strong>r items such as project management, connection to gas/electricity<br />
networks etc. The HRSG it likely to account for around 10-15% <strong>of</strong> this total.<br />
This is still significantly lower than for o<strong>the</strong>r forms <strong>of</strong> fossil fuel generation<br />
e.g. <strong>the</strong> equivalent capital cost for a new build advanced pulverised fuel plant<br />
is around £800/kW [53] .<br />
CHP plant capital expenditure is generally more expensive at around £750/kW<br />
[52] with <strong>the</strong> HRSG likely to account for 10-15% <strong>of</strong> this total.<br />
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3.8.2 Operating Costs<br />
Fixed operating costs, excluding fuel, are estimated to be around £12/kWyear<br />
for an existing CCGT plant [54] , although this could be higher for <strong>the</strong> most<br />
advanced class <strong>of</strong> GT plant due to GT maintenance costs. Generally, though,<br />
this represents <strong>the</strong> lowest value across <strong>the</strong> range <strong>of</strong> fossil fuel plant, <strong>the</strong> next<br />
lowest value being that <strong>of</strong> £14/kW for an existing coal fired plant without<br />
FGD. These CCGT fixed operating costs will again be dominated by <strong>the</strong> gas<br />
turbine, perhaps even more so than with <strong>the</strong> capital costs.<br />
Taking into account all costs (fuel cost at 23p/<strong>the</strong>rm, fixed operating cost and<br />
cost <strong>of</strong> capital), <strong>the</strong> estimated delivered energy cost for a CCGT in <strong>the</strong> UK is<br />
around 2.2p/kWh [53] .<br />
3.8.3 Reliability<br />
Reliability/availability will vary greatly depending upon <strong>the</strong> original build<br />
quality and design <strong>of</strong> <strong>the</strong> HRSG, <strong>the</strong> operating regime and <strong>the</strong> maintenance<br />
performed. EPRI [55] predicted <strong>the</strong>oretical total availability <strong>of</strong> a drum type<br />
HRSG to be 98.52% e.g. 1.48% availability loss. Powergen data from 1997-<br />
1999 [56] suggests a figure <strong>of</strong> around 0.2% average HRSG availability loss,<br />
which may be due to <strong>the</strong> relative youth <strong>of</strong> <strong>the</strong> plant and a fairly tight functional<br />
specification. The losses [56] appear to be mainly due to one <strong>of</strong> three causes;<br />
tube leaks, leaks from flange connections or trips due to incorrect (high or<br />
low) drum level on start up.<br />
A survey <strong>of</strong> <strong>the</strong> causes <strong>of</strong> tube leaks on Powergen CCGT and CHP plant<br />
indicates that around 50% are due to ‘wear out’ mechanisms such as flow<br />
accelerated corrosion, fretting, long term overheating, on load corrosion, stub<br />
weld cracking etc. The remaining 50% can roughly be categorised as arising<br />
ei<strong>the</strong>r from original manufacturing (usually weld) defects / previous site<br />
repairs or <strong>of</strong> being <strong>of</strong> a miscellaneous nature [57] .<br />
3.8.4 Maintenance<br />
As well as <strong>the</strong> scheduled routine maintenance (e.g. valve/pump maintenance,<br />
safety valve maintenance and testing, instrumentation checks, etc), typical<br />
preventative actions would include annual HRSG visual inspections <strong>of</strong>: -<br />
• HRSG/duct supports, expansion and alignment.<br />
• HRSG/duct external framing & internal stiffeners.<br />
• HRSG/duct internal insulation (if fitted).<br />
• Bypass damper and stack.<br />
• Main HRSG stack.<br />
• Tube modules and headers.<br />
• Duct fabric expansion joints (including <strong>the</strong>rmal imaging whilst on-load to<br />
identify areas operating at above-design temperatures and areas <strong>of</strong> gas<br />
leakage).<br />
• The condition and tightness <strong>of</strong> pipe penetration seals<br />
• The condition and movement <strong>of</strong> main feed and main steam pipe supports.<br />
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The following measures are also typically taken during major outages to<br />
guarantee <strong>the</strong> continued integrity <strong>of</strong> <strong>the</strong> HRSG through its design life (which<br />
may range between 15 and 30 years): -<br />
• Sample header / drum internal inspections for corrosion/debris, <strong>the</strong>rmal<br />
fatigue, blockage and/or FAC <strong>of</strong> orifices.<br />
• Measurement <strong>of</strong> creep pips (header diametrical measurements).<br />
• Sample header end-cap and butt weld inspections.<br />
• Pipework butt-weld inspections.<br />
• Tube sampling/thickness checks (for flow accelerated corrosion and <strong>of</strong>fload<br />
corrosion).<br />
• Valve casting inspections.<br />
3.9 Industrial HRSG Applications<br />
HRSG applications are more diverse at <strong>the</strong> industrial scale and can be broadly<br />
classified as below.<br />
3.9.1 Industrial Gas Turbine HRSGs<br />
At <strong>the</strong> small scale, gas turbines may be used in smaller CHP schemes or to<br />
provide shaft power e.g. for pumping stations on gas pipelines. In CHP<br />
schemes <strong>the</strong> demand is usually for process steam (e.g. for enhanced oil<br />
recovery) and <strong>the</strong> generation <strong>of</strong> electricity by using a GT to burn <strong>the</strong> fuel and<br />
generate electricity ra<strong>the</strong>r than just burning it in a boiler is an economic bonus.<br />
Because <strong>the</strong> provision <strong>of</strong> steam to <strong>the</strong> process is usually <strong>the</strong> paramount<br />
concern, an auxiliary burner is usually fitted to allow continuation <strong>of</strong> boiler<br />
operation even when <strong>the</strong> GT has tripped. In this case a fresh air inlet duct is<br />
needed. Units may also be installed for marine use in gas turbine driven ships,<br />
floating production storage and <strong>of</strong>floading vessels (FPSO) and <strong>of</strong>fshore<br />
platforms. GT based CHP schemes typically achieve an electrical efficiency <strong>of</strong><br />
around 23% (GCV) and a heat efficiency <strong>of</strong> around 49% (GCV) [7] .<br />
In recent years a new breed <strong>of</strong> microturbines has been introduced, based on<br />
turbocharger ra<strong>the</strong>r than aero-derivative technology. These are usually in <strong>the</strong><br />
range up to 0.5MWe, at which scale <strong>the</strong> aero-derivative type becomes more<br />
economic. At present a typical microturbine unit from Bowman Power<br />
Systems has an output <strong>of</strong> 80kWe and a <strong>the</strong>rmal output <strong>of</strong> 130 – 260 kWth in an<br />
exhaust gas stream at a temperature <strong>of</strong> around 600°C [58] . Most units installed<br />
so far have recovered heat as hot water, but in some specialised applications<br />
steam has been generated.<br />
3.9.2 Reciprocating Engine Exhaust Gas Boilers<br />
Internal combustion engines may be used on a small scale for electricity<br />
generation and HRSGs may be added to run in combined heat and power<br />
mode. Low grade heat is usually recovered as hot water from <strong>the</strong> engine<br />
cooling circuit. Higher grade heat may be recovered from <strong>the</strong> exhaust as<br />
steam. Normally smoke tube design package units are used to generate<br />
saturated steam. Engines may be run on liquid or gaseous fuels. Increasingly,<br />
alternative fuel sources are being used, such as landfill gas, coal mine methane<br />
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and bio-gas from anaerobic digestion <strong>of</strong> sewage sludges, agricultural wastes<br />
and industrial wastes. Reciprocating engine based CHP schemes typically<br />
achieve an electrical efficiency <strong>of</strong> around 27% (GCV) and a heat efficiency <strong>of</strong><br />
around 42% (GCV) [7] .<br />
3.9.3 Heat Recovery from O<strong>the</strong>r Industrial Exhaust Gases<br />
HRSGs are used to recover energy from <strong>the</strong> hot exhaust <strong>of</strong> o<strong>the</strong>r industrial<br />
processes such as: -<br />
• Glass and metallurgical furnaces<br />
• Kilns (e.g. sponge iron plants): Coal based high temperature reduction <strong>of</strong><br />
iron ore produces a flue gas with a temperature in <strong>the</strong> range <strong>of</strong> 1000-<br />
1200°C and a dust load as high as 40gNm -3 . The first stage <strong>of</strong> <strong>the</strong> heat<br />
recovery system is a radiant section with water membrane panel walls<br />
where <strong>the</strong> gas is cooled to around 750°C to reduce <strong>the</strong> <strong>risk</strong> <strong>of</strong> slag<br />
deposition on downstream heat transfer surfaces. This is followed by a<br />
plain tube superheater fitted with soot blowers and evaporator and<br />
economiser sections.<br />
• Roaster based plants: a typical application is in roasting <strong>of</strong> pyrite ores.<br />
Pyrite ores are oxidised in a fluidised bed to produce <strong>the</strong> oxide required for<br />
manufacture <strong>of</strong> <strong>the</strong> primary metal. The flue gases contain sulphur dioxide<br />
and are at a temperature <strong>of</strong> around 900°C with a high dust load. The<br />
Thermax design [59] uses a water tube boiler to recover heat. A vertical<br />
tube alignment and a wide tube pitch are used to minimise problems <strong>of</strong><br />
dust deposition. A hammering device dislodges dust from <strong>the</strong> tubes into<br />
hoppers below from which it is continuously removed.<br />
• Smelters and converters: for example in copper and zinc smelting. The<br />
high temperature waste gas has a very high dust load. The heat is<br />
recovered in two stages. In <strong>the</strong> first stage <strong>the</strong> gas passes through a large<br />
water membrane walled radiant section where some <strong>of</strong> <strong>the</strong> dust and slag is<br />
allowed to settle. The partially cleaned and cooled gas <strong>the</strong>n passes through<br />
a conventional convection section with vertical bare tubes, again fitted<br />
with hammering devices to dislodge dust [59] .<br />
• Coke ovens<br />
• Solid / liquid / gas waste incinerators<br />
• VOC <strong>the</strong>rmal oxidisers<br />
3.9.4 Process Integrated HRSGs<br />
Many process industries use HRSGs to recover heat from <strong>the</strong> necessary<br />
cooling <strong>of</strong> process gases. Industries include:<br />
• Petrochemicals (e.g. in sulphur recovery units)<br />
• Sulphuric <strong>acid</strong> plants: The double conversion double absorption process<br />
for <strong>the</strong> manufacture <strong>of</strong> <strong>sulphuric</strong> <strong>acid</strong> from elemental sulphur generates<br />
considerable heat in <strong>the</strong> exo<strong>the</strong>rmic conversion <strong>of</strong> sulphur to SO2 and SO 3<br />
gases. The optimum working temperature for <strong>the</strong> V2O5 catalyst is about<br />
440°C, so it is essential to have a process integrated HRSG in <strong>the</strong> system<br />
to cool <strong>the</strong> gas to this temperature.<br />
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• Nitric <strong>acid</strong> / Caprolactum plants: nitric <strong>acid</strong> may be manufactured by <strong>the</strong><br />
catalytic oxidation <strong>of</strong> ammonia at around 950°C to give a gas rich in<br />
nitrogen oxides. The next step <strong>of</strong> <strong>the</strong> process requires a gas temperature <strong>of</strong><br />
around 250°C creating a requirement for a HRSG. Ei<strong>the</strong>r water tube or fire<br />
tube designs may be used – in ei<strong>the</strong>r case <strong>the</strong> design needs to take into<br />
account a typical gas side pressure <strong>of</strong> 5 – 7 barg.<br />
• Ammonia plants<br />
• Hydrogen gas plants<br />
• Fluidised catalytic converter units<br />
3.10 Conclusions<br />
• Current state <strong>of</strong> <strong>the</strong> art utility scale HRSGs operate at HP steam conditions<br />
<strong>of</strong> up to 124 bar/565°C and allow <strong>the</strong> associated CCGT to deliver<br />
electrical power at a claimed net efficiency <strong>of</strong> up to 60%. They are<br />
generally two pressure or three pressure with reheat, and may be <strong>of</strong> ei<strong>the</strong>r<br />
vertical or horizontal gas flow.<br />
• The capital cost <strong>of</strong> new-build CCGT plant is around £425/kW, with <strong>the</strong><br />
HRSG accounting for 10-15% <strong>of</strong> this total. The estimated delivered energy<br />
cost for a CCGT in <strong>the</strong> UK is around 2.2p/kWh.<br />
• Current state <strong>of</strong> <strong>the</strong> art industrial HRSGs generally operate at lower steam<br />
conditions than utility scale plant, and are usually <strong>of</strong> single pressure<br />
design. They are integrated into a wide range <strong>of</strong> industrial plant and <strong>of</strong>ten<br />
include provision for supplementary or auxiliary (stand-alone) firing.<br />
Highly fired units may incorporate a water-cooled furnace. Lower pressure<br />
industrial boilers are usually <strong>of</strong> shell ra<strong>the</strong>r than water tube design.<br />
Designs tend to be bespoke for particular process applications.<br />
• The recent trend has been for CCGT plant to be built under turnkey<br />
contract. Whilst this does have advantages to <strong>the</strong> user in terms <strong>of</strong><br />
accountability, it does tend to mean that <strong>the</strong> user has less influence on <strong>the</strong><br />
detailed HRSG design.<br />
• Operational experience with HRSGs indicates that inclusion <strong>of</strong> specific<br />
design features and attention to detail during fabrication are just as<br />
important as <strong>the</strong> overall HRSG design, and that non pressure parts can be<br />
as problematic as pressure parts.<br />
• Key areas for improvement include build quality, access for in service<br />
inspection & maintenance, control & instrumentation and capability for<br />
flexible operation. Overall cycle chemistry philosophy also needs to be<br />
more thoroughly considered at <strong>the</strong> design stage.<br />
The current challenge for operational HRSGs, particularly in <strong>the</strong> UK, is <strong>the</strong><br />
need to cycle plant which has been designed for and/or previously operating at<br />
base load. Many users are currently carrying out investigations/trials and plant<br />
modifications.<br />
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4 NEW AND DEVELOPING TECHNOLOGIES<br />
4.1 Introduction<br />
This chapter describes and reviews HRSG technologies which are envisaged<br />
as becoming available in <strong>the</strong> near and longer term. A number <strong>of</strong> HRSG<br />
suppliers and users were consulted during <strong>the</strong> preparation <strong>of</strong> this report about<br />
technological developments and <strong>the</strong> need for fur<strong>the</strong>r research. The consensus<br />
<strong>of</strong> opinion amongst those consulted was that <strong>the</strong> technology is mature and that<br />
large or revolutionary advances in technology are not expected. However,<br />
small incremental improvements are expected to continue. None <strong>of</strong> <strong>the</strong><br />
industrial scale companies consulted stated that <strong>the</strong>y have research projects <strong>of</strong><br />
<strong>the</strong>ir own going on currently. At <strong>the</strong> industrial scale, most businesses are not<br />
large enough to take on large R&D commitments. Developments at <strong>the</strong> utility<br />
scale, such as <strong>the</strong> use <strong>of</strong> higher temperature materials, will cascade down to<br />
<strong>the</strong> smaller industrial scale market eventually and give gradual advances. A<br />
number <strong>of</strong> new applications or small areas <strong>of</strong> technological advance were<br />
identified and <strong>the</strong> following specific categories have emerged:<br />
• Developments in <strong>the</strong> design <strong>of</strong> HRSGs <strong>the</strong>mselves.<br />
• Developments in o<strong>the</strong>r parts <strong>of</strong> combined cycle plant or <strong>the</strong> overall cycle.<br />
• New applications.<br />
4.2 Developments in HRSG Design<br />
4.2.1 Utility Scale Once Through HRSG Designs<br />
In terms <strong>of</strong> components, <strong>the</strong> once-through steam generator is <strong>the</strong> simplest<br />
HRSG design for recovering heat from <strong>the</strong> exhaust <strong>of</strong> a gas turbine. Water<br />
entering at <strong>the</strong> cold end <strong>of</strong> <strong>the</strong> gas-pass, moves through a serpentine tube<br />
bundle where heat absorption occurs and a phase change takes place, and exits<br />
as superheated steam. The circulation ratio is one and <strong>the</strong>re is no requirement<br />
for circulation pumps.<br />
Conventional (i.e. not once through), sub-critical HRSGs utilise drums in<br />
which steam and water from <strong>the</strong> evaporative part <strong>of</strong> <strong>the</strong> cycle are separated.<br />
The water is <strong>the</strong>n recirculated within <strong>the</strong> evaporator with additional feedwater<br />
while <strong>the</strong> steam passes to <strong>the</strong> superheater for fur<strong>the</strong>r heating. Supercritical<br />
pressure boilers cannot utilise this type <strong>of</strong> design as <strong>the</strong>re is no distinct<br />
water/steam phase transition above <strong>the</strong> critical pressure. A once-through<br />
design is <strong>the</strong>refore required. The OTSG design also has advantages for flexible<br />
operation. The steam drum is <strong>the</strong> component in a conventional HRSG design<br />
with <strong>the</strong> thickest wall section and is <strong>the</strong>refore <strong>the</strong> most prone to <strong>the</strong> occurrence<br />
<strong>of</strong> stresses associated with differential <strong>the</strong>rmal expansion. It is <strong>the</strong> limiting<br />
component in setting maximum heat-up and cool-down rates and a design that<br />
eliminates <strong>the</strong> drum is <strong>the</strong>refore better for flexible operation.<br />
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Once-through technology has in <strong>the</strong> past generally been limited to projects<br />
based on aero-derivative or small industrial gas turbines. However, designs<br />
that can handle <strong>the</strong> larger frame gas turbines are now evolving.<br />
With regards to utility HRSG applications in <strong>the</strong> UK, once-through technology<br />
is currently at a demonstration stage with a full-scale once-through<br />
demonstration HRSG (supplied by Deutsche Babcock, now Babcock Borsig)<br />
currently in operation at Cottam Development Centre. This is a sub-critical<br />
Benson design with superheater steam conditions <strong>of</strong> 580°C and 160 bar and is<br />
described fur<strong>the</strong>r in Section 7.3.1. This technology, which originated with<br />
Siemens, is currently licensed to a number <strong>of</strong> o<strong>the</strong>r companies including<br />
Nooter/Eriksen.<br />
However in North America <strong>the</strong> commercial acceptance <strong>of</strong> once-through<br />
technology is far more apparent. ABB have 7 once-through (sub-critical)<br />
industrial sized HRSG units in operation and a fur<strong>the</strong>r 23 under construction<br />
and are moving towards larger scale applications with a significant new 2<strong>70</strong><br />
MWe once-through HRSG built recently at Agawam in Massachusetts. In<br />
addition, Innovative Steam Technologies (IST) <strong>of</strong> Canada won a contract for a<br />
once-through technology plant at Calpine’s Broadriver Energy Centre,<br />
although in this case <strong>the</strong> HRSG is only sized to provide steam for GT<br />
injection.<br />
Successful and extensive pilot trials have been undertaken by Cockerill<br />
Mechanical Industries (CMI) <strong>of</strong> Belgium in <strong>the</strong>ir Seraing works [60] with a<br />
view to achieving supercritical conditions in <strong>the</strong> once through HRSG.<br />
Indications are that HRSGs will gradually adopt once through technology and<br />
<strong>the</strong>n move to supercritical pressures as gas turbines become larger and exhaust<br />
gas temperatures continue to increase.<br />
4.2.2 Industrial Scale Once Through HRSG Designs<br />
The application <strong>of</strong> <strong>the</strong> OTSG design to CHP plants is sometimes limited by<br />
<strong>the</strong> critical need for a continuous supply <strong>of</strong> steam for some users. In a<br />
conventional drum HRSG design <strong>the</strong>re is a significant reservoir <strong>of</strong> steam and<br />
hot water in <strong>the</strong> drum. In <strong>the</strong> event <strong>of</strong> a GT trip, this will provide a buffer<br />
supply <strong>of</strong> steam to maintain <strong>the</strong> supply to <strong>the</strong> user’s plant while <strong>the</strong> auxiliary<br />
burner starts up and reaches <strong>the</strong> necessary output. The only water in <strong>the</strong> OTSG<br />
is in <strong>the</strong> tubes, which does not provide such a large reservoir <strong>of</strong> steam. For<br />
applications where maintenance <strong>of</strong> a continuous steam supply is critical,<br />
provision <strong>of</strong> steam buffer capacity needs to be investigated. The higher<br />
pressure drop on <strong>the</strong> water side <strong>of</strong> <strong>the</strong> OTSG has been identified as a minor<br />
disadvantage <strong>of</strong> <strong>the</strong> design. The development <strong>of</strong> new balanced header designs<br />
that distribute <strong>the</strong> flow evenly over all <strong>of</strong> <strong>the</strong> tubes will reduce this effect.<br />
4.2.3 Reliability Improvements<br />
Within <strong>the</strong> UK, as a direct result <strong>of</strong> <strong>the</strong> New Electricity Trading Arrangements<br />
(NETA) in England and Wales, generators and suppliers now have to contract<br />
directly with each o<strong>the</strong>r for <strong>the</strong> physical supply <strong>of</strong> power. The effect <strong>of</strong> this<br />
and similar legislation throughout <strong>the</strong> world on <strong>the</strong> plants <strong>the</strong>mselves, is that<br />
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many existing combined cycle gas turbine plants need to move towards more<br />
flexible operation than was initially envisaged at <strong>the</strong>ir design stage.<br />
This move from what was initially a system engineered for base loading to one<br />
with substantial requirement for two-shift operation has a detrimental impact<br />
on plant reliability, specifically with regards to <strong>the</strong> HRSG. For <strong>the</strong> plant, <strong>the</strong><br />
main <strong>risk</strong> associated with <strong>the</strong> use <strong>of</strong> <strong>the</strong> HRSG under flexible operation is <strong>the</strong><br />
impact on <strong>the</strong> achievable lifetime <strong>of</strong> pressure part and non-pressure part<br />
components such as tubes, headers, casing components etc. In general, a<br />
reduction in lifetime is expected resulting from causes such as Low Cycle<br />
Fatigue (LCF), localised header stresses and flow accelerated corrosion (FAC)<br />
and from a combination <strong>of</strong> LCF and Stress Corrosion Cracking (SCC).<br />
The challenge <strong>the</strong>refore faced by engineers is to design solutions that ensure<br />
<strong>the</strong> reliability <strong>of</strong> <strong>the</strong> next generation <strong>of</strong> HRSGs to be installed and upgrade <strong>the</strong><br />
existing plants (by correctly sizing drains for example) before major problems<br />
occur.<br />
In order to do this companies have had to invest heavily in effective transient<br />
<strong>the</strong>rmal modelling capabilities that allow <strong>the</strong>m to analyse thoroughly every<br />
component <strong>of</strong> <strong>the</strong> HRSG and make design changes to limit <strong>the</strong>rmal stresses.<br />
One such example where new features have specifically been designed to<br />
provide flexibility for <strong>the</strong> plant during <strong>the</strong>rmal transients is with Foster<br />
Wheeler’s Fort Meyers repowering project [61] . This novel feature is a “wet<br />
bypass” unit which is designed to absorb <strong>the</strong> instantaneous power loss <strong>of</strong> a<br />
steam turbine trip and enable <strong>the</strong> gas turbine to continue operating at a full<br />
simple cycle load. In <strong>the</strong> event <strong>of</strong> <strong>the</strong> steam turbine tripping, main steam is<br />
attemperated and its pressure reduced, before it is bypassed to <strong>the</strong> condenser.<br />
Reheated steam is ei<strong>the</strong>r bypassed to <strong>the</strong> atmosphere, when <strong>the</strong> condenser is<br />
not available or also attemperated and reduced in pressure before passing to<br />
<strong>the</strong> condenser dump. Thermal fatigue <strong>of</strong> <strong>the</strong> steam headers is greatly reduced<br />
by this innovative process.<br />
Likewise Alstom have adopted features specifically to reduce <strong>the</strong>rmal stress at<br />
welded joints albeit at a potential increase in capital outlay. Most natural<br />
circulation HRSGs use a multiple–row harp-shaped design, comprising <strong>of</strong> one<br />
horizontal upper header and one horizontal lower header joined by two or<br />
three rows <strong>of</strong> vertical tubes. Alstom maintains that, <strong>the</strong> temperature <strong>of</strong> <strong>the</strong><br />
exhaust gas drops sufficiently as it passes through <strong>the</strong> multiple tube rows to<br />
cause <strong>the</strong> individual tube rows to operate at different temperatures, inducing<br />
differential <strong>the</strong>rmal stress at <strong>the</strong> weld joints. Their solution is to form a single<br />
row <strong>of</strong> tubes between headers to remove <strong>the</strong>se differential stresses. As a single<br />
row allows for smaller header diameters, circumferential temperature<br />
gradients in <strong>the</strong> headers are also minimised. Alstom’s analysis concluded that<br />
small-diameter headers reduce <strong>the</strong>rmal stress by as much as 60% when<br />
compared to headers used with multiple rows.<br />
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4.2.4 Modularity and Improved Maintenance Features<br />
One noticeable innovation with regards to HRSGs is <strong>the</strong> drive towards<br />
modular designs. Aalborg Industries Inc., Alstom, Mitsui Babcock and<br />
Nooter/Eriksen are some manufacturers who have designed around <strong>the</strong><br />
concept <strong>of</strong> modularity in order to exploit it as a selling <strong>point</strong> for <strong>the</strong>ir HRSGs.<br />
Aalborg’s rapid delivery <strong>of</strong> standard units in less than 90 days alongside quick<br />
field erection <strong>of</strong> <strong>the</strong>ir pre-assembled, pressure-tested systems has won <strong>the</strong>m a<br />
considerable HRSG business. This modularity extends to <strong>the</strong> <strong>point</strong> where<br />
some <strong>of</strong> <strong>the</strong> auxiliary features <strong>of</strong> <strong>the</strong> HRSG are already in place (e.g.<br />
feedwater systems, air and flue gas ducting, etc).<br />
Nooter/Eriksen incorporate a modular design to increase shop fabrication and<br />
minimise field man-hours. Their flexible construction method and attention to<br />
detail allows setting <strong>of</strong> up to five modules per day.<br />
O<strong>the</strong>r manufacturers such as Foster Wheeler believe modularity to be<br />
advantageous. Their approach has been to make modules as large as possible<br />
leading to a requirement for fewer components to be assembled in <strong>the</strong> field.<br />
Foster Wheeler maintain that <strong>the</strong> increased “constructability” <strong>of</strong> <strong>the</strong>ir HRSGs<br />
helps reduce <strong>the</strong> <strong>risk</strong> <strong>of</strong> possible delays in <strong>the</strong> erection schedule and <strong>the</strong><br />
financial penalties that may <strong>the</strong>n result.<br />
O<strong>the</strong>r companies have patented design features such as enhanced accessibility<br />
to <strong>the</strong>ir HRSGs. The manufacturer Deltak, for example, claims this very<br />
feature reduces repair time to half <strong>of</strong> <strong>the</strong> industry standard.<br />
4.2.5 Control and Instrumentation<br />
At <strong>the</strong> simple smoke tube design end <strong>of</strong> <strong>the</strong> industrial HRSG market, control<br />
technology is being improved. Up to date touch screen control technology is<br />
only now being introduced to <strong>the</strong>se ‘traditional’ designs in less demanding<br />
applications.<br />
4.2.6 Highly Fired HRSG Designs<br />
An increasing number <strong>of</strong> industrial scale HRSGs are being used to supply onsite<br />
power and process steam requirements. In some instances <strong>the</strong> steam<br />
demand substantially exceeds what can be supplied from <strong>the</strong> exhaust <strong>of</strong> a GT<br />
meeting <strong>the</strong> on-site power demand, so a high degree <strong>of</strong> supplementary firing is<br />
required. This results in a very hot, high moisture content gas flow and a need<br />
to fire down to low oxygen levels while still meeting emission limits for CO<br />
and NOx. Often <strong>the</strong> supplementary burners must be sized to maintain full<br />
steam output even if <strong>the</strong> GT trips. This creates design challenges for HRSG<br />
manufacturers. More exotic materials are required for highly fired HRSGs and<br />
water membrane walls are becoming more common in designs for <strong>the</strong>se<br />
applications. These technologies are well established in fired boiler designs<br />
and are now being transferred across to HRSG designs.<br />
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4.3 Improvements to Cycle and O<strong>the</strong>r Plant Components<br />
4.3.1 Steam Cooled Turbine Blades<br />
For <strong>the</strong> gas turbine, <strong>the</strong> maximum allowable inlet temperature is governed by<br />
both <strong>the</strong> materials available for <strong>the</strong> turbine blading and <strong>the</strong> cooling technique<br />
employed.<br />
Previous generations <strong>of</strong> gas turbines utilised air to cool turbine components in<br />
an open loop system. The cooling air was supplied from a bleed in <strong>the</strong> gas<br />
turbine compressor, and <strong>the</strong>n ducted to <strong>the</strong> internal chambers <strong>of</strong> <strong>the</strong> turbine<br />
blades and discharged through small holes in <strong>the</strong> blade walls. This air<br />
provided a thin, cool insulating blanket along <strong>the</strong> external surface <strong>of</strong> <strong>the</strong><br />
turbine blade. As a result, <strong>the</strong>re is a significant exhaust gas temperature drop<br />
across <strong>the</strong> first stage nozzle and significant flow <strong>of</strong> air required to cool down<br />
<strong>the</strong> relevant turbine stages. An integrated closed loop steam cooling system<br />
significantly reduces this temperature drop in addition to eliminating <strong>the</strong><br />
requirement for air bleed for <strong>the</strong> turbine cooling. This technology is envisaged<br />
as contributing around 2% <strong>point</strong>s in <strong>the</strong>rmal efficiency.<br />
The <strong>the</strong>rmodynamic advantage <strong>of</strong> utilising steam in cooling circuits was<br />
recognised in <strong>the</strong> early 90’s [6] (Figure 32). This has been developed<br />
accordingly over <strong>the</strong> last decade to allow integration <strong>of</strong> <strong>the</strong> HRSG steam flow<br />
with <strong>the</strong> gas turbine cooling loop to fur<strong>the</strong>r enhance cycle performance. The<br />
implications <strong>of</strong> this on steam purity are significant if corrosion and fouling <strong>of</strong><br />
<strong>the</strong> cooling passages is to be prevented. This is discussed fur<strong>the</strong>r in Section<br />
3.5.9.<br />
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Figure 32: Effect <strong>of</strong> gas turbine cooling methods on efficiency (Courtsey <strong>of</strong><br />
Innogy plc) [6] .<br />
(83)
The world’s first operational steam cooled gas turbine, built by MHI, was<br />
commissioned in Japan in 1998 and installed in Unit 4 at <strong>the</strong> Higashi Niigata<br />
Power Station. In <strong>the</strong> United States, it was not until early 2001 that Siemens-<br />
Westinghouse achieved commercial operation with a 360 MWe power plant<br />
located in Massachusetts followed immediately by a second 249 MWe plant in<br />
Florida. The gas turbine installed in <strong>the</strong> American plants is considered<br />
“partially” steam cooled, with just <strong>the</strong> first stage vanes being incorporated<br />
within a closed loop. Whilst specific teething problems were found during<br />
start up conditions <strong>of</strong> <strong>the</strong> W105G gas turbine, a cycle efficiency <strong>of</strong> ~58%<br />
(LHV) was achieved with this technology.<br />
More recently General Electric installed <strong>the</strong>ir first H-class unit at <strong>the</strong> Baglan<br />
Energy Park in South Wales. This unit, which features steam-cooled rotor and<br />
stator vanes, is currently under commissioning tests with engineers aiming to<br />
break <strong>the</strong> 60% (LHV) cycle efficiency barrier.<br />
4.3.2 Fuel Heating<br />
In <strong>the</strong> late 90’s methods <strong>of</strong> heating fuel prior to combustion in <strong>the</strong> gas turbine<br />
were being introduced to <strong>the</strong> combined cycle in order to enhance efficiency.<br />
Preheating <strong>of</strong> <strong>the</strong> fuel results in a reduction in <strong>the</strong> amount <strong>of</strong> fuel needed to<br />
achieve a given firing temperature in <strong>the</strong> gas turbine. However, whilst <strong>the</strong><br />
efficiency <strong>of</strong> <strong>the</strong> cycle improves, <strong>the</strong> plant power output is found to reduce<br />
slightly. This originates from <strong>the</strong> fact that when a gas turbine is fed warmer<br />
fuel, it requires less mass flow <strong>of</strong> that fuel to obtain <strong>the</strong> previous cold-fuel<br />
firing temperatures, thus <strong>the</strong> exhaust mass flow and water vapour content <strong>of</strong><br />
<strong>the</strong> combustion products is lower. Less power is <strong>the</strong>refore obtained from <strong>the</strong><br />
combustion gas expansion through <strong>the</strong> turbine. Fur<strong>the</strong>rmore <strong>the</strong> HRSG<br />
generates a little less steam from <strong>the</strong> decline in gas turbine exhaust mass flow<br />
and hence a drop in steam turbine power also occurs. However, <strong>the</strong> overall<br />
improvement in <strong>the</strong> cycle efficiency results from <strong>the</strong> fact that <strong>the</strong> energy<br />
diverted from producing steam power is <strong>of</strong> relatively low grade, and is better<br />
employed as a heating medium for <strong>the</strong> fuel.<br />
The fuel heating source may be ei<strong>the</strong>r steam or water. For <strong>the</strong> case <strong>of</strong> steam<br />
this can originate from <strong>the</strong> steam turbine bleed or directly from one <strong>of</strong> <strong>the</strong><br />
HRSG pressure level circuits. For <strong>the</strong> case <strong>of</strong> water heating, <strong>the</strong> hot water is<br />
drawn from <strong>the</strong> HRSG economisers.<br />
There is a threshold at which <strong>the</strong> benefits associated with <strong>the</strong> increase in<br />
efficiency are found to be at <strong>the</strong> expense <strong>of</strong> <strong>the</strong> level <strong>of</strong> electrical power<br />
produced [62] . For example fuel heating to around 200°C from an intermediate<br />
pressure economiser exit water source on a typical three pressure reheat<br />
combined cycle, results in a net heat rate gain <strong>of</strong> about 0.6% with a<br />
corresponding net power loss <strong>of</strong> about 0.3%. If <strong>the</strong> temperature <strong>of</strong> <strong>the</strong> fuel<br />
was raised to around 300°C by a high pressure economiser exit water source,<br />
<strong>the</strong> loss <strong>of</strong> power becomes more evident at 0.75% whereas <strong>the</strong> noted increase<br />
in <strong>the</strong> heat rate gain is less apparent as it only rises to 0.8%.<br />
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4.3.3 Gas Turbine Steam Injection for Power Augmentation<br />
The injection <strong>of</strong> steam into a gas turbine for NOx control is well established.<br />
Steam injection into <strong>the</strong> combustor reduces combustion temperatures by<br />
diluting both <strong>the</strong> level <strong>of</strong> oxygen in <strong>the</strong> combustion air and <strong>the</strong> heat generated<br />
from combustion <strong>of</strong> <strong>the</strong> fuel. However <strong>the</strong> use <strong>of</strong> steam injection for power<br />
augmentation is considered to be somewhat under developed for larger heavy<br />
duty gas turbines.<br />
Injecting large amounts <strong>of</strong> steam for power augmentation creates a fairly<br />
efficient power only plant that effectively makes <strong>the</strong> steam turbine, condenser<br />
and cooling tower in a combined cycle redundant. Aero-derivative engines<br />
such as LM 5000 and <strong>the</strong> Alison 501 were proven in <strong>the</strong> mid 80s to be suitable<br />
for steam injection power augmentation [63] . The LM 5000 can absorb all <strong>the</strong><br />
steam generated from <strong>the</strong> heat recovered from its own exhaust, and in doing so<br />
increase its power output by up to 15%.<br />
The reason for <strong>the</strong> aero-derivative engines success at power augmentation was<br />
because aero-engines were initially designed to pick up load faster than heavy<br />
industrial gas turbines and consequently have a greater surge margin when<br />
operating in an industrial application. Some <strong>of</strong> this surge margin can <strong>the</strong>refore<br />
be exploited to accept steam injection.<br />
However <strong>the</strong> limited electrical generation capacity <strong>of</strong> <strong>the</strong>se gas turbines (<<br />
50MWe) means that <strong>the</strong> benefits <strong>of</strong> this application have been limited to<br />
mostly small scale industrial power supply uses. Although in some cases<br />
several <strong>of</strong> <strong>the</strong>se aero-derivative gas turbines have been successfully combined<br />
to form a reasonably sized utility plant (i.e. 7 x 50MWe). Currently no gas<br />
turbine greater than 50 MWe has been designed which allows for such heavy<br />
steam injection that <strong>the</strong> need for a separate steam turbine is removed (as is <strong>the</strong><br />
case for <strong>the</strong> LM5000).<br />
However, elaborate arrangements where steam/water is injected into large gas<br />
turbines are in <strong>the</strong> development stage, albeit that relatively few have actually<br />
been constructed. A current list and description <strong>of</strong> <strong>the</strong>se proposals has been<br />
generated by Foster-Pegg [64] . Those which have reached demonstration status<br />
include: -<br />
• Simple Steam Injected Gas Turbine “SIGT” Cycle: this system involves<br />
moderate steam injection into <strong>the</strong> combustor <strong>of</strong> a standard large gas<br />
turbine and has been used to augment power under hot ambient conditions.<br />
• Humid Air Turbine or “HAT” Cycle: this system involves evaporating<br />
moisture into <strong>the</strong> air flowing into a gas turbine and requires a special gas<br />
turbine in order to operate effectively. It has been highlighted as<br />
particularly appropriate for gasification combined cycles.<br />
The retr<strong>of</strong>it <strong>of</strong> gas turbine steam injection for power augmentation may be<br />
particularly attractive in areas where <strong>the</strong>re is existing industrial scale open<br />
cycle GT plant and a demand for greater generating capacity. A variety <strong>of</strong><br />
HRSG designs could be used in this application, but it is a developing<br />
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application for which OTSGs may be particularly suitable. The OTSG can be<br />
designed to run dry at full exhaust temperature, removing <strong>the</strong> need for a<br />
bypass stack and providing a more simple and robust system.<br />
4.3.4 Gas Turbine Inlet Air Chilling<br />
Air intake cooling technology is used to enhance combined cycle power<br />
output and is particularly relevant for utility plant situated in warm climates<br />
where <strong>the</strong> air is dry and hot. The cooling <strong>of</strong> <strong>the</strong> air at <strong>the</strong> inlet results in a<br />
noticeable increase in mass flow through <strong>the</strong> gas turbine. This in turn results in<br />
a higher gas turbine power output as well as a slight increase in <strong>the</strong> steam<br />
production in <strong>the</strong> downstream HRSG.<br />
The cooling <strong>of</strong> <strong>the</strong> inlet air is achieved by means <strong>of</strong> a refrigeration system<br />
similar to <strong>the</strong> type employed in large building air conditioning units. The heat<br />
exchanger used to cool <strong>the</strong> incoming gas turbine air is formed from a coil <strong>of</strong><br />
finned tubes located in <strong>the</strong> inlet housing <strong>of</strong> <strong>the</strong> gas turbine. Cooled water is<br />
circulated through <strong>the</strong> tubes. The prior cooling <strong>of</strong> <strong>the</strong> water is achieved by<br />
chillers which are mass produced pieces <strong>of</strong> equipment and essentially fall into<br />
two categories:-<br />
• Centrifugal chillers<br />
• Absorption chillers<br />
In general, <strong>the</strong> absorption chiller delivers a lower gross plant power output<br />
than <strong>the</strong> centrifugal chiller due to <strong>the</strong> use <strong>of</strong> steam bleed from <strong>the</strong> HRSG to<br />
drive it. However in terms <strong>of</strong> plant net power outputs <strong>the</strong> two systems are<br />
approximately <strong>the</strong> same. This is because <strong>the</strong> centrifugal chiller requires an<br />
electric pump for circulation and <strong>the</strong>refore consumes a far greater amount <strong>of</strong><br />
auxiliary power as opposed to <strong>the</strong> steam driven circulation for <strong>the</strong> absorption<br />
method. Fur<strong>the</strong>r differences between <strong>the</strong>se two systems are described in<br />
greater detail by Elmasri [62] .<br />
Chilling <strong>the</strong> inlet <strong>of</strong> a large combined cycle allows extra power to be obtained<br />
from a plant (~ 5% increase in <strong>the</strong> net kWe output). The cost <strong>of</strong> that additional<br />
power output is <strong>the</strong> additional expense <strong>of</strong> <strong>the</strong> capital and operational costs <strong>of</strong><br />
<strong>the</strong> upstream chilling unit and o<strong>the</strong>r necessary modifications to <strong>the</strong> gas turbine<br />
itself. These have been estimated by Elmasri [62] at ~$250 per kWe <strong>of</strong> capacity<br />
gained above <strong>the</strong> initial hot design condition.<br />
The small-scale OTSG design may also find application in power<br />
augmentation for existing open cycle GT plant by GT air inlet chilling, as<br />
described above. A small OTSG unit can be added to an open cycle GT to<br />
provide steam for an absorption chiller. Again <strong>the</strong> advantage <strong>of</strong> <strong>the</strong> OTSG<br />
design is that protection in <strong>the</strong> event <strong>of</strong> a boiler trip is not required as <strong>the</strong><br />
OTSG may be designed to run dry at full exhaust temperature.<br />
4.3.5 Increases in Gas Turbine Exhaust Temperature<br />
The pursuit <strong>of</strong> higher efficiency CCGT plant has driven <strong>the</strong> rapid increases in<br />
GT exhaust temperature and mass flow rate imposed on HRSGs. The exhaust<br />
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conditions <strong>of</strong> some established and more recently developed gas turbines are<br />
shown in Table 5 below:<br />
Gas Turbine Turbine inlet<br />
temperature<br />
(°C)<br />
Siemens/Westinghouse<br />
501G (a 60Hz machine)<br />
(87)<br />
Turbine exhaust<br />
temperature<br />
(°C)<br />
Mass flow<br />
(kg/s)<br />
1427 600 535<br />
GE 9351FA 1327 606 636<br />
Alstom GT 26 1260 641 549<br />
GE 9001H 1427 621 685<br />
Table 5: Turbine inlet/exhaust gas temperatures and mass flow rates on some<br />
modern gas turbines [65] .<br />
The Alstom GT 26 (and GT 24) gas turbine uses sequential combustion in two<br />
annular combustion chambers to achieve improved efficiency. This is different<br />
to <strong>the</strong> conventional approach to gas turbine combustion, which is carried out<br />
in a single stage and requires increasingly high firing temperatures and<br />
complicated cooling technologies [66] . The exhaust temperature is <strong>the</strong> highest<br />
<strong>of</strong> any commercially available gas turbine.<br />
The GE 9001H is designed to give a combined cycle <strong>the</strong>rmal efficiency <strong>of</strong><br />
60% and <strong>the</strong> first <strong>of</strong> its kind is being installed at Baglan Energy Park in South<br />
Wales. The efficiency improvement is due to <strong>the</strong> high firing temperature,<br />
which is made possible by <strong>the</strong> use <strong>of</strong> large single crystal airfoils, superior<br />
component and coating materials and a closed-loop steam cooling system (see<br />
Section 4.3.1) [67] . The implications <strong>of</strong> this type <strong>of</strong> cooling system for HRSG<br />
water/steam chemistry are not trivial and are discussed in Section 3.5.9.<br />
In general, <strong>the</strong> latest generation <strong>of</strong> gas turbines, with <strong>the</strong>ir increased gas<br />
turbine outlet conditions are not anticipated to be a major concern as far as <strong>the</strong><br />
HRSG pressure parts are concerned, as materials issues at <strong>the</strong>se temperatures<br />
have been successfully tackled on conventional coal-fired plant.<br />
For <strong>the</strong>se increased temperatures, GT diffuser ducts, HRSG inlet ducts and<br />
casings are likely to be internally insulated in <strong>the</strong> higher temperature regions.<br />
Currently used internal insulation liner materials can cope with <strong>the</strong>se relatively<br />
small increases in temperature (internal insulation has been proven on CHP<br />
plant with supplementary firing up to around 850°C).<br />
The most likely area to be impacted is that <strong>of</strong> non-cooled support components,<br />
particularly on vertical gas-flow HRSGs e.g. HP superheater/reheater tube<br />
sheets and support links. This may require more extensive use <strong>of</strong> higher grade<br />
alloys such as modified 9% chrome (P91) or stainless steel for support<br />
components. There may even be a need to employ water/steam cooled support<br />
tubes for high temperature tube banks on vertical gas-flow HRSGs (akin to <strong>the</strong><br />
rear pass <strong>of</strong> a conventional coal fired boiler). This method <strong>of</strong> support has<br />
largely been limited to supplementary fired vertical gas flow HRSGs in <strong>the</strong><br />
past.
4.3.6 Supercritical Technology<br />
Currently state-<strong>of</strong>-<strong>the</strong>-art supercritical pulverised fuel fired steam power<br />
generation plants exist and operate at up to nominally 300 bar and 600°C<br />
steam output with net efficiencies <strong>of</strong> ~45% LHV [68] . Due to advances in<br />
materials technologies steam temperatures and cycle efficiencies have<br />
gradually improved and are set to continue to do so. Targets <strong>of</strong> final steam<br />
conditions <strong>of</strong> 650-<strong>70</strong>0°C have been set for 2020 and associated cycle<br />
efficiencies <strong>of</strong> around 50-55% are expected.<br />
The recognised advantages <strong>of</strong> adopting a supercritical steam cycle in addition<br />
to <strong>the</strong> obvious improvements to cycle efficiency are [68] :-<br />
• CO2 emissions are reduced by about 15% per unit <strong>of</strong> electricity generated<br />
when compared with typical existing sub-critical plant.<br />
• Exceptionally good part load efficiencies are achievable, typical half <strong>the</strong><br />
decrease in efficiency exhibited by sub-critical plant.<br />
• Plant costs are considered comparable with sub-critical technology.<br />
Much <strong>of</strong> <strong>the</strong> technology surrounding supercritical technologies is not new and<br />
a great deal <strong>of</strong> development work was done in <strong>the</strong> 1950s and 1960s. At this<br />
time countries such as <strong>the</strong> UK kept a predominantly sub-critical power base<br />
due to <strong>the</strong> unreliability, expense and poor operational flexibility <strong>of</strong> <strong>the</strong>se early<br />
designs. However, elsewhere in Europe and in Japan, development and<br />
refinement continued to <strong>the</strong> extent that supercritical steam is now considered<br />
one <strong>of</strong> <strong>the</strong> leading clean coal technologies. Currently 10% <strong>of</strong> orders for new<br />
coal fired power generation plant are for supercritical steam cycles and whilst<br />
future orders are difficult to predict, estimates suggest a steady rise in <strong>the</strong><br />
adoption <strong>of</strong> this technology [68] .<br />
Supercritical steam cycles are not limited to coal fired plants exclusively. In<br />
<strong>the</strong>ory, supercritical steam cycles can be used for any technology<br />
incorporating a steam cycle to generate electricity. <strong>Therefore</strong> <strong>the</strong> benefits are<br />
considered applicable to HRSGs within combined cycle gas turbine systems.<br />
With advances in gas turbine technology, combined cycle units are now larger<br />
and HRSGs are operating at higher temperatures. Previously both <strong>the</strong>se factors<br />
were lacking and thus directly affected <strong>the</strong> commercial and technical viability<br />
<strong>of</strong> <strong>the</strong> supercritical HRSG.<br />
4.4 New Applications for HRSGs<br />
4.4.1 The Role <strong>of</strong> HRSGs in IGCC Plant<br />
4.4.1.1 IGCC Plant Description<br />
Whilst gas turbine technology has been applied previously in natural gas and<br />
oil fired combined cycle plants, <strong>the</strong> development <strong>of</strong> <strong>the</strong> Integrated Gasification<br />
Combined Cycle (IGCC) allows both solid and liquid fuels to be <strong>the</strong> main<br />
(88)
source <strong>of</strong> fuel for <strong>the</strong> plant. After several years <strong>of</strong> technology development and<br />
demonstration operation, this power plant technology is approaching <strong>the</strong> status<br />
<strong>of</strong> commercial operation.<br />
The concept <strong>of</strong> an IGCC power plant incorporates an oxygen or air-blown<br />
gasifier operating at high pressure and producing a raw gas, which is cleaned<br />
<strong>of</strong> most pollutants and burned in <strong>the</strong> combustion chamber <strong>of</strong> a gas turbine<br />
generator set for power generation. The sensible heat <strong>of</strong> <strong>the</strong> raw gas<br />
production process along with <strong>the</strong> hot exhaust gas from its combustion in <strong>the</strong><br />
gas turbine are used to produce steam. The steam, in turn, is <strong>the</strong>n utilised to<br />
generate additional electrical power through a series <strong>of</strong> steam turbines. The<br />
main subsystems <strong>of</strong> an IGCC power plant are <strong>the</strong>refore:-<br />
• Gasification plant including feedstock preparation system<br />
• Raw gas heat recovery system<br />
• Gas purification system with sulphur recovery<br />
• Air separation unit (ASU); required only for oxygen-blown gasification<br />
• Gas turbine with electrical generator<br />
• Heat recovery steam generator (HRSG)<br />
• Steam turbine system with electrical generator<br />
The actual coal gasification process for IGCC power generation is classified<br />
into three categories namely, stationary bed (Lurgi and British Gas Lurgi<br />
systems), fluidised bed (High Temperature Winkler, U-gas and Kellog-Rust-<br />
Westinghouse systems) and entrained-flow bed.<br />
The entrained flow bed gasification process uses an oxygen blown gasifier and<br />
is <strong>the</strong> most proven technology for single unit with large capacity applications.<br />
The entrained flow bed gasifier has essentially five distinctive types according<br />
to manufacturer (Texaco, Destec, Prenflo, Shell and GazCobinat Schwarze<br />
Pumpe). Of <strong>the</strong> five, two distinct categories are apparent:<br />
• Wet feed processes such as Texaco and Destec utilise a coal slurry feed.<br />
• Dry feed process such as Prenflo, Shell and GazCobinat Schwarze Pumpe<br />
(GSP) utilise a dry powder feed.<br />
Generally <strong>the</strong> temperatures within <strong>the</strong> gasifiers are lower in <strong>the</strong> case <strong>of</strong> <strong>the</strong> wet<br />
feed process than <strong>the</strong> dry feed process. Water-cooled walls, ra<strong>the</strong>r than<br />
firebrick are <strong>the</strong>refore necessary. Manufacturers claim that a dry powder feed<br />
gasifier has a slight advantage in terms <strong>of</strong> cycle efficiency over <strong>the</strong> coal slurry<br />
gasifier. Dry processes systems are however, considered to be more<br />
complicated than <strong>the</strong>ir counterpart. These complications are generally<br />
associated with reliability penalties. On <strong>the</strong> whole <strong>the</strong> unit investment for <strong>the</strong><br />
dry feed gasifier is considered greater than <strong>the</strong> wet feed unit.<br />
A schematic showing a typical IGCC utility plant layout is shown in Figure<br />
33. This figure illustrates <strong>the</strong> plant arrangement based on a Shell dry feed<br />
entrained-flow gasification process. The cycle is described in detail below:-<br />
(89)
Initially, <strong>the</strong> coal is pulverised in a roll mill and <strong>the</strong>n conveyed to a dryer.<br />
Within <strong>the</strong> dryer <strong>the</strong> coal is flash dried in a stream <strong>of</strong> hot nitrogen which has<br />
been supplied from an ASU and heated by low-pressure steam. The dried coal<br />
is separated in cyclones and <strong>the</strong> nitrogen cooled and <strong>the</strong> water removed. This<br />
process reduces <strong>the</strong> moisture content <strong>of</strong> <strong>the</strong> coal considerably. The coal is <strong>the</strong>n<br />
pressurised with additional nitrogen from <strong>the</strong> ASU and fed into <strong>the</strong> dry-feed,<br />
entrained flow, slagging gasifier through lock hoppers. In addition to <strong>the</strong><br />
nitrogen, <strong>the</strong> ASU also provides a steady supply <strong>of</strong> oxygen into <strong>the</strong><br />
gasification chamber.<br />
The gasification pressure vessel is protected from <strong>the</strong> hot gasification products<br />
by a tube wall construction in which intermediate pressure (IP) steam is raised.<br />
The gasifier operates at a pressure <strong>of</strong> 25bara and a temperature <strong>of</strong> 1400ºC and<br />
produces a raw fuel gas, mainly composed <strong>of</strong> carbon monoxide (CO) and<br />
hydrogen (H2). Most <strong>of</strong> <strong>the</strong> coal ash forms a molten slag, which falls into a<br />
water bath at <strong>the</strong> bottom <strong>of</strong> <strong>the</strong> gasification chamber. Sensible heat is<br />
recovered from <strong>the</strong> raw gas in a waste heat boiler situated at <strong>the</strong> top <strong>of</strong> <strong>the</strong><br />
gasifier. This boiler evaporates water bled from <strong>the</strong> high pressure (HP) circuit.<br />
In addition, fur<strong>the</strong>r heat is also recovered from a syngas cooler after exiting<br />
<strong>the</strong> gasifier. To ensure that <strong>the</strong> fly ash is solid prior to entering <strong>the</strong> syngas<br />
cooler, cooled raw gas is recycled from <strong>the</strong> outlet <strong>of</strong> <strong>the</strong> syngas cooler.<br />
The syngas cooler heat exchanger consists <strong>of</strong> economiser and evaporator<br />
surfaces and generates IP steam supplied directly from <strong>the</strong> IP pump. The<br />
remaining heat in <strong>the</strong> raw fuel gas is exchanged in a gas-to-gas heat<br />
exchanger. This exchanger utilises <strong>the</strong> raw fuel gas to re-heat <strong>the</strong> cleaned fuel<br />
gas after an <strong>acid</strong> gas removal process. The gas cleaning process itself is done<br />
in stages. Initially, <strong>the</strong> fly ash is removed by cyclones and by water scrubbers,<br />
which also absorb any hydrogen chloride (HCl) present. Heat is extracted for<br />
boiler feedwater heating and <strong>the</strong> cooled raw gas <strong>the</strong>n passed to <strong>the</strong> purification<br />
stage where sulphur-bearing compounds, mainly hydrogen sulphide (H2S) and<br />
cabonyl sulphide (COS), are removed in order to protect <strong>the</strong> gas turbine and<br />
also to meet environmental legislation. These compounds are absorbed by<br />
counter-current washing with Purisol solvent and are recovered from this<br />
solvent in a series <strong>of</strong> flash columns. The solvent is recycled and <strong>the</strong> sulphurbearing<br />
compounds are sent to <strong>the</strong> sulphur recovery plant. This plant is based<br />
on a Claus design. Unreacted gases are treated in a SCOT tails gas recovery<br />
unit. Heat generated in <strong>the</strong> Claus plant is used for boiler feed water heating.<br />
The clean fuel gas is saturated with hot water in a humidifier, which helps to<br />
reduce <strong>the</strong> NOx formation in <strong>the</strong> gas turbine combustor. Prior to entry to <strong>the</strong><br />
combustor, <strong>the</strong> fuel gas is fur<strong>the</strong>r heated by an exchanger using a bleed from<br />
<strong>the</strong> high-pressure, high-temperature (HP/HT) economiser. At <strong>the</strong> combustor,<br />
<strong>the</strong> clean fuel gas is mixed with air supplied directly from <strong>the</strong> GE 9FA turbine<br />
compressor alongside compressed nitrogen, <strong>the</strong> original nitrogen source being<br />
air from <strong>the</strong> gas turbine compressor which has been separated in <strong>the</strong> ASU.<br />
From <strong>the</strong> gas turbine, <strong>the</strong> hot flue gas passes to <strong>the</strong> HRSG where steam is<br />
raised at two pressure levels (NB <strong>the</strong> IP stream is only superheated within <strong>the</strong><br />
(90)
HRSG, <strong>the</strong> steam itself is originally raised within <strong>the</strong> gasifier). The cooled<br />
gases are <strong>the</strong>n exhausted via <strong>the</strong> stack to atmosphere.<br />
The condensate from <strong>the</strong> low pressure LP steam turbine is passed through a<br />
condensate preheater prior to entry to <strong>the</strong> deaerator. Here <strong>the</strong> incoming water<br />
is heated by direct contact with steam. From <strong>the</strong> deaerator, <strong>the</strong>re are three<br />
supply lines to <strong>the</strong> HRSG, namely <strong>the</strong> HP, IP and LP lines.<br />
The LP pump supplies feedwater directly to an LP evaporator within <strong>the</strong><br />
HRSG. Following evaporation, some saturated steam is extracted after <strong>the</strong> LP<br />
evaporator and used in <strong>the</strong> dryer to remove moisture from <strong>the</strong> incoming<br />
pulverised fuel (PF). The remaining saturated steam from <strong>the</strong> evaporator feeds<br />
into <strong>the</strong> LP superheater. After being superheated, <strong>the</strong> LP steam is split into two<br />
lines. One line supplies <strong>the</strong> superheated LP steam to <strong>the</strong> LP turbine ano<strong>the</strong>r<br />
recirculates <strong>the</strong> LP superheated steam back to <strong>the</strong> deareator.<br />
The IP pump supplies feed water to <strong>the</strong> syngas cooler and gasifier membrane<br />
wall where <strong>the</strong> heat from <strong>the</strong> gasification process is utilised to generate IP<br />
steam as previously described. Some steam is also bled <strong>of</strong>f and fed to <strong>the</strong><br />
gasifier itself as part <strong>of</strong> <strong>the</strong> gasification process. The IP steam from <strong>the</strong> gasifier<br />
is <strong>the</strong>n fed into <strong>the</strong> HRSG for superheating. Following superheating, <strong>the</strong> IP<br />
steam is added to <strong>the</strong> exit line from <strong>the</strong> HP turbine. These lines combine and<br />
are reheated in <strong>the</strong> HRSG before entering <strong>the</strong> IP turbine.<br />
The HP pump supplies feedwater to <strong>the</strong> high-pressure, low-temperature<br />
(HP/LT) economiser and <strong>the</strong>n on to <strong>the</strong> HP/HT economiser. Upon leaving <strong>the</strong><br />
HP/HT economiser, feedwater is extracted to supply <strong>the</strong> waste heat boiler<br />
within <strong>the</strong> gasifier (see above) as well as supplying a source <strong>of</strong> heat for <strong>the</strong><br />
clean fuel gas line. Saturated steam is <strong>the</strong>refore produced from both <strong>the</strong> HP<br />
evaporator within <strong>the</strong> HRSG and <strong>the</strong> waste heat boiler within <strong>the</strong> gasifier. The<br />
two steam lines <strong>the</strong>n recombine to be superheated within <strong>the</strong> HRSG. The<br />
superheated HP steam is <strong>the</strong>n fed to <strong>the</strong> HP turbine for power generation.<br />
The IP turbine steam supply consists <strong>of</strong> <strong>the</strong> HP turbine exit flow combined<br />
with <strong>the</strong> HRSG IP line. The LP turbine steam supply consists <strong>of</strong> <strong>the</strong> IP turbine<br />
exit flow combined with <strong>the</strong> HRSG LP line.<br />
(91)
Figure 33: Diagram <strong>of</strong> a typical IGCC plant with dry feed gasifier (Courtesy <strong>of</strong> Mitsui Babcock Energy Ltd)<br />
(92)
4.4.1.2 IGCC Plant Performance<br />
As can be seen from Figure 33 and <strong>the</strong> description above, in order to enhance<br />
<strong>the</strong> plant efficiency, <strong>the</strong> steam cycle <strong>of</strong> <strong>the</strong> HRSG in an IGCC plant is very<br />
much integrated with o<strong>the</strong>r plant components such as <strong>the</strong> gasifier. For such<br />
plant, in general, overall cycle efficiencies <strong>of</strong> around 43% can be achieved.<br />
The efficiency <strong>of</strong> an IGCC plant is however still essentially lower than that <strong>of</strong><br />
a typical gas fired combined cycle plant. In addition to <strong>the</strong> loss <strong>of</strong> chemical<br />
energy from <strong>the</strong> removal <strong>of</strong> sulphur and o<strong>the</strong>r combustible contaminants, <strong>the</strong><br />
hot gas leaving <strong>the</strong> gasifier must be cooled in order to allow effective chemical<br />
and ash removal. <strong>Therefore</strong> <strong>the</strong> combination from both gasification and <strong>the</strong> gas<br />
cooling are responsible for <strong>the</strong> lower overall cycle efficiency [69] .<br />
Since <strong>the</strong> 1950’s <strong>the</strong>re have been 24 IGCC plants constructed or planned for<br />
construction throughout <strong>the</strong> world. These are based on several different<br />
variations <strong>of</strong> <strong>the</strong> gasification process. Of <strong>the</strong>se 24, some 3 are dismantled, 17<br />
are in operation and <strong>the</strong> remaining are ei<strong>the</strong>r at <strong>the</strong> planning, engineering or<br />
construction stage.<br />
In recent years <strong>the</strong> numbers <strong>of</strong> large Utility IGCC plants have been growing<br />
and in both <strong>the</strong> USA and Europe IGCC plant have reached <strong>the</strong><br />
commercialisation stage. In Europe three large scale IGCC (>250MWe) plants<br />
based on combining state-<strong>of</strong>-<strong>the</strong>-art gasifier technology and a high degree <strong>of</strong><br />
HRSG process steam integration have been constructed and successfully<br />
operated during <strong>the</strong> last few years. Two <strong>of</strong> <strong>the</strong>se, Buggenum (Ne<strong>the</strong>rlands) and<br />
Puertollano (Spain) employ coal as <strong>the</strong> main fuel source whilst Priola Gargallo<br />
(Italy) utilises refinery residues. In both coal based plants dry feed entrainedflow<br />
gasifiers were selected and in <strong>the</strong> case <strong>of</strong> <strong>the</strong> refinery residues-based<br />
plant <strong>the</strong> wet feed entrained-flow gasifier process was chosen.<br />
In <strong>the</strong> USA <strong>the</strong>re are currently two IGCC units generating electricity<br />
commercially - <strong>the</strong> United States Tampa Electric unit at Polk Power (250<br />
MWe) station and <strong>the</strong> Cinergy owned (260 MWe) plant at Wabash River.<br />
Characteristics <strong>of</strong> <strong>the</strong>se key plants [69] are outlined in Table 6 alongside those<br />
<strong>of</strong> o<strong>the</strong>r IGCC plant world-wide.<br />
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Plant Country Start Fuel Process MWe Status<br />
Steag F.R. Germany 1952 Coal Lurgi 50 Dismantled<br />
Steag F.R. Germany 1959 Coal Lurgi 150 Dismantled<br />
Coolwater USA, Cal. 1984 Coal Texaco 100 Dismantled<br />
Plaquemine USA, La 1986 Coal Destec 220 Operating<br />
Demkolec Ne<strong>the</strong>rlands 1993 Coal Shell 250 Operating<br />
Tampa,Polk USA, Florida 1996 Coal Texaco 250 Operating<br />
Eldorado USA, Kansas 1996 Coke Texaco 40 Operating<br />
Wabash USA, Indiana 1996 Coal Destec 262 Operating<br />
Schwarze-<br />
Pumpe<br />
F.R. Germany 1996 Coal/Oil Shell 40 Operating<br />
Pernis Ne<strong>the</strong>rlands 1997 Heavy Shell 127 Operating<br />
Oil<br />
Pinon Pines USA, Nevada 1998 Coal KRW 80 Operating<br />
Puertallano Spain 1998 Coal Prenflo 300 Operating<br />
I.S.A.B Italy 1998 Asphalt Texaco 540 Operating<br />
Saras Italy 1999 Tar Texaco 550 Operating<br />
Star USA, Del. 1999 Coke Texaco 240 Operating<br />
A.P.I. Italy 1999 Tar Texaco 250 Operating<br />
Fife Power UK, Scotland 1999 Coal BGL 120 Operating<br />
I.B.I.L India 2000 Lignite Tampella 60 Operating<br />
G.S.K Japan 2000 Tar Texaco 540 Operating<br />
Fife Power UK, Scotland 2000 Coal/Rdf BGL 400 Operating<br />
Zuv Czec Rep. 2000 Coal HTW 400 Planning<br />
S.P.C.C. China, Yantai 2003/4 - - 2x400 Planning<br />
K.P.E USA, 2003/4 - - - Planning<br />
Global<br />
Energy<br />
Kentucky<br />
USA, Ohio 2003/4 - - 580 Planning<br />
Table 6: IGCC plants world-wide.<br />
Two main disadvantages which are usually associated with IGCC are <strong>the</strong><br />
reliability / availability <strong>of</strong> <strong>the</strong>se combined cycles and <strong>the</strong> initial significant<br />
capital outlay [<strong>70</strong>] . Whilst <strong>the</strong> reliability/availability factor is believed to be<br />
improving as is illustrated from <strong>the</strong> efficient running <strong>of</strong> <strong>the</strong> Pernis plant in <strong>the</strong><br />
Ne<strong>the</strong>rlands [71] , <strong>the</strong> cost <strong>of</strong> an IGCC plant still remains relatively higher than a<br />
PF plant with a flue gas desulphurisation system installed.<br />
However, <strong>the</strong> main benefit <strong>of</strong> an IGCC plant is its ability to allow coal to be<br />
fired in a clean and efficient manner. The removal <strong>of</strong> contaminants during <strong>the</strong><br />
gas clean up results in a process which is potentially <strong>the</strong> cleanest type <strong>of</strong> coalfired<br />
power plant in operation. Whilst coal remains <strong>the</strong> largest unused source<br />
<strong>of</strong> fossil fuel in <strong>the</strong> world, it makes environmental sense to develop<br />
technologies that allow it to compete with its “naturally cleaner” counterparts<br />
and <strong>the</strong>refore reduce <strong>the</strong> rate <strong>of</strong> consumption <strong>of</strong> premium liquid and gaseous<br />
fuels.<br />
4.4.2 Biomass Integrated Gasification – Combined Cycle<br />
Biomass IGCC applications tend to be sized at <strong>the</strong> industrial ra<strong>the</strong>r than <strong>the</strong><br />
utility scale due to <strong>the</strong> logistics <strong>of</strong> fuel supply. They are unlikely to reach<br />
utility scale, even once <strong>the</strong> technology is mature, due to <strong>the</strong> low energy density<br />
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<strong>of</strong> biomass fuels and <strong>the</strong> land area and fuel supply infrastructure required to<br />
support even a relatively small plant.<br />
There are a variety <strong>of</strong> approaches to biomass gasification including fixed bed,<br />
rotary kiln, pressurised circulating fluidised bed (CFB), atmospheric CFB and<br />
<strong>the</strong> Batelle process [72] . The air blown CFB, fixed bed and rotary kiln<br />
approaches produce a low calorific value (typically 5-6MJNm -3 ) ‘syngas’<br />
while <strong>the</strong> Batelle process by excluding air and using steam as <strong>the</strong> gasifying<br />
medium produces a medium calorific value gas (~15 MJNm -3 ). The ‘syngas’<br />
from all <strong>of</strong> <strong>the</strong>se processes can be burnt in a GT or a reciprocating engine with<br />
exhaust heat recovery. If syngas is to be burnt in an engine, it must be cleaned<br />
first to remove particulates and in some cases ‘tars’ as well. Current gas clean<br />
up technology requires that <strong>the</strong> gas be cooled from <strong>the</strong> gasification<br />
temperature (typically 850 - 950°C) before filtration. There are <strong>the</strong>refore two<br />
HRSGs in <strong>the</strong> system, one to recover heat from <strong>the</strong> hot process gas prior to<br />
filtering and <strong>the</strong> second to recover heat from <strong>the</strong> engine exhaust. The ‘syngas’<br />
cooler HRSG will be exposed to carry over <strong>of</strong> bed material and ash. Biomass<br />
fuels may be rich in alkali metals which increase <strong>the</strong> potential for tube fouling.<br />
This needs to be taken into account in <strong>the</strong> design.<br />
Very few BIG-CC projects have yet been successfully developed. If BIG-CC<br />
technology can be made to operate reliably and economically it will open up a<br />
new market for industrial scale HRSGs.<br />
4.4.3 Microturbines<br />
In general, microturbines are unlikely to be coupled with HRSGs. The<br />
relatively low exhaust temperature (if recuperated as most are) and flow are<br />
not normally sufficient for economic steam generation at useful steam<br />
conditions. However, microturbine suppliers are working on scaling up <strong>the</strong>ir<br />
units. Bowman Power Systems expect to release a 200kWe unit soon and<br />
believe that microturbines up to 500kWe are feasible. At <strong>the</strong> larger sizes <strong>the</strong>y<br />
are more likely to be coupled to HRSGs to provide steam flows for smaller<br />
consumers in some specialist applications. It is possible that <strong>the</strong>y could be<br />
used for air pre-heating or provide heat for an LP circuit as part <strong>of</strong> a larger<br />
boiler system.<br />
4.5 Conclusions<br />
• Future increases in HRSG operating conditions will largely be dictated by<br />
increases in GT exhaust temperature.<br />
• One area <strong>of</strong> significant interest is once through design. The main benefit <strong>of</strong><br />
this technology at present is its suitability for flexible operation. In <strong>the</strong><br />
long-term future, it should pave <strong>the</strong> way for supercritical cycles with even<br />
higher <strong>the</strong>rmal efficiencies.<br />
• Ano<strong>the</strong>r area <strong>of</strong> significant interest is <strong>the</strong> use <strong>of</strong> HRSG steam for GT blade<br />
cooling in <strong>the</strong> latest class <strong>of</strong> GTs. This presents significant challenges for<br />
HRSG design in attaining <strong>the</strong> high steam qualities required.<br />
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• The use <strong>of</strong> HRSGs within IGCC plant is now approaching <strong>the</strong> status <strong>of</strong><br />
commercial operation, although <strong>the</strong> costs still remain relatively high.<br />
• O<strong>the</strong>r development areas include modular design to reduce build costs,<br />
improving reliability, and improving access. The latter two items address<br />
specific problems experienced by plant operators. Improvements in <strong>the</strong>se<br />
areas are perceived to provide product differentiation in an extremely<br />
competitive market place.<br />
• Industrial scale HRSG technology is relatively mature. Most development<br />
comes from <strong>the</strong> integration <strong>of</strong> HRSGs within new processes, and <strong>the</strong><br />
trickling down <strong>of</strong> technology from utility scale HRSGs. One exception is<br />
<strong>the</strong> use <strong>of</strong> once through technology which is already standard practice for<br />
one HRSG supplier.<br />
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5 WORLD-WIDE ACTIVITIES<br />
5.1 Introduction<br />
This chapter reviews <strong>the</strong> current trends in <strong>the</strong> Global HRSG market. The main<br />
sources <strong>of</strong> HRSG supply and <strong>the</strong> countries responsible for purchasing HRSGs<br />
are highlighted, alongside capabilities <strong>of</strong> <strong>the</strong> key players in <strong>the</strong> Global HRSG<br />
market.<br />
Two approaches were taken to finding information for this section <strong>of</strong> <strong>the</strong><br />
report. An internet search was carried out to try to identify as many companies<br />
as possible that are active in <strong>the</strong> field. Appendix A shows a list <strong>of</strong> <strong>the</strong><br />
companies identified and a summary <strong>of</strong> <strong>the</strong>ir capabilities. A brief<br />
questionnaire was sent to each <strong>of</strong> <strong>the</strong>se, but <strong>the</strong> response to this survey was<br />
disap<strong>point</strong>ing, with only thirteen complete responses received. The second<br />
approach was to examine published data. McCoy Power Reports [73] provides a<br />
suitable source, but is focussed on <strong>the</strong> utility sector <strong>of</strong> <strong>the</strong> market.<br />
5.2 Survey Responses<br />
The capabilities <strong>of</strong> <strong>the</strong> companies that responded are summarised in Table 7<br />
below.<br />
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Company<br />
Alstom<br />
Aprovis<br />
Erie<br />
Innovative Steam<br />
Technologies<br />
M E Engineering<br />
Turnover<br />
Range (M $)<br />
>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<br />
Application Utility Combined Cycle X X X X X X X X X X<br />
BIG-CC X X<br />
Petrochemicals X X X X X X X X X<br />
O<strong>the</strong>r chemical / process X X X X X X X X<br />
Iron, steel & coke X X X X X X<br />
Furnaces / Kilns X X X X X X<br />
Waste incineration X X X X<br />
Industrial GT exhaust X X X X X X X X X X X X<br />
Diesel engine X X X X<br />
Gas engine X X X X<br />
Scale 1-5 X X X X<br />
5-10 X X X X X X<br />
10-20 X X X X X X<br />
20-50 X X X X X X X X X X X<br />
50-100 X X X X X X X X X<br />
>100 X X X X X X X X X<br />
Capabilities Consult X X X X X<br />
Design X X X X X X X X X X X X X X<br />
Manufacture X X X X X X X X X X X X X X<br />
Commission X X X X X X X X X X X X X<br />
Operate X X<br />
Technologies Smoke tube X X X X X X X X<br />
Water tube X X X X X X X X X X X X<br />
OTSG X X X X X X X X<br />
Table 7: Summary <strong>of</strong> capabilities <strong>of</strong> companies responding to survey<br />
(99)<br />
Mitsui Babcock<br />
NEM<br />
Nooter/Eriksen<br />
SFL<br />
TBW<br />
Thermax<br />
Wellmann Robey<br />
Vogt-NEM<br />
TEI Greens
5.3 Utility Scale Market – Published Information<br />
5.3.1 Source <strong>of</strong> Market Information<br />
McCoy’s data was ga<strong>the</strong>red through a written survey <strong>of</strong> US and non-US<br />
suppliers <strong>of</strong> electric power generating equipment and engineering services. As<br />
data from each power plant are cross-checked from various sources, it is<br />
believed that McCoy provides <strong>the</strong> most complete and accurate information<br />
from an independent organisation. The calculations are based on <strong>the</strong> steam<br />
turbine MWe output in combined cycle applications and half <strong>the</strong> gas turbine<br />
output in cogeneration, (non combined cycle) projects. The final figure<br />
generated for total installed electrical capacity is <strong>the</strong>refore somewhat<br />
conservative by this method, however, <strong>the</strong> data provides an excellent<br />
indication <strong>of</strong> trends within <strong>the</strong> market (Section 5.3.2) and major market<br />
players (Section 5.3.3).<br />
5.3.2 The HRSG Buyers<br />
In terms <strong>of</strong> geographical distribution, it is apparent that over <strong>the</strong> past ten years<br />
(1992-2001), <strong>the</strong> biggest buyers by far <strong>of</strong> HRSGs have been in <strong>the</strong> US. A<br />
massive 48% <strong>of</strong> all world-wide purchases have been made by operators in <strong>the</strong><br />
US. Next to <strong>the</strong> US <strong>the</strong> United Kingdom and Japan are <strong>the</strong> joint closest in<br />
terms <strong>of</strong> purchases over this period, however, at just 4% <strong>of</strong> <strong>the</strong> total ten year<br />
sales <strong>the</strong> sheer size and domination <strong>of</strong> <strong>the</strong> US market is obviously apparent.<br />
In terms <strong>of</strong> customer type three categories emerge. These are classed as:<br />
• Non-Utility Generators (NUGs)<br />
• Electricity Utility Power Generators (EUPGs)<br />
• Industrial Power Generators (IPGs).<br />
The NUGs account for some 81% <strong>of</strong> orders over <strong>the</strong> past ten years in <strong>the</strong> US<br />
market and some 49% <strong>of</strong> orders for <strong>the</strong> rest <strong>of</strong> <strong>the</strong> world. Over <strong>the</strong> same ten<br />
year period, EUPGs account for some 17% <strong>of</strong> <strong>the</strong> orders in <strong>the</strong> US alone and<br />
some 44% <strong>of</strong> <strong>the</strong> non-US market.<br />
5.3.3 The HRSG Manufacturers<br />
With respect to <strong>the</strong> outlined ten year period, <strong>the</strong> key manufacturers on an<br />
individual company basis were identified as Alstom Power (14.2%),<br />
Nooter/Eriksen (12.6%), Deltak (9.5%), NEM (7.7%) and Aalborg Industries<br />
(7.5%). Companies outside this top five, in <strong>the</strong> 1-7% share <strong>of</strong> <strong>the</strong> market<br />
included Foster Wheeler Energy (6.4%), Mitsubushi Heavy Industries (4.3%),<br />
Doosan Heavy industries (4.0%) and Mitsui Babcock Energy Limited (1%).<br />
Below <strong>the</strong> 1% threshold, some 50 companies, partnerships or joint ventures<br />
compete for <strong>the</strong> remaining market share.<br />
It is worth noting that many companies are involved in various types <strong>of</strong><br />
commercial agreements with related companies throughout <strong>the</strong> world,<br />
<strong>the</strong>refore if all related companies, joint projects and licensee relationships are<br />
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considered <strong>the</strong> top ranking is altered with NEM taking first place followed by<br />
Nooter/Eriksen and <strong>the</strong>n Alstom Power.<br />
5.4 Conclusions<br />
• Over <strong>the</strong> past ten years (1992-2001), <strong>the</strong> biggest buyers by far <strong>of</strong> utility<br />
scale HRSGs have been in <strong>the</strong> USA, with 48% <strong>of</strong> all world-wide<br />
purchases. Next are <strong>the</strong> United Kingdom and Japan with 4% <strong>of</strong> <strong>the</strong> total<br />
sales.<br />
• Key manufacturers in <strong>the</strong> above period were Alstom Power (14.2%),<br />
Nooter/Eriksen (12.6%), Deltak (9.5%), NEM (7.7%) and Aalborg<br />
Industries (7.5%). Companies outside this top five in <strong>the</strong> 1-7% share <strong>of</strong> <strong>the</strong><br />
market included Foster Wheeler Energy (6.4%), Mitsubishi Heavy<br />
Industries (4.3%), Doosan Heavy industries (4.0%) and Mitsui Babcock<br />
Energy Limited (1%).<br />
• For industrial scale HRSGs, <strong>the</strong>re were around 33% <strong>of</strong> sales in each <strong>of</strong> <strong>the</strong><br />
USA and Europe, with <strong>the</strong> o<strong>the</strong>r leading market being Asia and Australasia<br />
(excluding China) with 19%.<br />
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6 MARKET POTENTIAL<br />
6.1 Introduction<br />
This chapter discusses <strong>the</strong> potential <strong>of</strong> various world-wide markets. The views<br />
expressed are derived from internal consultations amongst <strong>the</strong> project partners<br />
and consultation with o<strong>the</strong>r organisations [74] . The external consultation<br />
included <strong>the</strong> completion <strong>of</strong> a questionnaire by a number <strong>of</strong> companies, which<br />
included information about <strong>the</strong>ir geographical market breakdown by value.<br />
The chapter focuses on <strong>the</strong> US and China as two main areas with significant<br />
potential for development within <strong>the</strong> global market for utility HRSGs, and on<br />
<strong>the</strong> home market in <strong>the</strong> UK. Non- technical barriers to future success within<br />
<strong>the</strong>se markets are identified and discussed.<br />
6.2 Market Survey<br />
The results <strong>of</strong> <strong>the</strong> questionnaire survey have been used to give an idea <strong>of</strong><br />
which markets are most active. The small response to <strong>the</strong> survey means that<br />
confidence in <strong>the</strong> results is low.<br />
The geographical market share averaged over <strong>the</strong> thirteen questionnaire<br />
responses received are shown in Figure 34 below:-<br />
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Figure 34: Average percentage <strong>of</strong> business by geographical market.<br />
Looking at <strong>the</strong> industrial scale sector alone, a breakdown <strong>of</strong> 68 enquiries<br />
received by M E Engineering over <strong>the</strong> last 18 months is shown in Figure 35<br />
below:-<br />
Figure 35: Percentage <strong>of</strong> enquiries coming from geographical market<br />
(Courtesy <strong>of</strong> ME Engineering Ltd).<br />
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10 respondents provided a breakdown <strong>of</strong> <strong>the</strong> proportion <strong>of</strong> <strong>the</strong> HRSGs <strong>the</strong>y<br />
supply (by value) in each <strong>of</strong> 6 size categories. The averaged information is<br />
shown below:-<br />
Figure 36: Average percentage <strong>of</strong> business by HRSG size.<br />
This simply shows that <strong>the</strong>re is activity at all scales. It is based on a simple<br />
average <strong>of</strong> <strong>the</strong> percentage <strong>of</strong> units (by value) that each company supplies.<br />
Since <strong>the</strong> companies that supply <strong>the</strong> larger units also have far larger turnover,<br />
in value terms <strong>the</strong> market is dominated by <strong>the</strong> large units.<br />
6.3 Market Perception amongst Consultees<br />
Consultees in <strong>the</strong> US suggest that <strong>the</strong> market for utility scale HRSGs is very<br />
poor currently. Prior to <strong>the</strong> last year or so, <strong>the</strong> market in <strong>the</strong> US was buoyant.<br />
HRSG companies had expanded to meet a demand for new utility scale power<br />
plant. However <strong>the</strong> market is now largely saturated and <strong>the</strong>re is generation<br />
over-capacity. Transmission and distribution networks are close to full<br />
capacity and finance for merchant plant cannot be obtained in <strong>the</strong> current<br />
economic climate. Siemens [10] expect <strong>the</strong> US HRSG market to slump<br />
considerably over <strong>the</strong> next few years. Consolidation amongst HRSG<br />
companies in <strong>the</strong> US is expected. At <strong>the</strong> industrial scale <strong>the</strong>re is more activity.<br />
There are opportunities for <strong>the</strong> development <strong>of</strong> CHP schemes on industrial<br />
sites, largely driven by security <strong>of</strong> price and supply issues in <strong>the</strong> volatile<br />
deregulated electricity market. Concern over climate change is not yet<br />
perceived as a significant influence on policy or <strong>the</strong> market in <strong>the</strong> US.<br />
However, <strong>the</strong> Clean Air Act is having an influence at <strong>the</strong> industrial scale.<br />
Consents are specifying lower NOx emission levels and ra<strong>the</strong>r than retr<strong>of</strong>itting<br />
low NOx boilers and selective catalytic reduction (SCR) some companies are<br />
opting to switch to a completely new CHP scheme.<br />
One consultee identified Russia as a good current market due to <strong>the</strong> need to<br />
replace ageing and inefficient plant. The same is true <strong>of</strong> Central and Eastern<br />
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European (CEE) countries. The market in CEE countries is likely to be<br />
enhanced as <strong>the</strong> EU enlarges as trade with <strong>the</strong>m will become easier and <strong>the</strong>y<br />
will be striving to meet EU environmental standards. Turkey was identified as<br />
a good market due to low gas prices and a large demand for electricity. The<br />
Middle East was identified as a market with good potential due to <strong>the</strong><br />
abundance <strong>of</strong> open cycle gas turbine plant that could be retr<strong>of</strong>itted with<br />
HRSGs for improved efficiency by operating in combined cycle mode or for<br />
power augmentation by turbine inlet chilling. One consultee identified Italy<br />
and Spain as good markets for oil replacement plant and <strong>the</strong> Middle East for<br />
desalination plant.<br />
The market in China is expanding rapidly, but is viewed as a difficult place to<br />
do business. This is due to <strong>the</strong> bureaucracy <strong>of</strong> complying with <strong>the</strong> local codes<br />
and standards and <strong>the</strong> fierce competition from local manufacturers. The<br />
market in Indonesia is also apparently growing, but competition from Chinese<br />
manufacturers is stiff here too.<br />
A number <strong>of</strong> o<strong>the</strong>r markets were identified by consultees as still being active,<br />
despite <strong>the</strong> general depression <strong>of</strong> <strong>the</strong> CHP market throughout Europe<br />
associated with falling electricity prices and rising gas prices. Within Europe<br />
<strong>the</strong> markets in France, Spain, Italy, Germany and Scandinavia are perceived as<br />
being most active for <strong>the</strong> development <strong>of</strong> CHP projects. German and<br />
Scandinavian markets are seen as being more highly regulated still (less<br />
competitive pressure on wholesale electricity prices) and <strong>the</strong>re is price support<br />
for CHP schemes in Germany for a limited period. Some new CHP schemes in<br />
Germany benefit from a guaranteed feed in price. France, Spain and Italy also<br />
have support mechanisms in place for CHP.<br />
6.4 UK Market<br />
The UK electricity generator market has essentially two sub-sectors, utility<br />
CCGT / CHP and industrial CHP as outlined in Table 8.<br />
Utility<br />
CCGT/CHP<br />
Industrial<br />
CHP<br />
DISTRIBUTION BY MWe<br />
+1 MWe +10 MWe +40 MWe +500 MWe<br />
60 20<br />
200 80 20<br />
Table 8: UK power generation market sectors.<br />
Utility CCGT/CHP are required to compete with conventional plant under <strong>the</strong><br />
New Electricity Trading Arrangements (NETA). Industrial CHP plants are<br />
struggling under NETA trading conditions and most are currently operating<br />
<strong>the</strong>ir steam and power supply contracts at a loss. There is <strong>the</strong>refore a degree <strong>of</strong><br />
turmoil within <strong>the</strong> market with attrition expected amongst some <strong>of</strong> <strong>the</strong> players.<br />
However despite competition problems both sectors cannot ignore <strong>the</strong> need to<br />
consider widespread integrity and performance improvements to meet NETA<br />
market and client contractual demands.<br />
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6.4.1 Non-Technical Barriers in <strong>the</strong> UK Utility HRSG Market<br />
In terms <strong>of</strong> sustaining a pr<strong>of</strong>itable business based on <strong>the</strong> internal UK utility<br />
HRSG market certain barriers currently exist:<br />
6.4.1.1 Current Surplus <strong>of</strong> Generating Capacity in <strong>the</strong> UK<br />
The electricity market in <strong>the</strong> UK is currently oversupplied, with <strong>the</strong> ‘Seven<br />
Year Statement’ published by <strong>the</strong> National Grid Company in 2002 [75] stating<br />
that <strong>the</strong> capacity available for <strong>the</strong> 2002/3 winter is 67564MW. This capacity is<br />
made up as shown in Figure 37 below, with CCGTs contributing<br />
approximately 32.5% to <strong>the</strong> overall generation mix. Electricity demand in<br />
extreme winter wea<strong>the</strong>r conditions is expected to reach 55306MW, giving a<br />
surplus plant margin <strong>of</strong> 22.2%. However, in normal wea<strong>the</strong>r conditions, <strong>the</strong><br />
peak demand is projected to be 52500MW (this was <strong>the</strong> peak demand during<br />
<strong>the</strong> winter <strong>of</strong> 2001/2), resulting in an even higher plant margin. This is<br />
attributed to <strong>the</strong> fact that governmental responsibilities for sufficient and<br />
reliable power generation in <strong>the</strong> past have led to capacity above actual need.<br />
Figure 37: UK generation capacity available for <strong>the</strong> 2002/3 winter.<br />
Although a reasonable margin on plant capacity is obviously a necessity, <strong>the</strong><br />
UK remains oversupplied and, as a consequence, energy prices are very low<br />
and are likely to remain so for <strong>the</strong> foreseeable future. This means that although<br />
CCGTs are relatively cheap to build and operate (see Sections 3.8.1 and<br />
3.8.2), <strong>the</strong>y remain economically unviable under current market conditions.<br />
This, coupled with <strong>the</strong> high price <strong>of</strong> natural gas (see below) not only makes<br />
<strong>the</strong> building <strong>of</strong> new, utility-scale HRSGs unlikely, but has also resulted in <strong>the</strong><br />
recent mothballing <strong>of</strong> some UK CCGT plant.<br />
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6.4.1.2 Fluctuations in <strong>the</strong> Price <strong>of</strong> Natural Gas<br />
Recently investors have been dissuaded from investing in CCGT plant by <strong>the</strong><br />
volatility in <strong>the</strong> price <strong>of</strong> natural gas. Price volatility results in difficulties in<br />
reliably forecasting <strong>the</strong> overall costs occurred over <strong>the</strong> entire operating life <strong>of</strong><br />
<strong>the</strong> combined cycle plant.<br />
6.4.1.3 Current Unpredictability <strong>of</strong> <strong>the</strong> UK Retr<strong>of</strong>it Market<br />
With little in <strong>the</strong> way <strong>of</strong> large new-build utility plants in <strong>the</strong> UK, <strong>the</strong> market<br />
for upgrading existing facilities within <strong>the</strong> country must be <strong>the</strong> primary focus.<br />
The effects <strong>of</strong> flexible operation are becoming more and more apparent to<br />
operators, so <strong>the</strong> potential for upgrade opportunities is large. However with<br />
flexibility upgrades on drainage, pressure parts and casings expected to be<br />
between £100k and £400k per HRSG, <strong>the</strong> depth <strong>of</strong> <strong>the</strong> market remains<br />
uncertain. Factors within <strong>the</strong> operators market as a direct result <strong>of</strong> deregulation<br />
suggest that <strong>the</strong> availability <strong>of</strong> finances to fund <strong>the</strong>se upgrades is questionable.<br />
6.4.2 UK Industrial CHP Market<br />
The annual Directory <strong>of</strong> UK Energy Statistics (DUKES) for 2001 gives<br />
various data for CHP schemes in <strong>the</strong> UK. The data is ga<strong>the</strong>red through <strong>the</strong><br />
Government’s CHP quality assurance scheme. The majority <strong>of</strong> schemes are<br />
fuelled with natural gas (61%), with fuel oil accounting for 7%, 2% from<br />
renewables and <strong>the</strong> balance from various process exhausts or by-product fuels.<br />
The majority <strong>of</strong> <strong>the</strong> 1573 schemes are small, but generating capacity is<br />
dominated by <strong>the</strong> minority <strong>of</strong> larger schemes.<br />
Electrical capacity size % <strong>of</strong> total number <strong>of</strong> % <strong>of</strong> total generating<br />
range<br />
schemes<br />
capacity<br />
< 100 kWe 43.2 0.9<br />
100 kWe – 999 kWe 40.1 3.2<br />
1 MWe – 9.9 MWe 12.1 16.2<br />
> 10 MWe 4.6 79.7<br />
Table 9: CHP Schemes by size, 2001.<br />
Figure 38 below shows <strong>the</strong> installed CHP capacity in <strong>the</strong> UK for <strong>the</strong> last 5<br />
years.<br />
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Figure 38: Installed CHP capacity in <strong>the</strong> UK 1997-2001.<br />
The chart shows that through <strong>the</strong> 1990s <strong>the</strong> pace <strong>of</strong> addition <strong>of</strong> CHP capacity<br />
was accelerating with <strong>the</strong> rate peaking in 2000 with 844MW <strong>of</strong> plant being<br />
commissioned, a 22% increase on <strong>the</strong> previous year. However in 2001 only 38<br />
MW <strong>of</strong> capacity was added. As part <strong>of</strong> this study <strong>the</strong> Combined Heat and<br />
Power Association and a number <strong>of</strong> companies involved in <strong>the</strong> supply and<br />
installation <strong>of</strong> CHP schemes were consulted. All <strong>of</strong> <strong>the</strong>se reinforced <strong>the</strong> view<br />
<strong>of</strong> <strong>the</strong> market given by <strong>the</strong> DUKES statistics. The market for CHP schemes<br />
was buoyant towards <strong>the</strong> end <strong>of</strong> <strong>the</strong> 1990s but <strong>the</strong>n collapsed. The reasons for<br />
<strong>the</strong> current depressed state <strong>of</strong> <strong>the</strong> market are discussed below. The trend is<br />
mirrored in <strong>the</strong> figures for electrical export from CHP schemes. In 2000 8482<br />
GWh were exported. In 2001 <strong>the</strong> figure had dropped to 5960 GWh. Similar<br />
problems with <strong>the</strong> CHP market apply elsewhere in <strong>the</strong> EU, such as in <strong>the</strong><br />
Ne<strong>the</strong>rlands and Germany [76] .<br />
6.4.2.1 Stricter Consents Policy<br />
In 1998 <strong>the</strong> Government introduced a ‘stricter consents policy’ on gas fuelled<br />
electricity generation plant. Under this policy, consent for <strong>the</strong> development <strong>of</strong><br />
any gas fired power plant <strong>of</strong> generating capacity greater than 10MW was<br />
required from <strong>the</strong> Government. The measure was introduced because <strong>of</strong><br />
concern that <strong>the</strong> electricity market was being distorted and coal fired plant was<br />
being unfairly penalised by this. The policy was kept in force while a review<br />
<strong>of</strong> electricity arrangements was carried out. It ended in 2000 with <strong>the</strong><br />
introduction <strong>of</strong> <strong>the</strong> New Electricity Trading Arrangements (NETA). The only<br />
plants granted consents during this period were CHP plants. The stricter<br />
(108)
consents policy had <strong>the</strong> effect <strong>of</strong> concentrating attention on <strong>the</strong> development<br />
<strong>of</strong> CHP projects.<br />
6.4.2.2 Natural Gas Prices<br />
Most CHP plant is fuelled with natural gas. The interconnection <strong>of</strong> <strong>the</strong> UK gas<br />
grid with that <strong>of</strong> continental Europe via <strong>the</strong> Bacton-Zeebrugge pipeline was<br />
accomplished in October 1998. This has exposed <strong>the</strong> UK to <strong>the</strong> higher prices<br />
<strong>of</strong> <strong>the</strong> continental European market and UK natural gas prices have<br />
consequently risen from a low <strong>of</strong> under 14p/<strong>the</strong>rm in 1999 to 19p/<strong>the</strong>rm in<br />
2001 [77] .<br />
6.4.2.3 New Electricity Trading Arrangements<br />
The New Electricity Trading Arrangements (NETA) were brought into force<br />
in March 2001. NETA introduced new regulations governing <strong>the</strong> deregulated<br />
electricity market in <strong>the</strong> UK. Previously <strong>the</strong> pool price at any one time was<br />
paid to all generators supplying power at that time and <strong>the</strong> price was set by <strong>the</strong><br />
most expensive generator. Under NETA, most wholesale electricity sales<br />
between generators and retailers are now concluded well in advance with <strong>the</strong><br />
timing, volume and price <strong>of</strong> supply fixed. A balancing mechanism provides a<br />
means <strong>of</strong> meeting short term demand fluctuations. Fierce competition since<br />
<strong>the</strong> liberalisation <strong>of</strong> <strong>the</strong> market has driven down <strong>the</strong> prices at which contracts<br />
have been concluded. Since 1998, when NETA was first proposed, electricity<br />
wholesale prices have fallen by 40%. Between April 2001 and February 2002<br />
baseload prices have fallen by 20% and peak prices by 27% [78] .<br />
What is more, CHP schemes are unlikely to get <strong>the</strong> best prices. CHP schemes<br />
are generally small compared to utility scale plant so have little market<br />
influence. Penalty payments are levied if a generator fails to meet its<br />
scheduled supply pr<strong>of</strong>ile. Many grid connected CHP schemes tend to run to<br />
meet <strong>the</strong> heat or steam demands <strong>of</strong> its customer, ra<strong>the</strong>r than an electricity<br />
supply pr<strong>of</strong>ile, and <strong>the</strong> electrical output is <strong>the</strong>refore not entirely predictable.<br />
The CHP scheme is exposed to a potential mismatch between <strong>the</strong> heat and<br />
electrical demand pr<strong>of</strong>iles that it is trying to meet. This results ei<strong>the</strong>r in NETA<br />
penalties or running at lower efficiency than <strong>the</strong> design <strong>point</strong>.<br />
6.4.3 O<strong>the</strong>r Barriers for UK Firms<br />
The grid has evolved to distribute electricity from a small number <strong>of</strong> large<br />
generators. A substantial amount <strong>of</strong> power is wasted in <strong>the</strong> form <strong>of</strong><br />
transmission losses. In 1999 it is estimated that transmission and distribution<br />
losses accounted for 1336 TWh, equivalent to 11.6% <strong>of</strong> <strong>the</strong> World’s final<br />
electricity demand [79] . CHP plants are generally connected to local grid<br />
networks and <strong>the</strong> separation between generator and consumer is smaller,<br />
resulting in lower transmission and distribution losses. Decentralised or<br />
embedded generation can also have benefits in streng<strong>the</strong>ning <strong>the</strong> local grid and<br />
improving power quality. These benefits <strong>of</strong> embedded generation are currently<br />
not fully reflected in <strong>the</strong> sale price <strong>of</strong> electricity from CHP schemes. However<br />
<strong>the</strong> connection <strong>of</strong> a large number <strong>of</strong> smaller generators may also cause<br />
difficulties for <strong>the</strong> grid system relating to fault levels, islanding and power<br />
(109)
quality. Where substantial modifications are required to <strong>the</strong> grid to allow<br />
connection, <strong>the</strong> cost to <strong>the</strong> scheme developer may be prohibitive, especially<br />
for smaller schemes. The cost and complexity <strong>of</strong> grid connection is currently a<br />
barrier to <strong>the</strong> development <strong>of</strong> smaller CHP schemes.<br />
Anecdotal evidence suggests that banks are not willing to invest in energy<br />
projects at present due to <strong>the</strong> <strong>risk</strong> associated with price volatility and<br />
uncertainties within energy markets. The market is in such a poor state that <strong>the</strong><br />
major CHP developers have disbanded <strong>the</strong>ir development teams. The only<br />
projects that may go ahead currently are ei<strong>the</strong>r ones where all <strong>of</strong> <strong>the</strong> power<br />
will be consumed on site or that have ano<strong>the</strong>r factor driving <strong>the</strong>m, such as<br />
avoided grid connection streng<strong>the</strong>ning costs.<br />
One UK consultee identified <strong>the</strong> diversity <strong>of</strong> European standards as being a<br />
problem for companies trying to export to o<strong>the</strong>r EU countries. A common<br />
European standard for shell boiler design is being introduced (EN12953), but<br />
<strong>the</strong> consultee was concerned that oversees clients will continue to specify <strong>the</strong>ir<br />
own national standards.<br />
The current strength <strong>of</strong> sterling was also identified as a problem for UK HRSG<br />
suppliers. There is strong competition in <strong>the</strong> market place and o<strong>the</strong>r European<br />
suppliers can undercut UK companies, even in <strong>the</strong> UK despite <strong>the</strong>ir higher<br />
transport costs.<br />
6.4.4 Future Industrial CHP Market Potential in <strong>the</strong> UK and Mainland<br />
Europe<br />
The European Commission sponsored ‘Future Cogen’ study assessed <strong>the</strong><br />
potential for <strong>the</strong> expansion <strong>of</strong> CHP within EU member states and Central and<br />
Eastern European (CEE) states. It modelled <strong>the</strong> growth <strong>of</strong> CHP under four<br />
scenarios ranging from <strong>the</strong> pessimistic ‘deregulated liberalisation’ scenario to<br />
<strong>the</strong> optimistic ‘post Kyoto’ scenario. In <strong>the</strong> ‘deregulated liberalisation’<br />
scenario EU CHP capacity grew by only 16 GW from a base level <strong>of</strong> 65GW to<br />
81GW in 2020. In contrast, under <strong>the</strong> ‘Post Kyoto’ scenario installed capacity<br />
grew by 130GW to 195GW by 2020. Under <strong>the</strong> ‘Post Kyoto’ scenario, CHP in<br />
<strong>the</strong> UK would grow from a base level <strong>of</strong> 3453GW to 27215GW in 2020. Not<br />
all <strong>of</strong> this growth would come from CHP schemes involving steam generation<br />
but it would represent a substantial opportunity for growth in <strong>the</strong> HRSG<br />
industry [80] .<br />
At present CHP opportunities in <strong>the</strong> UK are limited to those that have specific<br />
driving factors o<strong>the</strong>r than just more efficient use <strong>of</strong> fuel. The UK government<br />
has set a target <strong>of</strong> achieving an installed CHP capacity <strong>of</strong> 10GW by 2010,<br />
compared to <strong>the</strong> current capacity <strong>of</strong> 4801MW (2001). Some policy measures<br />
have been introduced to stimulate <strong>the</strong> CHP market. Fuels used in CHP are<br />
exempted from <strong>the</strong> Climate Change Levy (CCL). In <strong>the</strong> April 2002 budget it<br />
was announced that electricity exported from CHP schemes will also be<br />
exempted from <strong>the</strong> CCL (subject to approval under EU state aid rules).<br />
Enhanced capital allowances (ECAs) are allowed on some items <strong>of</strong> CHP<br />
(110)
equipment, increasing <strong>the</strong> opportunities for investment in CHP. However<br />
ECAs are not yet available on all items in a complete installation.<br />
The EU target is to double CHP capacity as a fraction <strong>of</strong> total electricity<br />
generation capacity from 9% (1994) to 18% in 2010. In order to achieve this<br />
target <strong>the</strong> EU have proposed a CHP directive [81] . The key <strong>point</strong>s <strong>of</strong> <strong>the</strong><br />
directive are:-<br />
• The introduction <strong>of</strong> a common definition <strong>of</strong> cogeneration;<br />
• Targeting <strong>of</strong> support at schemes with an electrical capacity <strong>of</strong> up to 50MW<br />
(or at <strong>the</strong> first 50MW <strong>of</strong> larger schemes);<br />
• Providing a guarantee <strong>of</strong> <strong>the</strong> origin <strong>of</strong> electricity from cogeneration;<br />
• The establishment <strong>of</strong> efficiency criteria for cogeneration;<br />
• An obligation on member states to establish <strong>the</strong>ir national potential for<br />
cogeneration;<br />
• Allowing national support schemes for cogeneration in <strong>the</strong> short to<br />
medium term (under state aid rules);<br />
• The establishment <strong>of</strong> objective, transparent and non-discriminatory rules<br />
for grid connection and reinforcement;<br />
• A requirement for member states to review legislative frameworks with a<br />
view to reducing barriers to cogeneration.<br />
These actions should enhance <strong>the</strong> European HRSG market.<br />
The Kyoto agreement sets binding targets for greenhouse gas emission cuts for<br />
signatory countries. CHP has been identified as one <strong>of</strong> <strong>the</strong> most cost-effective<br />
methods <strong>of</strong> cutting CO2 emissions. Joint Implementation and Emissions<br />
Trading mechanisms can potentially be harnessed to help develop CHP<br />
schemes. In ‘Annex II’ countries, <strong>the</strong> Clean Development Mechanism may<br />
<strong>of</strong>fer opportunities to help develop CHP schemes.<br />
6.4.5 Action to Stimulate <strong>the</strong> UK Market / Support <strong>the</strong> UK Industry<br />
A common view was expressed by all UK consultees: <strong>the</strong>re is no problem with<br />
<strong>the</strong> product but huge problems with <strong>the</strong> market. No need for <strong>DTI</strong> funded<br />
research was identified – <strong>the</strong> technology is essentially mature. However <strong>the</strong><br />
Government does need to act to stimulate <strong>the</strong> UK market. The combination <strong>of</strong><br />
NETA and a high natural gas price has dramatically reduced <strong>the</strong> market for<br />
CHP and <strong>the</strong> climate change levy is not seen as being an adequate incentive to<br />
invest in new HRSGs / CHP schemes. Enhanced support for CHP is required<br />
from government and a ‘CHP obligation’ seems to be <strong>the</strong> preferred<br />
mechanism in <strong>the</strong> industry.<br />
The current pessimistic industry view is supported by a report by Forum for<br />
<strong>the</strong> Future / Cambridge Econometrics commissioned by <strong>the</strong> Combined Heat<br />
and Power Association and released in October 2002. This predicted that total<br />
installed capacity would only reach 6.6 GWe by 2010 and 8.6 GWe by 2020<br />
under current conditions, compared to <strong>the</strong> government target <strong>of</strong> 10 GWe by<br />
2010.<br />
(111)
The Combined Heat and Power Association has <strong>the</strong>refore identified <strong>the</strong><br />
following steps as means <strong>of</strong> improving <strong>the</strong> situation for <strong>the</strong> development <strong>of</strong><br />
CHP projects:-<br />
• Introduction <strong>of</strong> a CHP obligation, similar in form to <strong>the</strong> Renewables<br />
Obligation but with a lower buy-out price, to provide an underpinning<br />
market mechanism<br />
• A proactive planning and communication strategy<br />
• Adequate resourcing within government<br />
• Full implementation <strong>of</strong> existing support mechanisms for CHP<br />
• Action to address existing and emerging barriers to CHP<br />
• Delivery <strong>of</strong> effective support to emerging technologies<br />
6.5 North American Market<br />
The North American market at present is considered by some to be expanding<br />
significantly, in contrast to <strong>the</strong> opinions expressed by some consultees (see<br />
Section 6.3 above). In <strong>the</strong> year 2001 according to Power Magazine [61] an<br />
installation record <strong>of</strong> 48.6 GWe in total was established for new gas turbine<br />
based power plants. This figure surpasses <strong>the</strong> 1974 record <strong>of</strong> 43 GWe for new<br />
installations. However, <strong>the</strong> 2001 record is envisaged as being short lived as a<br />
result <strong>of</strong> <strong>the</strong> 66 GWe for 2002 and 69 GWe for 2003 announced or under<br />
construction [61] . Whilst mid-sized aero-derivative gas turbines are part <strong>of</strong> <strong>the</strong><br />
sales surge, <strong>the</strong> vast majority <strong>of</strong> this increased capacity has been, and no doubt<br />
will continue to be in large, utility scale machines.<br />
When it is considered that just 27 GWe <strong>of</strong> new capacity came on line in <strong>the</strong><br />
year 2000, <strong>the</strong> extent <strong>of</strong> <strong>the</strong> rapid growth within <strong>the</strong> North American market is<br />
clearly apparent.<br />
Whilst <strong>the</strong> size <strong>of</strong> <strong>the</strong> North American market is clearly large, <strong>the</strong>re are<br />
obvious signs <strong>of</strong> <strong>the</strong> high level <strong>of</strong> competition existing in this potentially<br />
lucrative business sector. Evidence <strong>of</strong> this rivalry can be found from <strong>the</strong><br />
undisputed fact that in recent years <strong>the</strong> market has attracted <strong>the</strong> attention <strong>of</strong><br />
several new competitors, all contending for <strong>the</strong>ir share <strong>of</strong> <strong>the</strong> pr<strong>of</strong>its.<br />
Fur<strong>the</strong>rmore this additional competition has emerged from both international<br />
manufacturers winning American based contracts and American based<br />
companies with previously limited interests in <strong>the</strong> HRSG market suddenly<br />
expanding <strong>the</strong>ir involvement.<br />
From what was essentially a US supplier only market, <strong>the</strong>re has been a recent<br />
spate <strong>of</strong> key contracts awarded to non-US manufactures such as Toshiba<br />
(Tokyo, Japan), CMI (Brussels, Belgium) and Hitachi (Tokyo, Japan). Foster<br />
Wheeler is a prime example <strong>of</strong> an American company expanding its activities<br />
in <strong>the</strong> HRSG market. Prior to 1997 its HRSG interests were considered not to<br />
be a prime business within <strong>the</strong> company. However, <strong>the</strong> company claims that<br />
having recognised <strong>the</strong> huge potential for rapid combined cycle power plant<br />
expansion, it strategically expanded into this area from its traditional business<br />
<strong>of</strong> solid-fuel boiler fabrication. The end result is that in just 5 years its HRSG<br />
business has now grown from a minor business sector to its largest one.<br />
(112)
6.5.1 Possible Non-Technical Barriers to Development <strong>of</strong> Combined Cycle<br />
Technology within <strong>the</strong> USA<br />
Some analysts [82, 83] are sceptical about <strong>the</strong> future <strong>of</strong> <strong>the</strong> North American<br />
market and predict as much as 50% <strong>of</strong> <strong>the</strong> announced future projects in <strong>the</strong><br />
states will not make it fur<strong>the</strong>r than <strong>the</strong> drawing board. The main reasons cited<br />
are:-<br />
• Inadequate supplies <strong>of</strong> natural gas: Natural gas is <strong>the</strong> fuel <strong>of</strong> choice for at<br />
least 95% <strong>of</strong> <strong>the</strong> projects. The US Energy Information Administration<br />
estimates that natural gas production and delivery would have to rise 40-<br />
50% over <strong>the</strong> next 15 to 20 years to supply <strong>the</strong> projected combined cycle<br />
developments. This is viewed as a somewhat heroic task based on <strong>the</strong> aged<br />
state <strong>of</strong> <strong>the</strong> nation’s gas fields and requirement for extensive new pipelines<br />
for gas delivery.<br />
• Price <strong>of</strong> Gas: Market forces are also at play with <strong>the</strong> high price <strong>of</strong> gas<br />
dissuading investors in gas turbine technology and looking towards coal,<br />
nuclear and hydro power for <strong>the</strong>ir energy solutions. The use <strong>of</strong> gasification<br />
combined cycles is still however a possible lucrative market that should<br />
not be ignored.<br />
6.5.2 The US CHP Market<br />
In <strong>the</strong> US, <strong>the</strong> Assistant Secretary for Energy Efficiency and Renewable<br />
Energy has issued a CHP challenge calling for industry and government to<br />
work toge<strong>the</strong>r to double <strong>the</strong> capacity <strong>of</strong> CHP in <strong>the</strong> US by 2010. According to<br />
<strong>the</strong> US Combined Heat and Power Association (USCHPA), <strong>the</strong> current<br />
installed capacity is around 65GW, on <strong>the</strong> way from 46GW in 1998 to <strong>the</strong> goal<br />
<strong>of</strong> 92GW in 2010. However measures to support this target are limited. There<br />
are federal programmes supporting awareness raising, research and<br />
demonstration. A 10% investment tax credit for CHP was included in<br />
proposed legislation passed by both houses <strong>of</strong> Congress in <strong>the</strong> last two years,<br />
but it was not enacted into law due to disagreements over o<strong>the</strong>r provisions <strong>of</strong><br />
<strong>the</strong> law. In order to avoid revenue loss, <strong>the</strong> same provision would have<br />
stretched out CHP asset depreciation for tax purposes, so it was considered<br />
something <strong>of</strong> a neutral measure by <strong>the</strong> CHP industry. There are federal<br />
requirements that CHP operators achieving certain levels <strong>of</strong> efficiency can<br />
compel utilities to purchase <strong>the</strong>ir power at <strong>the</strong> utilities' avoided costs. This was<br />
a strong incentive for CHP in earlier times when incremental power generation<br />
costs were quite high, but motivates fewer projects now, according to <strong>the</strong><br />
USCHPA. Few states have introduced mechanisms to support CHP or<br />
equitable rules to govern <strong>the</strong> connection <strong>of</strong> CHP schemes to <strong>the</strong> grid.<br />
6.6 Chinese Market<br />
In terms <strong>of</strong> future world markets <strong>the</strong> People’s Republic <strong>of</strong> China is significant.<br />
Currently <strong>the</strong> installed power generation capacity in China is <strong>the</strong> second<br />
largest in <strong>the</strong> world, with <strong>the</strong> United States being in first position. However <strong>the</strong><br />
per capita electric power utilisation level in China is still low. China expects<br />
its economy to grow at an average rate <strong>of</strong> 7% or more per year over <strong>the</strong> next<br />
decade. <strong>Therefore</strong> if a constant ratio <strong>of</strong> primary energy to gross domestic<br />
(113)
product is assumed for this period <strong>the</strong> primary energy consumption would<br />
nearly double. Thus <strong>the</strong> electric generating capacity for <strong>the</strong> nation will be<br />
required to increase dramatically.<br />
China is a large coal production country with coal as its main source <strong>of</strong> power<br />
generation. This situation is envisaged as remaining unchanged in China for<br />
<strong>the</strong> foreseeable future. Of <strong>the</strong> ~300GWe <strong>of</strong> installed capacity at <strong>the</strong> end <strong>of</strong><br />
1999 fossil fuel capacity was almost 75%. Coal fired units account for more<br />
than 95% <strong>of</strong> <strong>the</strong> fossil fuel fired capacity. China is <strong>the</strong>refore actively pursuing<br />
Clean Coal Technologies (CCTs) as a means <strong>of</strong> meeting <strong>the</strong>ir future energy<br />
requirements with integrated gasification technology (IGCC) and supercritical<br />
boilers attractive options for <strong>the</strong> 21 st Century.<br />
China has made a decision to build a large-scale IGCC demonstration power<br />
plant and is currently conducting preparatory research for such a project.<br />
Yantai power plant in Shandong province has been proposed as <strong>the</strong> host site<br />
for this demonstration for which two 400MWe IGCC units are being<br />
considered.<br />
Assuming that <strong>the</strong> Yantai IGCC project proceeds, it could be in commercial<br />
operation by <strong>the</strong> end <strong>of</strong> year 2005. Wider deployment <strong>of</strong> IGCC could,<br />
<strong>the</strong>refore, be forecast for <strong>the</strong> period beyond 2005-2010. The potential rise <strong>of</strong><br />
IGCC within <strong>the</strong> market place over a 15-year period is predicted as resulting<br />
in a 17% share in <strong>the</strong> coal-powered generation market by <strong>the</strong> end <strong>of</strong> 2025.<br />
With <strong>the</strong> HRSG being an integral component <strong>of</strong> <strong>the</strong> IGCC plant (as outlined in<br />
Section 4.4.1) <strong>the</strong> knock on effect <strong>of</strong> HRSG sales in <strong>the</strong> Chinese market place<br />
may well be significant. However, it is apparent that <strong>the</strong> final market size will<br />
depend entirely on <strong>the</strong> success <strong>of</strong> <strong>the</strong> demonstration and <strong>the</strong> cost reductions<br />
achieved.<br />
In addition, <strong>the</strong> air blown gasification combined cycle (ABGC) has been<br />
proposed as ano<strong>the</strong>r possible contributor to China’s future energy generation.<br />
This cycle also is dependent on <strong>the</strong> use <strong>of</strong> <strong>the</strong> HRSG to enhance overall<br />
performance. Essentially <strong>the</strong> ABGC is a hybrid combined cycle power<br />
generation technology based on <strong>the</strong> partial gasification <strong>of</strong> coal [84] . The<br />
combustion <strong>of</strong> <strong>the</strong> fuel-gas is undertaken within a gas turbine. The combustion<br />
<strong>of</strong> <strong>the</strong> remaining gasifier char is carried out in a circulating fluidised bed<br />
combustor where steam is generated to drive a steam turbine. A key feature <strong>of</strong><br />
<strong>the</strong> ABGC process is its potential to achieve high cycle efficiencies with low<br />
environmental emissions.<br />
ABGC development is estimated at being around five years behind IGCC.<br />
However, its main attractiveness stems from <strong>the</strong> fact that it is well suited to<br />
poor quality high sulphur coal which is in abundance in <strong>the</strong> developing<br />
countries <strong>of</strong> China and also India.<br />
Predictions indicate that on <strong>the</strong> basis that a working plant could be established<br />
within <strong>the</strong> period 2005-2010, <strong>the</strong>n within 15 years some 10% <strong>of</strong> <strong>the</strong> market<br />
share <strong>of</strong> coal fired power generation could be supplied via ABGC.<br />
(114)
Detailed studies <strong>of</strong> CCTs within <strong>the</strong> Chinese market place have been<br />
undertaken by Mitsui Babcock [<strong>70</strong>, 84, 85] along with various Chinese research<br />
institutions. This previous work has been undertaken with <strong>the</strong> financial<br />
support <strong>of</strong> <strong>the</strong> <strong>DTI</strong>.<br />
6.6.1 Possible Non-Technical Barriers to Development <strong>of</strong> Combined Cycle<br />
Technology within China<br />
The specific market for HRSGs within China is clearly dependent on <strong>the</strong><br />
Chinese Authorities’ adoption <strong>of</strong> a positive policy on cleaner coal<br />
technologies. In general <strong>the</strong> Chinese market is seen as being hindered by seven<br />
factors listed below.<br />
6.6.2 Complex Administrative Procedures<br />
China is in <strong>the</strong> process <strong>of</strong> government and administration reform and<br />
enormous changes have been made in recent years. In 1998, <strong>the</strong> State Power<br />
Corporation (SPC) replaced <strong>the</strong> Ministry <strong>of</strong> Electric Power and <strong>the</strong><br />
government's administrative responsibility for <strong>the</strong> power industry was<br />
transferred to <strong>the</strong> State Economic and Trade Commission (SETC).<br />
Traditionally, <strong>the</strong> State Development and Planning Commission (SDPC) is <strong>the</strong><br />
top authority responsible for approving new power plant projects. The State<br />
Economic and Trade Commission (SETC) is <strong>the</strong> top authority responsible for<br />
approving renovation projects. These two commissions are <strong>the</strong> most powerful<br />
government agencies in terms <strong>of</strong> applying for and receiving approval for<br />
cleaner coal technology projects.<br />
The first step in influencing <strong>the</strong> SDPC and SETC is to inform <strong>the</strong>m <strong>of</strong> <strong>the</strong><br />
technology, <strong>the</strong> history <strong>of</strong> development, <strong>the</strong> current situation, technical and<br />
economical features, advantages and disadvantages. Providing <strong>the</strong>m with<br />
documents, inviting <strong>the</strong>m to attend a workshop, or visit research facilities or<br />
demonstration sites <strong>the</strong>refore allows this interaction to take place. Secondly, if<br />
a project is being prepared, a feasibility study report with favourable financing<br />
arrangements such as a s<strong>of</strong>t loan or a grant from international organisations<br />
will certainly have a positive influence on <strong>the</strong> approval process.<br />
6.6.3 Low Institutional Capability<br />
The lack <strong>of</strong> collaboration between design institutes, research institutes and<br />
manufacturers acts as a key barrier to international technology transfer. Most<br />
R&D for cleaner coal technologies requires a multidisciplinary approach. In<br />
addition, China’s state-owned manufacturing enterprises have not developed<br />
commercial or innovative skills and <strong>the</strong>re is a lack <strong>of</strong> market pressure on<br />
Chinese enterprises. With <strong>the</strong> deepening <strong>of</strong> economic reform and system<br />
restructuring, however, all state-owned enterprises and research institutes will<br />
accelerate <strong>the</strong> process <strong>of</strong> upgrading management and technology in order to<br />
improve competitiveness.<br />
(115)
6.6.4 Environmental Emission Controls<br />
With China being a developing country, <strong>the</strong> standards relating to<br />
environmental protection are still much lower compared to those in fully<br />
industrialised countries. The regulations on emissions from <strong>the</strong>rmal power<br />
plants, for example, are not so stringent. This situation does not put enough<br />
pressure on industry to create a demand for cleaner coal technology hardware<br />
and services. In addition, <strong>the</strong> implementation <strong>of</strong> <strong>the</strong>se standards is sometimes,<br />
and in some places, poor and inconsistent. The lack <strong>of</strong> enforcement and<br />
monitoring <strong>the</strong>refore also has a negative influence on environmental<br />
investment. Environmental protection, however, is one <strong>of</strong> China’s basic<br />
national policies for sustainable development. With <strong>the</strong> rapid economic<br />
development and improvement <strong>of</strong> living conditions environmental policy is<br />
being given a higher priority and becoming more stringent.<br />
6.6.5 Financial Issues<br />
Lack <strong>of</strong> finance is <strong>of</strong>ten an important barrier to cleaner coal technology<br />
transfer. The following measures will enhance <strong>the</strong> possibilities for technology<br />
transfer:<br />
(i) Both government and international organisations will devise more<br />
favourable policies and <strong>of</strong>fer concessional finance for <strong>the</strong> introduction <strong>of</strong><br />
advanced cleaner coal technologies in <strong>the</strong> form <strong>of</strong> s<strong>of</strong>t loans, capital subsidies<br />
or grants.<br />
(ii) Cleaner coal projects will become economic if <strong>the</strong> issue <strong>of</strong> pollution<br />
costs is addressed. This issue is linked to <strong>the</strong> reform <strong>of</strong> <strong>the</strong> pollution levy<br />
system.<br />
(iii) The cost <strong>of</strong> cleaner coal equipment manufactured in China is much<br />
lower than <strong>the</strong> cost <strong>of</strong> imported equipment. Hence, <strong>the</strong>re is a strong economic<br />
and financial incentive to maximise <strong>the</strong> local manufacture <strong>of</strong> equipment. This<br />
can only be realised with technology transfer.<br />
6.6.6 Maturity <strong>of</strong> <strong>the</strong> Technology<br />
As end users, power companies will only employ mature technologies. It is<br />
generally deemed to be crucial that at least two reference plants <strong>of</strong> <strong>the</strong> same or<br />
comparable size should be operating. For newly developed technologies a<br />
demonstration project <strong>of</strong> relevant size and parameters is important.<br />
6.6.7 Issue <strong>of</strong> Intellectual Property<br />
Gradually, <strong>the</strong> move to commercialise state-owned industries is streng<strong>the</strong>ning<br />
respect for intellectual property rights. Fur<strong>the</strong>rmore, <strong>the</strong> move to a competitive<br />
market will eventually bring about a situation in which companies in China<br />
will have less incentive to share information with each o<strong>the</strong>r.<br />
6.6.8 Long-Term Collaboration<br />
Joint ventures between Chinese and foreign firms or involving technology<br />
licensing agreements can potentially facilitate <strong>the</strong> transfer <strong>of</strong> <strong>the</strong> wider<br />
(116)
knowledge, expertise and experience necessary for managing technological<br />
change. Joint ventures in particular have one important feature which can help<br />
collaborative relationships in China to be successful: a relationship that gives<br />
both sides a stake in <strong>the</strong> future success <strong>of</strong> <strong>the</strong> product or service concerned,<br />
and allows <strong>the</strong> build up <strong>of</strong> trust.<br />
6.7 Conclusions<br />
• Whilst <strong>the</strong> utility scale HRSG market has been healthy in recent years,<br />
<strong>the</strong>re is a predicted sharp downturn in <strong>the</strong> HRSG market in <strong>the</strong> shortmedium<br />
term due to plant over capacity. The situation is not expected to<br />
pick up again until around 2007-2011. Key future HRSG markets are seen<br />
as <strong>the</strong> USA and China (via IGCC). Non technical barriers in <strong>the</strong>se two<br />
markets include <strong>the</strong> price/availability <strong>of</strong> gas in <strong>the</strong> USA and<br />
administrative/financial issues in China.<br />
• For industrial scale HRSGs, <strong>the</strong> European market is depressed due to<br />
falling electricity prices and rising gas prices. However potential markets<br />
include Russia, Central and Eastern European (CEE) countries, Turkey<br />
and <strong>the</strong> Middle East. In <strong>the</strong> USA, despite problems on <strong>the</strong> utility scale,<br />
<strong>the</strong>re are still opportunities for development <strong>of</strong> CHP schemes on industrial<br />
sites, largely driven by security <strong>of</strong> price and supply issues in <strong>the</strong> volatile<br />
deregulated electricity market.<br />
• The current surplus <strong>of</strong> generating capacity in <strong>the</strong> UK and fluctuations in<br />
<strong>the</strong> price <strong>of</strong> natural gas have led to a low requirement to build large scale<br />
power generation plant within <strong>the</strong> UK. The only plus side is that with <strong>the</strong><br />
effects <strong>of</strong> flexible operation becoming more apparent, plant performance<br />
upgrade opportunities are present.<br />
• The combination <strong>of</strong> NETA and a high natural gas price has dramatically<br />
reduced <strong>the</strong> UK market for CHP and <strong>the</strong> climate change levy is not seen as<br />
being an adequate incentive to invest in new HRSGs / CHP schemes.<br />
Enhanced government support for CHP is required if <strong>the</strong> target <strong>of</strong> 10 GWe<br />
by 2010 is to be met.<br />
(117)
7 UK ACTIVITIES<br />
This chapter reviews <strong>the</strong> prospects <strong>of</strong> UK manufacturers in <strong>the</strong> global HRSG<br />
market, and <strong>the</strong>ir capabilities. Areas <strong>of</strong> current research, development and<br />
demonstration (RD&D) which are being undertaken in <strong>the</strong> UK are indicated<br />
alongside recommendations <strong>of</strong> areas <strong>of</strong> significant future focus.<br />
7.1 Prospects <strong>of</strong> UK Suppliers and Manufacturers in <strong>the</strong> Global Market<br />
Large, new build HRSG manufacture, as with many o<strong>the</strong>r heavy engineering<br />
manufacturing business within <strong>the</strong> UK, is finding it increasingly difficult to<br />
compete with <strong>the</strong> low costs associated with both European competition based<br />
on <strong>the</strong> continent (e.g. in Italy and Spain) and <strong>the</strong> significantly reduced outlay<br />
incurred by manufacturing in East Asia.<br />
With more modular HRSG designs becoming commonplace, <strong>the</strong> future <strong>of</strong> UK<br />
HRSG companies in <strong>the</strong> new-build market lies in <strong>the</strong> ability to sell, supply and<br />
assemble HRSGs, based on <strong>the</strong>ir own designs and advanced technologies,<br />
albeit that <strong>the</strong> standard components may not necessarily have been<br />
manufactured inside <strong>the</strong> country.<br />
Within such an environment, licensing agreements and collaborative<br />
partnerships are <strong>the</strong>refore deemed essential in order for companies to maintain<br />
<strong>the</strong> ability to compete in <strong>the</strong> global market.<br />
In order to form such alliances, UK companies must be in a position to <strong>of</strong>fer<br />
something in return. Under such conditions <strong>the</strong> requirement to be continually<br />
developing new technologies becomes vital. <strong>Therefore</strong> to guarantee future<br />
long-term prospects for UK suppliers and manufacturers in <strong>the</strong> global market,<br />
its knowledge and development <strong>of</strong> leading edge technologies must be<br />
maintained.<br />
7.2 UK Capabilities in HRSG Design, Manufacture and Supply –<br />
Utility-Scale<br />
In terms <strong>of</strong> UK based large utility HRSG manufacture and design, Mitsui<br />
Babcock has a significant presence within <strong>the</strong> UK.<br />
Mitsui Babcock is a major energy engineering company incorporated in <strong>the</strong><br />
UK and since 1995, a wholly owned subsidiary <strong>of</strong> Mitsui Engineering &<br />
Shipbuilding <strong>of</strong> Japan. The company is a technology leader in large fossil fuel<br />
steam generating plant, and specialises in <strong>the</strong> design, engineering,<br />
manufacture, construction, commissioning and after sales servicing <strong>of</strong> high<br />
efficiency, high availability coal, oil, and gas fired boilers for <strong>the</strong> power<br />
stations <strong>of</strong> electricity generating companies world wide. The company is also a<br />
major manufacturer and supplier <strong>of</strong> heat recovery steam generating plant,<br />
industrial fluidised bed and o<strong>the</strong>r clean burn coal fired boilers, coal milling<br />
plant, flue gas desulphurisation plant and low NOx technologies.<br />
(118)
Up until <strong>the</strong> mid 1990’s and operating at <strong>the</strong> time as Babcock Energy, Mitsui<br />
Babcock was one <strong>of</strong> <strong>the</strong> worlds foremost suppliers <strong>of</strong> HRSGs. In 1993 Mitsui<br />
Babcock were nominated as <strong>the</strong> “worlds leading supplier <strong>of</strong> HRSGs” and were<br />
winners <strong>of</strong> <strong>the</strong> coveted Power Engineering International “project <strong>of</strong> <strong>the</strong> year<br />
award”. To date <strong>the</strong> company has won contracts in some 23 different<br />
countries. However by <strong>the</strong> mid 1990s <strong>the</strong> HRSG market suffered a severe<br />
downturn with limited opportunities and reduced margins. To compound this,<br />
<strong>the</strong> market was migrating from assisted circulation to natural circulation<br />
designs and <strong>the</strong> company’s specific technology <strong>of</strong>fering became less<br />
competitive. However with a recent upturn in <strong>the</strong> fortunes <strong>of</strong> <strong>the</strong> HRSG<br />
market particularly in America, Mitsui Babcock have enhanced <strong>the</strong>ir product<br />
range by concluding a licensing agreement with Babcock Hitachi KK for<br />
natural circulation designs. Significant orders for utility plant HRSG supply<br />
such as <strong>the</strong> natural circulating HRSG for Naco Nogales power plant in Mexico<br />
and <strong>the</strong> assisted circulated HRSG employed at Black<strong>point</strong> power station in<br />
China have been completed.<br />
Mitsui Babcock employs approximately 3000 people in its various operations<br />
in <strong>the</strong> UK and abroad. Its headquarters are at Crawley in <strong>the</strong> UK but operates<br />
locally with regional operations elsewhere in <strong>the</strong> UK and around <strong>the</strong> world.<br />
The company’s strengths lie in its depth <strong>of</strong> engineering capabilities, its<br />
technology base, its extensive manufacturing facilities, its considerable<br />
experience in site erection, commissioning and servicing <strong>of</strong> major power plant<br />
in countries across <strong>the</strong> world and its ability and experience in managing very<br />
large multi-disciplinary projects. The company’s combination <strong>of</strong><br />
technological, financial and skill resources enable it to deliver projects in a<br />
range from £10 million to £400 million, anywhere in <strong>the</strong> world.<br />
Thermal Engineering International Ltd – Greens is <strong>the</strong> largest independent<br />
manufacturer <strong>of</strong> utility HRSG’s in <strong>the</strong> UK. Originally known as E Green &<br />
Son <strong>the</strong> Wakefield based company has amassed over 150 years <strong>of</strong> experience<br />
in <strong>the</strong> field <strong>of</strong> heat recovery since its founder Edward Green invented and<br />
patented <strong>the</strong> world’s first economiser which he patented in 1845.<br />
TEI Greens has manufactured Utility HRSG’s for most <strong>of</strong> <strong>the</strong> world’s leading<br />
boiler designers/makers as many no longer support <strong>the</strong>ir own manufacturing<br />
facilities. TEI Greens has been successful in manufacturing HRSG’s for<br />
domestic and export projects and has a wide experience <strong>of</strong> different designs<br />
including vertical and horizontal gas types and once through designs.<br />
Currently, around 40% <strong>of</strong> all <strong>the</strong> UK’s utility HRSG’s have been<br />
manufactured by TEI Greens.<br />
TEI Greens are holders <strong>of</strong> <strong>the</strong> ASME S & U stamps and have a large facility<br />
<strong>of</strong> over 100,000m 2 with extensive workshops. It has 3 x High Frequency<br />
Finning machines in its Wakefield Factory (10 worldwide) for <strong>the</strong><br />
manufacture <strong>of</strong> high frequency welded helical fin tubes as used in modern<br />
HRSG’s. The facility is capable <strong>of</strong> producing over 120,000 tubes and 10 major<br />
HRSG’s per annum.<br />
(119)
There is also a number <strong>of</strong> major utility-scale HRSG turnkey contractors<br />
operating within <strong>the</strong> UK, although <strong>the</strong>ir headquarters and manufacturing<br />
facilities are generally based overseas or manufacture is sub-contracted.<br />
Alstom Power, Foster Wheeler Energy Ltd, Mott Macdonald, Nooter/Eriksen-<br />
CCT Ltd and Siemens KWU all fall within this category.<br />
7.3 UK Capabilities in HRSG Design, Manufacture and Supply –<br />
Industrial-Scale<br />
Wellman Robey and BIB Cochran both manufacture and supply smoke tube<br />
(shell boiler) type HRSGs. Wellman Robey is owned by <strong>the</strong> Wellman Group<br />
<strong>of</strong> <strong>the</strong> UK and BIB Cochran is owned by <strong>the</strong> Mechmar Corporation <strong>of</strong><br />
Malaysia. Wellman Robey supply units in <strong>the</strong> 5-10MW range for use in<br />
exhaust heat recovery behind GTs; gas and diesel engines; incinerators, kilns<br />
and furnaces; and process integrated units in petrochemical, o<strong>the</strong>r chemical<br />
and iron and steel industries. It has its own manufacturing capabilities at its<br />
factory in Oldbury, and also <strong>of</strong>fers contract manufacturing services. Besides<br />
HRSGs, Wellman Robey supplies a range <strong>of</strong> fired package boilers and <strong>of</strong>fers<br />
after sales support and maintenance. BIB Cochran similarly supplies units for<br />
a range <strong>of</strong> exhaust heat recovery and process integrated applications. It<br />
manufactures its products at its factory in Dumfries and Galloway and its<br />
product range also includes a range <strong>of</strong> fired package boilers. It has<br />
representation in many counties in eastern and western Europe, <strong>the</strong> Middle<br />
East, south east Asia, India and <strong>the</strong> Americas. It also provides various after<br />
sales services.<br />
M E Engineering is owned by <strong>the</strong> Thermax group <strong>of</strong> India. It only supplies<br />
bespoke units ra<strong>the</strong>r than package units. It has a range <strong>of</strong> water tube designs<br />
for exhaust heat recovery and process integrated applications. In GT exhaust<br />
heat applications, <strong>the</strong> range <strong>of</strong> GTs served is from 5MWe to around <strong>70</strong>MWe.<br />
Besides heat recovery systems <strong>the</strong> company can supply boilers for a wide<br />
range <strong>of</strong> solid, liquid and gaseous fuels. The company does not have its own<br />
manufacturing facilities, but uses ei<strong>the</strong>r <strong>the</strong> factory <strong>of</strong> its parent company in<br />
India or sub-contract manufacture.<br />
Industrial HRSG’s are designed and manufactured in house by TEI Greens.<br />
These may be <strong>of</strong> a water tube or smoke tube design and may incorporate<br />
supplementary or auxiliary firing where required.<br />
The UK arm <strong>of</strong> Nooter/Eriksen also supplies industrial HRSGs although its<br />
design capability is based in <strong>the</strong> US and manufacture is sub-contracted.<br />
Details <strong>of</strong> each <strong>of</strong> <strong>the</strong> companies described above are summarised in Table 10<br />
below.<br />
(120)
Company Ultimate<br />
Parent<br />
Company<br />
BIB Cochran Mechmar<br />
Corporation<br />
Malaysia<br />
Wellman<br />
Robey<br />
M E<br />
Engineering<br />
Wellman<br />
Group, UK<br />
Thermax<br />
Group, India<br />
HRSG<br />
Business<br />
Annual<br />
Turnover<br />
(range)<br />
HRSG Designs Scale Applications Capabilities O<strong>the</strong>r Products<br />
- Smoke tube,<br />
Package,<br />
Optional<br />
supplementary<br />
firing<br />
$1-$5M Smoke tube,<br />
Package,<br />
Optional<br />
supplementary<br />
firing<br />
$0.5-$1.0M Smoke tube,<br />
Water tube,<br />
Optional<br />
supplementary<br />
firing<br />
Up to 35 tph steam at<br />
up to 35 bar g<br />
5-10 MW or up to<br />
20MW if<br />
supplementary fired.<br />
Up to 40 tph steam at<br />
up to 35 bar g and<br />
360°C, saturated or<br />
superheated<br />
Up to 55 tph steam at<br />
up to 60 bar g and<br />
450°C, saturated or<br />
superheated<br />
(121)<br />
CHP, GT exhaust,<br />
reciprocating engine<br />
exhaust, incinerator<br />
flue gas,<br />
petrochemical, o<strong>the</strong>r<br />
process industry<br />
CHP, GT exhaust,<br />
reciprocating engine<br />
exhaust, incinerator<br />
flue gas,<br />
petrochemical, o<strong>the</strong>r<br />
process industry, iron<br />
& steel<br />
CHP, CHP & cooling,<br />
GT exhaust,<br />
reciprocating engine<br />
exhaust, incinerator<br />
flue gas (clinical,<br />
municipal),<br />
petrochemical, o<strong>the</strong>r<br />
process industry,<br />
biomass IGCC, iron<br />
& steel, <strong>of</strong>fshore oil<br />
production<br />
Site surveys,<br />
Design,<br />
Manufacture in house,<br />
Installation,<br />
Commissioning,<br />
Training,<br />
Service,<br />
Repair and maintenance<br />
Spares supply<br />
Design,<br />
Manufacture in house,<br />
Commissioning,<br />
Training,<br />
Operation,<br />
Service,<br />
Repair and maintenance,<br />
Spares supply<br />
Design,<br />
Contract manufacture local<br />
to project or at parent<br />
company factory in India,<br />
Installation,<br />
Commissioning,<br />
Training,<br />
Repair and maintenance<br />
Gas burners,<br />
Package units:<br />
‘Thermax’, ‘Clansman’ and<br />
‘Calpac’ hot water boilers<br />
‘Wee Chieftan’, ‘Thermax’<br />
single and double furnace,<br />
‘Borderer’ and ‘Coalmaster’<br />
steam boilers<br />
Pressure vessels,<br />
Sub-contract manufacture,<br />
Package units:<br />
‘Robey’ low NO x boilers,<br />
‘STONE’ steam generators,<br />
‘Ygnis’ hot water and steam<br />
boilers<br />
Biomass & fossil solid fuel<br />
boilers (travelling , dumping<br />
and pinhole grates, fluidised<br />
beds) up to 100 tph evaporation,<br />
Liquid / gas fired single / bi<br />
drum water tube boilers up to<br />
300 tph evaporation,<br />
Fired once through coil boilers<br />
up to 50 tph evaporation and<br />
200 bar g<br />
Re-tubing, air-preheaters,<br />
economisers,<br />
Heat recovery to water,
TEI Greens Thermal<br />
Engineering<br />
International<br />
Nooter/Eriksen<br />
– CCT Ltd<br />
CIC Group<br />
Inc.<br />
$1-10M Smoke tube,<br />
Water tube,<br />
Optional<br />
supplementary<br />
firing or auxiliary<br />
firing<br />
- Smoke tube,<br />
water tube,<br />
optional<br />
supplementary or<br />
auxiliary firing.<br />
Various from industrial<br />
to utility scale.<br />
Various from industrial<br />
to utility scale.<br />
(122)<br />
Waste heat recovery<br />
from boiler and<br />
process flue gas<br />
streams in power<br />
generation (CHP &<br />
CCGT), refining,<br />
chemical, process and<br />
general industries.<br />
Power generation<br />
(CHP & CCGT),<br />
designs for waste<br />
incineration and<br />
process industry<br />
applications.<br />
Inclusion <strong>of</strong> catalysts<br />
possible.<br />
Table 10: Capabilities <strong>of</strong> UK industrial HRSG suppliers.<br />
Design,<br />
Manufacture in house,<br />
Unit build,<br />
Erection,<br />
Commissioning<br />
Design (overseas),<br />
Manufacture (subcontracted),<br />
Unit build, erection,<br />
commissioning.<br />
water/glycol, <strong>the</strong>rmal oil,<br />
Absorption cooling<br />
Helical finned tube manufacture<br />
in both solid and serrated fin<br />
pr<strong>of</strong>iles.<br />
Utility-scale HRSG<br />
manufacture in house, unit<br />
build, erection and<br />
commissioning (but not design)<br />
Optimised designs for cycling<br />
and constructability.<br />
Enhanced Oil Recovery<br />
OTSG’s for 80% quality steam.