Generution

0 pt io ins for m id - merit power generation in the UIK electricity market The article examines the future importance and growth of the mid-merit generation market, looks at the effect of environmental constraints on mid-merit plant, considers whether existing power stations can be operated efficiently at mid-merit and examines the cost and benefit implications of designing new power stations with the technology to mn moregexibly.

by I m P m Burdlon

n the April 1996 Monopolies & Mergers Commission (MMC) report on the merger between PowerGen and Midlands Electricity,' PowerGen (PG) classified its

generation as either baseload or non-baseload according to the pattern of the operation of the plant concerned. Plant which was kept at full load even in periods of lowest demand was said to generate baseload output; other plant was viewed as generating non-baseload output.

In the same report, National Power (NP) was quoted as saying that, in its view, the non- baseload part of the market was not distinct from the baseload part of the market. There was one merit order of generating plant which was called on to run on the basis of lowest bid price first,. highest price last. !Seasonal and intra-day variations in demand result in the lowest cost plant running all or most of the time. Plant which could be considered baseload could change both from day to day as a result of different bidding (and hence plant rising and falling in the merit order) and over time as more efficient, lower-cost, plant became available (thus pushing plant considered baseload

baseload as the average of the lowest daily demands in the year.

Taking the definition. of baseload plant as that which is used to supply continuous

towards or into mid-merit). NP further defined

demand even at its lowest level, the remaining plant which operates in the non-baseload part of the market can be divided into two groups: mid-merit (the lower end of this part of the market) and peak. Fig. 1 shows how this generation is deployed by means of a system load duration curve which indicates the number of hours in any period (in this case a year) over which a particular level of load occurred. The curve is derived from the daily demand curves, examples of which are illustrated in Fig. 2 for typical summer days and typical winter days. The importance of mid- merit plant in the generation market is that it is the bids of such plant which set the Pool price for a large proportion of the time, since it is the most expensive, or marginal, generator required to meet estimated demand for that period which determines Pool price.

From the foregoing, it can be seen that there is no generally agreed definition as to what constitutes non-baseload or mid-merit plant. the Office of Electricity Regulation (OFFER) refers to 'flexible capacity' as all capacity on the system excluding nuclear plant, early

or-pay gas contracts and the interconnector with France. The MMC chose not to accept OFFER'S definition of flexible capacity as a proxy for non-baseload plant. The National

independent power projects (IPPs) with take-

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1 System load duration curve January 1997 to December 1997

50 b oiland T

r o o o o o o o o o o o o o o o o o o o o o o o o o 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

" * * L D ( D W i . " ~ ~ ~ ~ 7 5 8 ~ ~ ~ $ ~ ~ ~ " ( ~ " o " b ' " "

r r r r r r r r r r -

cumulative number of half hours

Grid Company (NGC) meanwhile assumed that the non-baseload part of the market were those stations which had a load factor of less than 70%.

As a consequence of all this, there are large differences in the size and shares of the non- baseload part of the market as estimated by NP, PG and NGC, varying between 61.4 TWh and 104.4 TWh in total for 2000/2001. The estimates of the total market for electricity in that period are much closer, lying between 293

. 2 Demandand TWh and 296 TWh. Thus the mid-merit portion of the market lies somewhere between 20 and 33% of the total.

generation CGW) England and Wales

Examination of the future importance and growth of the mid-merit generation market It would appear from information contained within NGC's seven-year statement2 that baseload generation plant comprises, in order of price bid to the Pool, nuclear, combined- cycle gas turbine (CCGT), the imports from France and Scotland and the large coal stations. This plant is that which runs throughout the whole day This, of course, ignores the contribution made by renewables and combined heat and power (CHP) which, because it tends to be embedded in the Regional Electricity Companies' (RECs) distribution systems, effectively depresses the load which NGC meets at the grid supply points.

Additional demand, i.e. 'mid-merit' load and peak load is met from the coal stations, oil stations, pumped storage and open cycle gas turbines.

Information submitted to the MMC in 1996 by PG suggested that about 38 GW of plant, including 17 GW of CCGTs, would be seeking about 21 GW of baseload generation by year 2000. 'Mid-merit' load would amount to about 20 GW, given that the system load duration curve below the peak indicates a sub-peak load of about 40-41 GW.

PG took the view that nuclear would provide half the baseload capacity with the remaining half provided by CCGTs on take-or-pay gas contracts. NP considered that CCGT plant not linked to long-term contracts with the RECs

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would increasingly operate in the non-baseload part of the market. Thus it was suggested by the two big generators tha.t the coal-fired plants with flue gas desulphurisation (FGD), the interconnectors and about 6.4 GW of CCGT will be displaced from baseload into the mid- merit section of the market in the year 2000, as shown in Table 1.

According to NGC‘s seven-year statement, however, expected regi:stered capacity in year 2000 totals 78.466 GW made up as shown in Table 2. Of the capacity listed in Table 2, some 12.565 GW of CCGT p1,ant is not yet in service, 1.948 GW of the oil-fired plant was the orimulsion project at Pembroke (now abandoned) and 1 GW of interconnector capacity depends on the completion of the second Yorkshire line to allow increased exports from Scotland. It further assumes that oil-fired plant, open-cycle gas turbines (OCGTs), duel-fuelled plant and hydro operate to meet peak demand only.

According to this information, therefore, and accepting that PGs view on the baseload generation mix holds good, it would seem that about 47 GW of plant, as listed in Table 3 , could be potentially competing for about 17-20 GW of ‘mid-merit’ demand in year 2000.

This hypothetical caipacity is likely to be reduced somewhat by further closure of coal stations (possibly amounting to 12.2 GW of NP and PG capacity because of environmental constraints), the possible refusal of consent to construct the second Yorkshire line (1 GW) and the abandonment of proposals to burn

Table 1 baseload market in year 2000

PowerGen estimates of competition for

tormer baseload

plant owncr/type total baseload dnplaced to

1x1 id -m e r 1 t

nuclear 10-5 10.5 PG (CCGT) 3.1 NP (CCGT) 3.4 NP (Staythorpe) M} 10.5 6 4 existing IPPs new IPPs 1.7 interconnectors 4.2 4.2 PG (coal FGD) 2.0 2.0 NP (coal FGD) 4.0 4.0

16.6 ~ ~ ~

- totals 37.6 21.0 - -

orimulsion at Pembroke (1.95 GW). Thus the actual competitive capacity for the mid-merit market may decrease to 32 GW.

The figure will effectively be increased by 3- 4 GW if Government targets for CHP (which require a further 1.5-2.0 GW of capacity by the year 2000) and an increase in renewables, which requires a similar increase if 10% of electricity demand is to be produced by renewable sources in the year 2010, are attained.

Taking these factors into account, it is possible that 35-36 GW of plant, as shown in Table 4, could be competing for mid-merit load in year 2000. The possible competition for the

Table 2 Total generating capacity anticipated by NGC in year 2000

total regstered capacity not yet in

plant type GW service baseload mid-merit peak

nuclear small coal medium coal large coal CCGT oil OCGT Dual fuel hydro inter-connectors

10.529 0.701 4.283

19.121 2;‘,420 5142 1.094 3.900 ;!.088 ‘t.188

10 529 0 701 4 283

19 121 12 565 10 471 4 384 1948 3 194

1 094 3 900 2 088

1 000 3 188

15.513 21.000 31.677 10,276

totals 78.466 78,466 --

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Table 3 demand in year 2000

Hypothetical competition for mid-merit

coal CCGT interconnector oil (orimulsion)

24.1 16.8 4.2 2.0

~

total 47.2

mid-merit market will include a substantial element of CCGT and will also include imports via the interconnectors and some coal-fired plant, although one-third of that capacity may have been converted to gas firing.

A further factor bearing on the possible coal- fired capacity in year 2000 is that the existing OCGT plant used to meet system peak loads is ageing and rapidly being replaced by new OCGT plant with efficiencies of 42-43% (compared with 24% for old OCGT and 35-38% for coal-fired plant). About 5GW of such plant is under consideration at the present time, spread throughout the whole of England and Wales. It is embedded generation of less than 50 MW capacity and, therefore, not centrally dispatched. As its efficiency is higher than that for coal-fired plant, and as it is more flexible, it could replace a large part of the coal-fired capacity indicated in Table 4.

The effects of CHP and renewables on the utilisation of conventional generation capacity will be significant.

The way mid-merit plant is likely to be affected by environmental constraints Mid-merit generating plant, like all other major thermal power plant, is required to meet

Table 4 merit market in year 2000

Possible generation competing for mid-

coaVgas CCGT interconnectors

11.9 16-9 3.2

sub-total 32.0 ~

add:

renewables" effect of increasing CHP and 3-4

total 35-36

* assuming such plant operates on a 'must run' basis and displaces an equivalent amount of baseload plant into mid-merit operation.

Environment Agency requirements as set out in its Integrated Pollution Control (IPC) Authorisations.

By definition such plant is required to vary its output to match the available demand, i.e. it has to be capable of flexible operation. This may mean that it has to operate for periods at part- load or run intermittently, i.e. the so-called two- shifting operating regime.

The stop-start or modulated operation of combustion plant, whether as coal or oil in steam-raising boiler plant or as gas in a gas turbine, has implications for emissions, efficiency, plant life and operational costs, of which emissions and efficiency are of concern to the Environment Agency in the UK.

Dealing with steam-raising boiler plant first, much work was undertaken by the CEGB in the 1970s on two-shift operation of 500 MW oil- fired units at Fawley and Pembr~ke .~ .~ These trials highlighted the difficulties in maintaining satisfactory combustion and steam temperature control during two-shift and variable load operation for system frequency regulation purposes.

Rapid developments in microprocessor technology had resulted in large reductions in digital computing costs, and distributed digital control (DDC) techniques were adopted at Pembroke in 1975 which led to satisfactory control of temperature, combustion, load, burner management and feedwater flow. With such a system, combustion quality is continuously monitored via flue gas analysis and smoke density. The improvements in instrumentation and control of large boiler/ turbine generator units were subsequently applied to pulverised-fuel (PF) coal stations in the UK which were also to be operated on a two- shift basis.

The experiences of the two-shifting trials demonstrated essential prerequisites for routine two-shifting as being sound operator training, comprehensive operator instructions and a high standard of reliability on the part of instrumentation, controls and sequence control equipment.

The retention of as high a metal temperature as possible in the turbine metal and the rapid establishment of suitable steam temperature on start-up are critical features of the procedures.

The capability of large thermal stations to run intermittently on the UK system allowed higher capacity factors to be achieved on high merit plant and resulted in significant cost savings

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due to increased overall efficiency of operation of the coal stations as a whole.

Flexible operation of gas turbine plant operating in combined-cycle mode has significant operational implications for efficiency and degradation as well as emissions. Such operation may involve increased starting and stopping or, alternatively, frequent operation at part load. Where NOx control is achieved by steam injection into the combu:jtors, difficulties may be experienced (where the steam supply is obtained from the waste heat recovery steam generator rather than from an. auxiliary boiler) in achieving the limits required under the IPC Au thorisations.

The majority of gas turbines have dry low- NOx burners. These maintain low emission levels down to about 60% load. Below this, NOx emissions rise sharply and, consequently, operation is not permitted under the IPC Authorisation.

An additional environmental impact of flexible operation relates to the need for additional boiler blowdown to control boiler water chemistry on CCGT plant. This gives rise to additional demand for treated water which, in turn, increases the amount of effluent from the water treatment plant. This effluent, together with the effluent from blowdown, is normally discharged, after dilution, into a river (where direct cooling is employed) or the 10c;d sewers. The greater concentrations of these effluents may exceed Environment Agency limits unless special measures are taken.

Low-load operation of a gas turbine below about 60-70% results in much reduced efficiency and, therefore, an increase in the release of COz andl other products of combustion per unit of electricity generated. Increased degradation of performance because of frequent stop-start operation is also likely as is a worsening of the operating factor due to the increased losses incurred during start-up and shut-down. In addition, as load is reduced, stable operation of a gas. turbine (particularly in combined-cycle mode) is generally more

difficult to achieve, partly due to combustion characteristics and partly because of ‘coarseness’ in the control systems, and this, generally, has an adverse effect on environmental emissions.

An interesting operational aspect of flexible plant is that CEGB succeeded in bringing four 500 MW oil-fired sets into service between 0500 and 0900 hours on a regular basis at Fawley and Pembroke in the early 1980s achieving a rate of loading of 13 MW/minute per set over the last two hours of that period. Economical peak-lopping runs down to two hours were obtainable on an individual 500 MW unit.4

This is to be compared with the loading rate of a typical 2 + 1 CCGT installation using GE 9FA machines (720 MW declared net capacity) which is about 6 MW/min under hot start conditions. There are, therefore, important differences in degrees of flexibility between different types of plant.

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Conversion of existing power stations to operate efficiently at mid-merit This section deals with the technical issues which affect the ability of plant to operate on a flexible or two-shift basis to follow the available load. These issues relate, in the main, to the levels of thermally-induced cyclic stresses which affect combustion and steam-raising plant operating at high and cyclical temperatures but also relate to the degree to which control systems are capable of maintaining satis€actory emission control and optimum rate of load rejection and load acceptance to meet system requirements5-'

Historically in the UK, it was the coal-fired stations equipped with 60 MW and 120 MW sets which bore the brunt of two-shifting and peak-lopping duties. Developments in the 1970s referred to earlier, however, allowed the larger oil-fired sets to be shut down overnight so as to avoid burning expensive oil.

The specifications for most of the existing large oil and coal-fired thermal plant on the UK system required a capability for two-shifting operation from the outset, calling for rapid offloading and reloading facilities with the ability to reach full load in 20 minutes from synchronisation. The development programme of 25 years ago was undertaken to confirm the basic integrity of the designs and to identify possible problems in achieving flexibility and reliability as well as to establish best operational practice.

Problem areas associated with the turbines were largely associated with the effects of thermal changes on large, high-temperature, components such as HP and IP turbine cylinders and turbine valve-gear steam chests. Temperature measurements established temperature gradients in these components and finite-element analysis was used to obtain elastic thermal stress information. A reduction in loading rate on the 500 MW machines from 25 MW/minute to 10 MW/minute reduced the induced strain to acceptable levels and gave predicted crack-free lives in excess of 7000 cycles.

Boiler investigations concentrated on two possible damage mechanisms: creep life usage and thermal fatigue. The former was satisfactorily dealt with by the introduction of permanent computer-based creep life monitoring schemes which continuously record boiler metal temperatures whereby damage and defect propagation can be assessed with the use of algorithms which relate

temperature differentials to stredstrain levels. Trials demonstrated the importance of effective combustion control in limiting temperature excursions. Thermal fatigue problems were largely overcome by improved final steam temperature control schemes.

Problems with the generator units were resolved by modifications to stator windings, improvements in moisture control of the hydrogen cooling gas and the use of improved insulating materials on the rotors.

Control systems on the combustion and steam-raising plant on the large thermal stations prior to 1975 were based on conventional analogue controllers with fixed settings. It was evident during commissioning of both Fawley and Pembroke in 1969-73 that the control was barely adequate for steady load and inadequate for the rapid variation that would be met during flexible operation. DDC systems were introduced and are now the norm on all large thermal stations. One benefit has been the reduction in the statistical spread of superheater outlet temperature which has allowed an increase in mean running temperature of up to 10°C while still maintaining the same rate of creep life usage for the boiler. Such an improvement resulted in a fuel saving of about L200000 pa (1983). Precise temperature control and monitoring allowed the sets to be loaded and unloaded at the maximum possible rate, which can be as high as 15 MW/min.

The results of this development programme were subsequently applied to other large coal- fired stations in the 1980s with similar results.

The earliest of the CCGT stations, i.e. those commissioned between 1990 and the mid 1990s, are those which are likely to be edged out of the baseload market into mid-merit operation as more efficient gas-fired plant comes into service and their take or pay gas contracts come to an end. They were not intentionally designed for flexible operation and require modification to make them suitable for that duty A key issue will be gas turbine blade life under cyclic temperature and stress conditions.

While many of the problems that have to be resolved are related to thermal stress and fatigue, just as for the large oil and coal stations, there are cost implications also arising from additional maintenance requirements and a reduction in thermal efficiency of up to 4%.

A thermal effect which arises on a CCGT

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plant, but not with a large coal or oil-fired station, relates to the rapid condensation of steam in the HP superheater and reheater tube banks in the heat-recovery steam generator because of the sudden loss of heat from the gas turbine exhaust when firing is stopped on shutdown. Drainage for this condensate must therefore be provided.

Significant capital expenditure will be required in the early stations which may amount to L l million for a typical 660 MW CCGT station which was originally designed for 20 cold starts per year. This level of expenditure is, of course, relatively small in relation to a station which cost originally, perhaps, L250 million-f300 million.

The conclusions to be drawn from the above, therefore, are th,at the large coal and oil stations are already capable of operating flexibly and, indeed, have done so for ten years or more. The duties that these stations are now called on to undertake, however, go beyond the original two-shifting mode with the requirement to operate in the Pool on, effectively, a multi-shifting basis. Such operation is only possible if the appropriate techniques for damage assessment and life projections are adopted. Much time and money have been spent by NP and PG in the development of these techniques in recent years. The application of damage assessment techniques by PG, for example, has allowed the period between major outages to be extended from 38 months to 50 months. Careful plant husbandry is crucial to the successful operation of the large coal and oil stations.

In the case of the CCGT stations, the older plants will require relatively expensive modification in order to make them suitable for everyday flexible operation if high levels of reliability and availability are to be maintained. There are likely also to be efficiency and degradation penalties under such an operating regime. Many of the designs of gas turbine or heat-recovery steam generator were never intended to operate under a regular stopktart

regime as would be required to follow daily or even weekly load variations.

Cost implications of designing new power stations with the technology to run more flexibly In any discussion of cost, it is necessary to draw a distinction between cost, price and value and to bear in mind that, in simple language, price is what the seller of a good or a service considers the market will bear or the buyer will pay Competition will have a major effect on market prices, but a far smaller effect on manufacturing costs.

Value, in the context of mid-merit generation, relates to the revenue-earning capability of the power station in the market place and this will be related to the ‘goodness’ of the plant. The ‘goodness’ factor will include all those factors which bear on the ability of the plant to maximise its revenue earning capacity such as efficiency, availability, maintenance costs, as well as the initial capital cost, or more accurately, the cost of servicing that capital such as interest on and repayments of debt and equity return.

The current world market for gas turbine power generation plant is intensely competitive

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and prices, in real terms, are probably at an all- time low.

The capital costs of large coal plant which, in European terms, means PF stations equipped with flue gas treatment or other clean coal technology such as gasification or fluidised bed combustion, are considerably greater than for gas turbine plant largely because, first and foremost, they are much more complex, but also because there are fewer providers of advanced coal combustion technology and the potential market is much smaller.

If we confine our considerations, therefore, to the UK market place and, perhaps naively, for the moment ignore the announcement made by the Government at the beginning of December 1997 on the suspension of further consents for gas-fired power stations, it is likely that, because of capital cost considerations, new power stations are likely to be gas fired and, because of the competitive market place, the capital cost implications of specifying plant to be capable of flexible operation are likely to be minimal.

Assuming now that, because of Government intervention, a significant market opens up for new clean coal power stations, I would suggest that the cost implications of specifying flexible operation for PF plant with flue gas treatment would, perhaps, not be particularly significant since it has been the way that large coal-fired plant has been specified in the UK for almost 40 years - the effects of creep and fatigue in such designs are well understood. It has to be said, however, that any new PF plant introduced into the UK might well be based on supercritical steam conditions which would introduce materials and technology which are not currently operationally used within the UK.

The situation with regard to advanced coal technology, such as pressurised fluidised bed combustion (PFBC) or gasification, however, might not be quite so straightforward. The proprietary PFBC gasification techniques are relatively complex with vessels and pipework accommodating high-temperature high- pressure abrasive gases. Frequent thermal cycling of such plant is likely to have significant deleterious effect on its performance and lifespan. The specification of flexible operation in such plant is likely to have a major effect on capital and operating cost and efficiency.

Conclusions Notwithstanding the current moratorium on

Section 36 consents for gas-fired power generation plant, Year 2000 in the UK electricity supply industry will see a large slice of the mid-merit generation market served by CCGT stations. Coal plant will be operating at ever-lower capacity factors as environmental constraints on SOX and NOx bite further. Flexible open-cycle GT plant will enter service which will bear more heavily on the market share taken by the coal plant. Maintenance and repair costs of the coal stations will rise sharply as major high-temperature components require expensive repairs or replacement to satisfy safety case requirements. The early CCGT plants will begin multi-shifting in earnest and the effects of thermal cycling will become apparent.

Acknowledgments The author is grateful to the Directors of Merz and McLellan Ltd. and Parsons Brinckerhoff Ltd. for permission to publish this article. He acknowledges with thanks the assistance of colleagues in the company for help in its preparation and editing. It is emphasised that the views expressed are those of the author himself and in no way reflect the corporate attitudes or views of Merz and McLellan Ltd.

References PowerGen plc and Midlands Electricity plc; a report on the proposed merger (Cmd3231, HMSO, London, April 1996) Seven Year Statement (National Grid Company, Coventry, April 1997) ROGERS, E: ‘Two shift operation of CEGB 500 MW steam turbines’, paper presented at IMechE Conference ‘Making steam plant pay’, London, May 1979 BEATT, R. J. I. et al.: ‘Two shift operation of 500 MW boilerhrbine generating units’, paper presented at ImechE Seminar on ‘Management and operation of thermal power stations’, London, September 1983 ‘The two-shifting of CCGT and fossil-fired steam plant’, IMechE Seminar, London, December 1995 PASCOE, S. K., and WILSON, J. D.: ‘Methods of risk assessment and benefits from application to pressure

Conference Paper Ref C502/008/95, London, 1995 PASCOE, S. K.: ‘The role and benefits of practical temperature damage assessment within a competitive electricity market’, IMechE Conference Paper Ref C494/001/96, London, 1996

vessel components within PowerGenl, IMechE

OIEE: 1998

Mr Burdon is a Vice-president of Merz and McLellan Ltd., Consulting Engineers, Amber Court, William Armstrong Drive, Newcastle upon Tyne NE4 7YQ, UK. He is an IEE Fellow.

122 POWER ENGINEERING JOURNAL JUNE 1998