Generating power at high efficiency
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WPNL2204
Generating power at high efficiency Combined-cycle technology for sustainable energy production
Eric Jeffs
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CRC Press Boca Raton Boston New York Washington, DC
Cambridge, England
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Published by Woodhead Publishing Limited, Abington Hall, Granta Park, Great Abington, Cambridge CB21 6AH, England www.woodheadpublishing.com Published in North America by CRC Press LLC, 6000 Broken Sound Parkway, NW, Suite 300, Boca Raton, FL 33487, USA First published 2008, Woodhead Publishing Limited and CRC Press LLC © 2008, Woodhead Publishing Limited The author has asserted his moral rights. This book contains information obtained from authentic and highly regarded sources. Reprinted material is quoted with permission, and sources are indicated. Reasonable efforts have been made to publish reliable data and information, but the author and the publishers cannot assume responsibility for the validity of all materials. Neither the author nor the publishers, nor anyone else associated with this publication, shall be liable for any loss, damage or liability directly or indirectly caused or alleged to be caused by this book. Neither this book nor any part may be reproduced or transmitted in any form or by any means, electronic or mechanical, including photocopying, microfilming and recording, or by any information storage or retrieval system, without permission in writing from Woodhead Publishing Limited. The consent of Woodhead Publishing Limited does not extend to copying for general distribution, for promotion, for creating new works, or for resale. Specific permission must be obtained in writing from Woodhead Publishing Limited for such copying. Trademark notice: Product or corporate names may be trademarks or registered trademarks, and are used only for identification and explanation, without intent to infringe. British Library Cataloguing in Publication Data A catalogue record for this book is available from the British Library. Library of Congress Cataloging in Publication Data A catalog record for this book is available from the Library of Congress. Woodhead Publishing ISBN 978-1-84569-433-3 (book) Woodhead Publishing ISBN 978-1-84569-454-8 (e-book) CRC Press ISBN 978-1-4200-8069-8 CRC Press order number WP8069 The publishers’ policy is to use permanent paper from mills that operate a sustainable forestry policy, and which has been manufactured from pulp which is processed using acid-free and elementary chlorine-free practices. Furthermore, the publishers ensure that the text paper and cover board used have met acceptable environmental accreditation standards. Typeset by Ann Buchan (Typesetters), Middlesex Printed by TJ International Limited, Padstow, Cornwall, England
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Contents
Acknowledgements
vii
1
Introduction
1
2
A brief history of development
9
3
Some early schemes
41
4
Gas turbine developments
57
5
Steam generator concepts
87
6
The single-shaft block
117
7
Repowering steam plants
135
8
Combined heat and power
154
9
Gas turbines and coal
166
What does the future hold?
190
Index
203
10
v WPNL2204
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Acknowledgements
I would like to thank the many people throughout the industry who have helped me over the years, providing information and arranging site visits. In particular I would mention three people who have reviewed my manuscript and thank them for their valuable comments. Dick Foster-Pegg, although born in the UK, emigrated to the USA and worked for Bechtel Corporation on some of the early combined-cycle concepts there, and later for Westinghouse on gas turbine research and development in Pennsylvania. Louis Codogno was Managing Director of the Energy Division of Cockerill Mechanical Industries up to his retirement in 2005 and was almost 40 years ago involved in the design of some of the first heat recovery boilers built by that company. Dr Maher Elmasri, President of Thermoflow Inc., was Professor of Mechanical Engineering at Massachusetts Institute of Technology until 1987. He left to form his own company, Thermoflow Inc., to develop and market GTPro, the first computer program for the design of a combined cycle. In the following 20 years the program has evolved into a powerful suite of software which is used around the world for the design and study of the operation of a wide range of gas turbine applications including, in the latest versions, the IGCC.
vii WPNL2204
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1 Introduction
Almost all of us alive at the start of the twenty-first century have grown up secure in the knowledge that, when we touch the switch on the wall, the light will come on. If it does not, then the chances are that the bulb has burned out and has to be replaced. Security of electricity supply is essential to our way of life, but we almost take it for granted that enough of the power stations are working to keep us supplied. However, a power station wears out and has eventually to be replaced, and the important question that we have to answer is: with what do we replace it? Present-day worries about climate change suggest that high efficiency is required of all new thermal power plants. Combined heat and power is one solution, but even with district heating or industrial processes the demands for heat do not necessarily coincide with demands for electricity. However, there is one engine which produces large quantities of exhaust gas, at a sufficiently high temperature, to generate steam for a small steam turbine. The gas turbine, which was first developed in the 1930s as an aero engine, is now at the centre of the most efficient generating yet devised: the gas-fired combined cycle as an electricity generator with an efficiency close to 60%. For much of the twentieth century the main fuels available for power generation were coal and oil and the efficiency of electricity production was at best 30% for the first 50 years. In the years after the Second World War, as the shattered economies of Europe and Japan were rebuilt, there was a period of great innovation across industry which all pointed to rapid growth in electricity demand. The first transistors were produced at the Bell Telephone Laboratories in the USA in 1948; the first gas turbines to be designed specifically for mechanical drive applications on land appeared the following year in Europe and the USA. The following decade saw the first gas turbine powered aircraft enter commercial airline service, and the application of the first computers in industry. Steam locomotives were replaced with electric and diesel traction on the railways. In the domestic market, television, refrigerators and a host of other electrical appliances spread across the population. The various social changes that resulted from the 1 WPNL2204
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development of these industries and the rapid expansion of others, the greater use of cars and road transport generally, and the development of supermarkets also added to the demand for electricity. As demand continued to grow the combined cycle was born out of a need to improve the efficiency of power generation. Until reheat steam cycles were introduced in the mid-1950s thermal power stations generated at an efficiency of less than 30%. The first combined cycle appeared in Europe in about 1960, but these early developments used the gas turbines available at the time, of which the largest were rated at about 25 MW, and their low exhaust temperatures required additional firing in the exhaust duct to raise the steam temperature going into the steam turbine. Nevertheless there was a sufficient gain in efficiency over the other thermal power stations of the time to show that, with further development of the gas turbine, a larger and even more efficient power plant could result. The first combined cycle in Europe was being built in Austria at a time when the electricity supply industry in Europe and North America was entering a period of change to meet a growing demand for electricity stimulated by the wider application of electric and electronic technologies among industries and the public at large. Generating sets were becoming larger, and voltages were increasing so as to be able to transmit economically the extra power that was produced. The first nuclear power stations were coming into operation, and the first high-voltage direct current (HVDC) transmission schemes went into service in Scandinavia. The first gas discoveries were made in the North Sea in 1964. It is ironic that what then was seen as a natural development of the electricity supply system was having benefits for the environment long before the Green movement became involved. HVDC, as developed in Scandinavia, showed how Norway, Sweden and Finland with a large hydro capacity and Denmark, which had entirely thermal generating plants, could pool generating resources between countries with different climates, in different time zones and with different industries and different methods of organisation of the working day. Furthermore it is an inherent property of HVDC transmission that it cannot propagate a fault in the sending network to the receiving network. Denmark could send base-load coal power north and hydropower was sent south at Danish peak times which gave better use of existing facilities and delayed the building of new power stations. Nuclear plants were at last a generating system which was not emitting smoke and ash into the environment and could not be accused of acidifying lakes downwind of them. Gas discoveries, in Europe at least, were to replace coal gas in the domestic market before being applied to power generation, but already the first combined cycles were pointing the way to achieving more efficient power plants. The oil crisis of 1973 was the principal catalyst for change. First it started a search for new oil and gas resources, and also set industry looking at ways to
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Introduction
3
improve the energy efficiency of both its products and its processes. This was a time when the first of the large gas turbines started to appear: 100 MW units which could run at the common synchronous speeds and therefore not require a gearbox in order to drive the generator. Exhaust temperatures over 500 °C could support more efficient steam cycles at higher temperatures and pressures without supplementary firing. The 1970s also saw the rise of an environmental protest movement. There had been protests before but these had been against specific actions such as the route of a power line or a new road. The new protest movements were not so much individuals as global organisations protesting against government energy, transport and environmental policies. Groups such as Friends of the Earth and Greenpeace all date from this time and, although some of their campaigns have undoubtedly been of benefit, their influence has not all been benign but has spread globally through their mastery of television presentation. A little knowledge is a dangerous thing and the way that public opinion has been influenced by these groups is amply illustrated by the contraction of the nuclear industry in Europe and North America, and by their influence which extends through the teaching profession into the education systems that now have fewer students coming forward to study mathematics, science and engineering. Already, in 2007, this was causing some anxiety in the oil and gas and the nuclear power industries as the people who grew up professionally with them as they were developed reach retirement age. Global warming is the latest environmental campaign and has been running for more than 10 years, but how serious is it? In the 60 years since the end of the Second World War the world population has trebled; so to blame only combustion of fossil fuels is to ignore the fact that there are three times as many people in the world now than there were then. Recorded history shows significant changes in climate when there was a much smaller population, when transport was on foot or horseback and when wind power ground corn and propelled ships. Two thousand years ago the climate of southern Britain was warm enough to grow grapes and to produce wine. Later it cooled and 300 years ago it was possible in winter to skate on the Thames in London. Modern commercial wine production in southern England started around 1970, summers are noticeably warmer and there is far less snowfall in the south of the country in winter, if at all. Industry gains no credit for steadily improving the efficiency of energy conversion from fuel to mechanical and electrical power. Any car owner will know that the efficiency of car engines has increased significantly in the last 30 years. Similarly the efficiency of the gas turbine has also been increased. Early models in 1970 had efficiencies of around 25%. The large gas turbines, over 200 MW, found in modern combined cycle plants are at about 37%, and the efficiencies of the latest models are nearer to 40%. Electricity generation has by its nature not shown the same overall improvement
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Generating power at high efficiency
in efficiency, particularly with coal-fired power. Unless it is a modern large coalfired unit of about 700 MW with a supercritical steam cycle and all the environmental additions, the efficiency will be significantly less than 35% over much of the world. Lasting improvement in efficiency will only come with the replacement of these generating plants, many of which are more than 30 years old, by a combined cycle in one or other of its forms. The emphasis on energy planning has changed. Some countries have introduced energy taxes which have aimed to encourage greater energy efficiency and reduction of the so-called greenhouse gases, principally carbon dioxide. Renewables, mainly wind power, have been heavily subsidised but still contribute little to the electricity supply. Biomass, mainly forestry and agricultural wastes and specially cultivated fuel crops, is judged to be carbon neutral and has caused boiler firms to increase research and development into the circulating fluidised-bed combustion system. However, if the Green movement becomes agitated over large-area monocropping for food, because of its deleterious effects on biodiversity, surely they are going to be even more agitated over monocropping to produce fuel, particularly if the plants have been genetically modified to increase the quality and volume of their yield. Natural gas is a finite resource although it is a product of the decay of vegetable matter and a few operators of landfill sites for refuse disposal have organised them in such a way that methane can be captured from the decaying refuse and burned in a gas turbine to produce electricity. One such scheme in the UK supplies electricity to Birmingham Airport. However, gas has been produced from coal for more than 150 years, and this brings us to the other important energy development, which is clean coal technology. This is really another name for the integrated gasifier and combined cycle (IGCC) which is gathering momentum in the coal-producing areas of the USA. There is now significant operating experience in several countries of IGCC plants mainly, it must be said, at oil refineries using residual oil and asphalt as feedstock. The gasifiers have been identified which will form the basis of these sytems. Costs are being reduced down almost to meet those of the conventional coal-fired systems. The first IGCC schemes are likely to be rated about 630 MW with a combined cycle based on the present generation of large gas turbines. The term ‘clean coal’ comes from the fact that the synthetic gas (syngas) produced can be cleaned of sulphur by established chemical processes and can be burned in a gas turbine which, as part of a combined-cycle cogeneration scheme, could also draw steam from the syngas coolers. The few coal gasifier plants that have been built in The Netherlands, Spain and the USA have been funded as development projects with the assistance of Government or European Union money but, in the USA, the IGCC system is on the point of commercial exploitation. Coal is still the most abundant fossil fuel reserve in the world, not least in the USA, where exploitation of an indigenous resource must be viewed against a growing need to import liquefied natural gas (LNG).
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Introduction
5
Since 1990 there have occurred massive changes around the world in the way that electricity is supplied. Deregulation, which started with privatisation of the UK electricity supply industry in 1990 has had two effects. Firstly, by separating responsibility for generation from transmission and distribution, it opened the door to independent power producers and forced the technology of generation in a new direction. Almost immediately applications were filed for combined heat and power schemes in industry, with the paper, petrochemical and food-processing industries to the fore. In a system where anybody could generate electricity and sell its surplus production at a fair market price, industry was keen to become involved and cut their energy costs, and in many countries, because of the state ownership of the electricity supply industries, they had never before had the opportunity. Secondly, the independent power producers appeared on the scene to provide the investment capital to continue the system. Year by year, as demand for electricity continued to grow, the cost of new capacity additions to keep pace with it also continued to rise but, whereas the State-owned utility systems had developed over the long term with specific energy policy objectives in mind, it was different for the independents. For them a power plant was an investment; they wanted one which which was easy to plan, quick to build, did not damage the environment and was highly reliable so that it could provide a good rate of return on the investment. All this pointed to the combined cycle which by 1990 could be considered proven technology and at a time when natural gas had emerged as an acceptable fuel for power generation with large reserves distributed around the world. As deregulation has evolved, the initiative for development of power plants has moved from the utilities to their supplier industries. Instead of the utility writing a specification for a power plant and inviting bids to design and build it, they just want an addition of capacity and have a choice of suppliers of complete generating plants which will be offered with long-term support for operation and maintenance. In the aftermath of deregulation, many of the public utilities, particularly in southeast Asia, have remained as the owners of the grid and therefore control the market into which the generators must sell their power. They retain a measure of influence in that they still control the development plan and collect data on the rate of growth of electricity demand and other factors on a national level which the private investors cannot be expected to do. Governments decide when new plants will be required and where they can be installed, although private capital will fund the project and the builders might retain a presence in the completed plant to train operators and to supervise operation and maintenance for the first few years. What has also happened is that electricity supply has become much more of a global industry as former national electric utilities have moved offshore. Spanish utilities, for instance, have moved into South America and Central America. The Belgian company Tractebel, is a major gas supplier in the USA and has interests in power generation there. Its Thai operation, Glow Energy Ltd, operates three large
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Generating power at high efficiency
combined heat and power schemes and an 800 MW combined cycle. International Power, from the UK, operates plants in, among others, the USA, Czech Republic, United Arab Emirates, Pakistan and Australia. In turn, the combined cycle has become standardized, with the development of the single-shaft block. This has made it possible for one of the new global generating companies to have the same plants as a standard 400 MW combinedcycle block (250 MW in 60 Hz countries) operating in different parts of the world with a global maintenance company supporting them with the turbomachinery. In Europe and North America, a more open market system has been set up. The original UK system had a national power pool into which all generators bid to supply in each half-hour period and were paid the price of the last unit to come on during that period. Several other countries adopted a similar system but did not have such a large system or such great diversity of generating plant as in the UK. However, the situation in Europe and North America is subtly different from that in much of the rest of the world. Here combined cycles have been installed in mature power systems where rates of increase in electricity demand in recent years have been no more than 1 or 2%/year. The combined cycles compete with the existing power plants many of which are old and completely written down, leaving just fuel, operation and maintenance costs to earn, whereas the combined cycle has to meet all these costs and capital repayment as well. From the end of 2004 onwards, there has been a steady rise in the price of both oil and gas, but oil at more than US$60/bbl has not had the damaging effect on the global economy as did the initial quadrupling of the oil price in 1973. In some ways it can be said to have had a beneficial effect in that it has stimulated the exploitation of more remote resources of oil and gas, and to support that is the development of a growing trade in LNG. In the last 40 years, new gas fields have been discovered in the Far East, the Barents Sea off the north coast of Norway, and in Central Asia, the latter requiring either long pipelines to bring the fuel to market, or else liquefaction for shipment to the customer. The much higher oil prices have encouraged deep-water drilling off the coast of Angola, Namibia and Brazil and stimulated the development of unmanned production facilities on the sea bed. As the North Sea fields decline, LNG from Norwegian, Middle Eastern and North African sources is starting to enter Europe and North America, and new pipelines are being built from Russia and Central Asia to western Europe, and also to China. For many years there have been just four companies offering basic designs in scaled 50 and 60 Hz versions of the large heavy-duty gas turbines specifically designed for power generation. As the result of various mergers within the industry there are two companies in Europe and one each in the USA and Japan who can bid to supply a combined-cycle block to any developer anywhere in the world. This is where we are at the beginning of the twenty-first century with the development of the combined-cycle technology firmly in the hands of the gas turbine suppliers. For the time being, the trend is to the basic refinement of the
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Introduction
7
design to make it more efficient and more reliable. Development so far has been hampered by major design problems in two of the gas turbine families and, although these have now been resolved, the market has since been cautious. European governments recently have been more concerned with meeting Kyoto targets and assigning a percentage of energy supply to renewables, mainly large wind farms. For the rest, coal has too many environmental problems and is almost priced out of the market. Nuclear power can be kept running but governments must be able to carry the electorate with them, if they are to build any more, although that seems to have happened in Europe in Finland and France, and a nuclear renaissance is gathering momentum in North America. For much of the world, however, combined cycle is the system of choice for most of the new generating plant needed in the first 20 years of this century, and as much again may be needed to replace plant that must be retired. It satisfies most environmental requirements with low emissions and a much reduced carbon dioxide emission due both to the higher efficiency and the use of methane with carbon dioxide and water as combustion products. In development over 50 years, the efficiency of electricity generation has risen from at best 35% for a large subcritical coal-fired plant to more than 58% in a single-shaft combined-cycle block and with far less environmental impact, in terms of both the physical size of the plant and the level of emissions. Gas turbines now under development aim to lift combined cycle efficiency above 60% but they are not likely to have much impact on the market for at least another 5–10 years. Several other technologies based on gas turbines have also been studied and some power plants have been built to test the principles of operation in a commercial environment but have not resulted in large markets. The Asian steel industry uses a number of gas turbines adapted to burn blast furnace gas, but this is a niche market for a particular industry. Although the price of oil is higher than in 1973, at between US$60 and US$80/ bbl, low inflation has reduced its economic impact. Nevertheless the factors raising the price of oil are not so much political as economic. Rapid industrial growth in China and India has increased demand, not just for oil and gas but also for other raw materials at a time when there is a shortage of refining capacity in the USA and Europe and irregular production due to sabotage of installations in Iraq and Nigeria. Opinion is moving toward the view that high fuel prices will be with us for a long time. Even where gas is not linked to the price of oil, LNG will add a new economic dimension to energy planning in Europe and North America. With many combined cycles in recent years having been designed for base-load duty and a quick return on the investment, have we lost sight of the value of flexible operation in later years? It would be advisable to look again at the lessons of the past if high gas prices persist, new coal-based and nuclear systems come to the fore, and combined cycle has again to occupy the mid-load market to provide the flexibility of operation that is the guarantee of a secure electricity supply.
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Generating power at high efficiency
There are signs of this already happening as a number of combined-cycle plants have been ordered in Europe during the second half of 2007 in, among other places, Germany, the UK, the Netherlands and Portugal. Several of these have specified Benson heat recovery boilers in anticipation of load following duty, including one project near Rotterdam which will only run during the daytime when electricity prices are highest. Does this point to the combined cycle of the future?
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2 A brief history of development
The principle of the combined cycle is that the hot exhaust gas from a gas turbine is passed through a water-cooled heat exchanger to power a small steam turbine. The Brayton cycle of the gas turbine is linked to the Rankine cycle of the steam turbine, and hence the term combined cycle. On gas turbine exhaust heat alone, the relationship is about 2:1 gas turbine to steam turbine output, so that a 120 MW gas turbine would generate enough steam from its exhaust gas to power a 60 MW steam turbine and, since no additional fuel is burned to make the steam, the efficiency of the system is significantly higher than that of the gas turbine alone, and of the traditional power plant of the last century with a coal- or oil-fired boiler generating steam for a 180 MW steam turbine. A combined-cycle set-up can be designed either as a pure generating plant or as a combined heat and power scheme integrated with an industrial process, with steam at the required pressures extracted from the steam turbine and/or the heat recovery boiler. Generally such projects are among the smaller installations serving a particular industrial site, with gas turbines rated at less than 50 MW, but there are now an increasing number of large schemes using the 250 MW class gas turbines in the 50 Hz market, and the equivalent 180 MW, 60 Hz models in the North American market, serving entire industrial estates. The combined-cycle principle as it is understood today is very much a European concept just as the gas turbine was before it, but that is not to say that other countries have not made significant contributions to the technology in the intervening years. In less than 50 years the combined cycle has evolved from a design idea to improve the efficiency of the power generation systems of the day, to being the preferred fossil-fuel-generating system across the world at a time of growing environmental concern. To understand why this should have happened we have only to look at the impact of the modern combined cycle on the power generation market. Cottam, shown in Fig. 2.1, is one of a string of coal-fired power stations built in the 1960s along the Trent valley of central England, close to the coal fields of 9 WPNL2204
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Generating power at high efficiency
2.1 Cottam, UK: the 400 MW combined cycle with the 2000 MW coalfired steam plant in the background. The combined cycle went into service in 1998 and is operated commercially by E.ON (UK).
Nottinghamshire and south Yorkshire. It provides a good example of the compactness of the combined cycle. The coal-fired power station was completed in 1968 and two of the eight large cooling towers are associated with each of the station’s four 500 MW steam turbines. The four boiler flues are contained in a single stack about 200 m high to allow for wide dispersal of the flue gases on the prevailing wind. The low buildings in front of the station are, from right to left, the heat recovery boiler of the combined cycle with the stack 60 m high, the gas turbine building with a small bypass stack to enable the gas turbine to run independently of the steam cycle, and 14 hybrid mechanical draught cooling units. The plant was completed by Siemens in 1998 as a development centre for testing combined-cycle components, notably the prototype Benson once-through heat recovery boiler, in a utility environment. Some upgrade kits also have been tested on the gas turbine. The original plan was to replace the gas turbine, their F-class Model SGT54000F, with a more powerful unit after about 5 years, but this development was postponed and the plant now runs commercially under the ownership of E.ON (UK). The plant output is 400 MW and the efficiency is 58.5%, compared with about 36% for the coal-fired station. The Cottam combined cycle, if it had been built as a standard single-shaft block, using the same gas turbine, would be even more compact, with probably a wet mechanical-draught-cooling system with eight rather than 14 cells, or else an air condenser, an outdoor heat recovery boiler, and no gas turbine bypass stack. Five
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A brief history of development
11
such units would provide the 2000 MW of the coal-fired plant, but they need not all be built on the same site. These then are the basic advantages of the combined cycle: high efficiency, low emissions and low environmental impact. This also gives it greater freedom of location. The combined cycle was built at Cottam because the then owners of the station were an existing gas turbine customer of Siemens who had land available, and there was a high-pressure gas line coming into the site. The greater freedom in siting combined-cycle power plants means that they can be located much closer to the load centres that they will serve and can therefore make better use of the existing transmission system. Not only that, but construction time is shorter and a typical time from initial ground breaking to the start of commercial operation, for a single 400 MW block, is little more than 2 years. Several combined cycles in the UK have been built on the sites of old coal-fired stations built in the 1930s and have been connected to the original 132 kV transmission system which would have remained in place. A further benefit is the much lower cooling load of the combined cycle. If the original power plant had three 60 MW steam sets cooled by a river passing the site, the steam turbine of a 400 MW combined cycle would be about 120 MW and marginally more efficient than the original 60 MW units. The combined cycle would therefore have a much smaller cooling load and it would probably have a hybrid mechanical draught system or an air condenser rather than draw cooling water straight from the river. Combined cycle is the preferred fossil fuel generating system because of its high efficiency, low environmental impact, low capital cost and shorter construction time. Cottam represents the culmination of development of the combined cycle over 50 years, which has almost doubled the efficiency of power generation. Although the first gas turbines are generally considered to be the two aero engines developed independently in the UK and Germany at the end of the 1930s, there was in fact a third stationary gas turbine developed for power generation, in Switzerland, by Brown Boveri, and exhibited at a World Trade Fair in Geneva in 1939. This unit, rated at 3 MW, was subsequently installed at the Neuchatel water works and, in 1990, was still available as a standby unit on the Swiss power system. After the end of the Second World War, in the late 1940s, the British gas turbine technology was made available to the USA and others, and the USA and Russian industries continued development on the basis of aero engines and from that into heavy-frame industrial versions for power generation and mechanical drive. In North America the combined-cycle developments started at the end of the 1940s but focused on the application of the gas turbine as a feedwater heater for a conventional coal- or oil-fired steam plant. The gas turbine was seen as a relatively small device producing a large volume of exhaust gas at less than 400 °C. As such, it had the potential to heat feedwater for a large steam plant and thereby to reduce the amount bled off the steam turbine for this purpose. The steam turbine would therefore produce more electricity from its own steam supply to which would be added the output of the gas turbine.
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In 1950, General Electric (GE) announced a 3.5 MW gas turbine which later became known as the Frame 3 and, although designed principally as a mechanical driver for the oil and gas industry, some single-shaft units were built, with the first examples being used in power plants as feedwater heaters. These early units were high-speed machines and were linked to the driven unit through a gearbox. Oklahoma Gas and Electric are credited with being the first utility to run such a combined cycle at their Belle Isle power station in 1949 followed by a second unit completed in 1952. Gas turbine development continued in North America. Three companies in particular focused on the market for power generation: GE, in Schenectady, New York, and with a separate aero engine division in Cincinnati, Ohio; Pratt & Witney in Hartford, Connecticut, concentrating on aero engine developments; Westinghouse, with headquarters in Pittsburgh, Pennsylvania, and with a Canadian production line at Hamilton, Ontario, about 120 km west of Toronto. By 1960 this industry was already global. Apart from the airline industry for which one of three companies could provide engines for a growing fleet of gasturbine-powered aircraft, the heavy-frame gas turbine manufacturers had also formed alliances with the electrical industries of other countries. Westinghouse had set up licences for their gas turbine and nuclear power technology with Fiat in Italy and Mitsubishi Heavy Industries in Japan, which in effect meant that, from a Westinghouse design base, the two companies could develop 50 Hz designs for the rest of the world while, because of the dual system frequency in Japan, Mitsubishi also could provide design input to the 60 Hz gas turbines. GE had a different approach with a network of business associates; these initially were Alsthom in France, AEG Kanis in Germany, John Brown Engineering in the UK, Kvaerner Brug in Norway, Nuovo Pignone in Italy, and Hitachi in Japan. Under this arrangement, GE supplied rotors, combustors and other noble parts to their business associates who would then package them and fit locally produced driven units. In 1962, West Texas utilities were planning a new power plant at Lake Nasworthy, near San Antonio. They already operated three gas turbines, including a GE Frame 3 which in 1959 had been applied to feedwater heating at their Rio Pecos station. The new plant for Lake Nasworthy would either be a conventional reheat steam plant of about 107 MW or a combined cycle of about the same capacity. Comparative studies showed that by using a 27.5 MW gas turbine there would be sufficient exhaust gas at 435 °C to supply a separate economiser which would replace all the low-pressure feedwater heaters of a conventional steam plant. Cost analysis showed that the combined cycle at a rated output of 130 MW could be installed at a total cost some US$3.60/kW cheaper than the steam plant alone. Lake Nasworthy went into commercial operation in June 1966 with a 27.5 MW Westinghouse 301 gas turbine and a 99 MW two-cylinder tandem-compound steam turbine, also by Westinghouse. The gas turbine was fitted with an evaporative
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intake cooler for summer use when ambient temperatures reach about 40 °C. At the design inlet temperature of 19 °C the gas turbine output was 24.6 MW with the steam turbine output as 99.6 MW and the plant heat rate was 9342 Btu/kW h, which made it the most efficient thermal power plant in the USA at the time. Despite the combined cycle’s advantage of higher efficiency the electric utilities were slow to take up the idea. By 1967 there were only five companies operating combined-cycle plants of this type. All were in the southwestern USA, with a total capacity of 658 MW, which was then equivalent to only 0.3% of a total installed capacity in the country of 236 000 MW. A problem of these early combined cycles was maintenance, which may explain why American utilities were not receptive of the idea. Incorporating a gas turbine into the steam cycle of a fired boiler meant that the maintenance needs of the gas turbine would determine the availability of the whole plant. In any case, most steam plant operators performed their own maintenance and the gas turbine was a new technology which they did not fully understand. However, these were not the only gas turbine developments at that time in the USA. By 1960 the basic designs had been established for a number of gas turbines, derivatives of which are still in production nearly 50 years later. A steady increase in performance came from the use of improved high-temperature materials, and the air cooling of the first turbine inlet vanes and the first rotating blade stages. As a result the GE Frame 3 rating of 5000 hp in 1950 had reached 14 250 hp by 1969, with the two-shaft Frame 3J introduced in that year. In 1957, GE announced their larger Frame 5 model in single- and twin-shaft versions for power generation and mechanical drive respectively, with an initial rating of about 19 MW. It was progressively improved over the next 13 years to the Frame 5P model which was introduced in 1970 as a 25.2 MW unit with an efficiency of 27.7%, burning natural gas and aimed specifically at electricity generation. Pratt & Whitney meanwhile had cornered the US civil aviation market with their JT4 turbojet engine and had developed from it the FT4, which was announced in 1960 as a unit of 13.5 MW which could be used to drive either a generator or a pipeline compressor. The engine exhaust was directed to a free power turbine which was coupled to the driven unit through a gearbox as appropriate. As such, it could be used with either system frequency. In England, Rolls-Royce announced, in 1963, a similar development of their Avon turbojet, as a 14.6 MW unit for generator and compressor drive. This unit was later uprated to 17.75 MW and saw service in generator packages, on offshore platforms and as compressor drivers on gas pipelines around the world. More than 1000 units were sold over the next 20 years. However, in the USA there was a massive power blackout in the northeast in 1963 which also extended into Canada. The following year Boston Edison bought four Avon gas turbine generator packages from the UK to act as peaking and standby units on their system. These were the first of many generating packages
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with aero-derivative gas turbines to be ordered around the world for similar duty. A feature of the Avon packages was the placement of a clutch between the power turbine and the driven unit so that the two could be separated and the generator run as a synchronous compensator at off peak times. Most of the gas turbines ordered by utilities during the late 1960s were for simple-cycle peaking units of this type. In Europe, the first combined-cycle projects followed the discovery of natural gas in The Netherlands and its distribution into neighbouring countries at the end of the 1950s. They were based on the available gas turbines of the time from the European manufacturers which were multi-cylinder units with free-standing combustion chambers and were characterised by relatively low powers and operating temperatures. As in America the object of the exercise was to improve the efficiency of power generation. It was the Austrian utility Niederösterreicher Elektrizitaetswerke AG (NEWAG) who in 1960 built the first combined cycle in Europe at their Korneuburg power station near Vienna. It was rated at 75 MW and consisted of two Brown Boveri Type 12 gas turbines with heat recovery boilers and a 25 MW steam turbine. From the beginning, the European concept of the combined cycle was different. The gas turbines were larger than the early American units which had been used for feedwater heating, with the Brown Boveri Type 12 at 25 MW, of the same order as the largest American machines then available. The European concept started with two gas turbines supplying a small steam turbine from their exhaust energy. Except for supplementary firing to raise the gas temperature entering the boilers, the arrangement of two gas turbines and heat recovery steam generators powering one steam turbine would become the commonest format for the majority of combined cycles that would be built with the next generation of gas turbines over the following 40 years. Korneuburg A had an efficiency of 32.5%. If compared with the efficiency of a 75 MW steam turbine of the time operating on a low-pressure non-reheat steam cycle, which would have been about 28%, it was a definite improvement in efficiency. Korneuburg A went into service in 1960 and ran on base load, averaging 6000 h/year for the next 14 years. By then, parallel developments in steam turbine technology had introduced higher steam pressures, with reheat, and the thermal efficiency had reached 36% with the 500 MW coal-fired units which came into operation in Europe from 1965 onwards. Meanwhile, NEWAG had built a second combined cycle at Hohe Wand, which was of a similar concept to that of the combined cycles that were then in operation in the USA. Rated 75 MW, it consisted of a Siemens Model VM51 gas turbine rated at 11 MW which was integrated into the steam cycle of a 54 MW steam turbine. The plant went into operation in 1965 as a base-load unit with an efficiency of 43.7%. For the first 10 years in operation it ran 73 000 h. Then, 4 years later, in 1969, at Angleur power station near Liège in eastern Belgium, a 23 MW Sulzer N1101 gas turbine was fitted with the prototype of a single-pressure heat recovery boiler which supplied steam to a 28.5 MW turbine.
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Since the exhaust temperature of the gas turbine was only 380 °C, supplementary firing in the exhaust duct raised the gas temperature to 530 °C so as to generate enough steam for the turbine. In these early years, the underlying problem was the low operating temperatures of the available gas turbines, and the low steam conditions and efficiency of the small steam turbines. Nevertheless these early plants had demonstrated the principles. The Belgian plant, in particular, ran in load-following mode with an average of 4500 h and 250 starts/year during its first 10 years of life and, by 1990, operation had reduced to less than 1000 h/year, since when it has been held on stand by and is now running no more than 100 h/year. The concept of Hohe Wand was similar to that of the American stations with a small gas turbine integrated with a large steam turbine. Initially it was more efficient than the gas-turbine-led concept of Korneuburg. In Europe, with larger gas turbines of about 50 MW capacity available, a series of power plants was developed, which became known as fully fired combined cycles installed between 1965 and 1978 and were formed by incorporating gas turbines with the fired boilers and steam cycles of existing power plants. With these larger gas turbines the hot exhaust gas would be used as combustion air for the burners of the main boiler and on its way to the boiler passed through heat exchangers that took over the role of some of the high-pressure feedwater heaters. There were 15 plants of this type built, at a time when nuclear construction was at a peak, and there were limits in Europe to the gas supply available for power generation. The gas turbine exhaust flow had to be matched to the combustion airflow to the burners in the main boiler, which determined whether one large or two small gas turbines would be used. It increased the power output from the site by both the contribution of the gas turbine and the additional steam flow released from feedwater heating. A typical installation would have a gas turbine of about 50 MW linked to a steam turbine of about 350 MW for a total plant capacity of 400 MW. The gas turbine generally burned gas and the steam turbine boiler was dual fired with natural gas or heavy oil. The majority of these plants were built in Germany and, for a while, ran in base load at an efficiency of about 44%. Two plants were of particular interest because they had coal-fired steam turbines. STEAG’s Kellerman Lünen station can be considered to be the first combined cycle linked to a coal gasifier. The gas turbine was the 50 MW Siemens Model V93.2 which burned gas produced by a Lurgi gasifier on an adjacent site. The other plant was Gersteinwerk K which used an early Siemens Model V94.2 as the gas turbine with a 500 MW coal-fired boiler. This plant was promoted as an example of how a gas turbine topping cycle could increase the efficiency of a coalfired power plant. The heyday of the fully fired combined cycle was really the 1970s. A 50 MW gas turbine linked to a 350 MW steam turbine provided a far more efficient plant than
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the 400 MW steam turbines then being installed across much of Europe. A further group of fully fired combined cycles was converted in the late 1980s from ten steam plants in The Netherlands. These were all between 12 and 15 years old and varied in output from 150 MW at Dordrecht to 590 MW at Eemshaven, near Groningen. Eemshaven was the last of the fully fired combined cycles to be built in Europe. It was a gas-fired steam plant with a single turbine with an efficiency of 40.3%. The gas turbine is a Siemens Model V94.2 rated at 128 MW (ISO rating). The converted plant has the heat recovery unit running in parallel with the feedwater heaters. After conversion the plant output was 698 MW of which the steam turbine produced 571 MW and the gas turbine 127 MW; the efficiency was 46.3%. By the time that Eemshaven went into operation in the winter of 1986, development of the alternative plant with an unfired boiler behind a gas turbine of high mass flow and exhaust temperature had established the definitive combined-cycle design around the world. Then, 10 years after their introduction, larger gas turbines with greater output and higher exhaust temperatures, and operating at the common synchronous speeds, had defined the combined cycle as we know it today; a gas turbine with an unfired boiler supplying a small steam turbine was the way to proceed to higher efficiency in generation. Furthermore there was no design compromise between the gas turbine and the steam turbine. The gas turbine had a specific output of heat and a boiler could be designed to produce steam at the desired pressure and temperature which set the design conditions for the steam turbine. Development was proceeding slowly in a less than encouraging environment in Europe. Electricity supply was fully publicly owned, in the UK, France and Italy, which were among the industrial leaders; in the UK a power station could only be supplied by a British company, in France by a French company, etc. The smaller countries with a more open industrial culture were more receptive to new ideas and it is not surprising that the first combined cycles installed in Europe were in Austria, Belgium, Ireland and The Netherlands. This also meant that the gas turbines based on American designs could not be easily sold in Europe but could in other parts of the world by for example GE’s European and Japanese business associates, but there were some units sold to large industries such as oil refineries and petrochemical plants where there was freedom to generate their own power outside the orbit of the public utilities. Combined-cycle development in earnest really began in Europe and North America after about 1970. The few operating plants on both sides of the Atlantic had demonstrated the potential of the combined cycle in its different forms to contribute to improved efficiency of power generation. The power plants Korneuburg A and Angleur had laid the groundwork for the combined cycles to follow, but up to this time the available gas turbines were relatively small and, at both plants, supplementary firing had been required because of the low gas turbine
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exhaust temperatures, but development of larger higher-temperature machines had already started. The first units designed to operate at the 60 Hz synchronous speed of 3600 rev/ min had been the GE Frame 7 gas turbine at 55 MW, announced in 1968, and the Westinghouse 501A gas turbine rated at 66 MW a year later. In Switzerland, Brown Boveri had announcd their first 3600 rev/min gas turbine as the Type 11 at 72.5 MW. An assembly line was set up at the company’s USA factory in St Cloud, Minnesota. The first GT11 went into operation in 1970. By this time there were therefore three large gas turbine models designed to operate at the 60 Hz synchronous speed of 3600 rev/min. Westinghouse and GE in the USA and Brown Boveri in Europe who assembled the Type 11 at their US plant. All the combined-cycle experience to date had been gained with old gas turbine designs of low power and operating temperature, but the principle was understood and designs for commercial power plants had been produced. In 1973, the outbreak of war between Israel and its Arab neighbours, and the creation of the Organization of Petroleum Exporting Countries (OPEC), who were then prepared to use the price of oil as a political weapon in support of their Arab members, led to the oil crisis in the autumn of that year which saw a four-fold increase in the price of a barrel of oil. Although gas had been discovered in The Netherlands, and later in the southern North Sea, electricity generation in Europe and North America was mainly with coal- or oil-fired steam turbogenerator sets, which had steadily increased in output and with a subcritical reheat steam cycle achieved an efficiency of at best about 36%. Much of the available hydropower potential had already been exploited to its economic limit, although not in the rest of the world, and the first nuclear power plants were coming into service. Over much of the developed world, oil was the main fuel for power generation, the exceptions being the UK, Germany, Australia and the USA with large reserves of coal which, together with nuclear power, was seen as the answer for at least large steam power plants. Algerian and Siberian natural gas supplies were starting to arrive in Europe, initially to replace synthetic coal gas in the domestic market, and high oil prices had stimulated development in the North Sea and Alaska. A large part of the natural gas associated with oil around the world was still being flared off at the well head as a useless by-product. Coal was also being considered, both for a coal-burning gas turbine and for the IGCC, but it would be another 20 years before the first applications would appear in the USA and Europe. In 1973, in the USA, Westinghouse completed a 520 MW combined cycle at American Electric Power’s Comanche Peak, Oklahoma, site. This had four of the 90 MW Westinghouse 501B gas turbines arranged in two blocks, each with two gas turbines, two heat recovery boilers and one steam turbine. Over the next 4 years they installed another five examples of this nominally 260 MW combined-cycle block. One was installed at El Paso, Texas in 1975, and two were provided to
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Florida Power and Light at Putnam, Florida, in 1976 and two more the following year to Southern California Edison at Coolwater. Subsequently, 10 years later, Coolwater would become the site for the Texaco gasifier and the first IGCC scheme burning syngas derived from coal. GE similarly were promoting their STAG system and had a notable success with Comisión Federal de Electricidad (CFE) in Mexico, with one block installed at their Dos Basos site in 1974, and three at Gomez Palacio in 1976. In Europe, the first gas turbines to run at the 50 Hz synchronous speed of 3000 rev/min were under development. Brown Boveri launched their Type 13 in 1973. The following year, Siemens launched their 3000 rev/min unit as the V94.0 at 90 MW. In Italy in 1975, Fiat (the Westinghouse licensee) had scaled up the original W501 design to produce the 92.5 MW TG50 for the 50 Hz market and Westinghouse with Ateliers de Constructions Electriques de Charleroi (ACEC) built one as the W1101 gas turbine in the ACEC factory at Gent and installed it at Interbrabant’s Drogenbos power station in the southwestern suburbs of Brussels. Also in 1975, GE put into service their first Frame 9B gas turbine at 82 MW which they had developed in a joint venture with Alsthom, who were their French licensee for nuclear and other technologies. Initial production was all in Europe. Alsthom set up a factory at Bourogne a few kilometres from their gas turbine production line at Belfort to supply rotors for the new 50 Hz machines. By 1975, therefore, all the major manufacturers in Europe each had a large gas turbine operating at synchronous speed and with exhaust temperatures at 500 °C but none yet applied to combined cycles. The high price of gas in Belgium prompted InterBrabant to repower the best of the three 37 MW steam sets at their Drogenbos plant by replacing its boiler with a heat recovery boiler fitted to the Westinghouse gas turbine that was already on the site. Cockerill Mechanical Industries (CMI) who had supplied the original boiler at Angleur in 1969 were engaged to supply the new heat recovery boiler. The repowering was completed in March 1976. Meanwhile, Westinghouse with ACEC had seen an opportunity to supply a smaller 120 MW combined-cycle block based on the 40 MW Model W251B7 gas turbine which they installed at Angleur 2 in 1978 (Fig. 2.2). They also supplied two of these gas turbines to repower a 35 MW steam turbine at the Jertovec power station in Croatia. Siemens had applied their 90 MW Model V94.0 gas turbine in 1974 at an initial rating of 90 MW. The first unit was installed in Vienna for an extension of the Leopoldau district heating station, followed by two more at the South Munich district heating plant. GE sold five of their Frame 9B gas turbine at the initial rating of 85 MW of which the first was installed by Electricité de France (EdF) as a peaking plant on a site in the north of the country near Valenciennes in 1975. Of the first production batch, three were sold to the Berlin utility BEWAG, for a district heating plant, although not a combined cycle, and one to the Electricity Supply
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2.2 Angleur 2, Belgium: the schematic diagram of the definitive combined cycle with high-temperature gas turbines, a single-pressure steam cycle and no supplementary firing. It was completed in 1978.
Board of Ireland which was used to repower a 30 MW steam turbine at the Marina power station, near Cork. By 1980, there were 14 combined-cycle stations operating in seven countries of which six were in the USA and two each in Belgium and Mexico, and one each in Austria, The Netherlands, Ireland and Germany. Of these, two were repowering schemes in Belgium and Ireland; two were district heating schemes in Vienna and Munich. The gas turbines of these plants were the first to be designed specifically for power generation and with further development achieved outputs of 100– 160 MW and would come to dominate the combined-cycle market up to 1995. By 1980, there was a clear distinction for the heavy-frame gas turbines, between the European designs and the aero-engine-inspired American designs. The Europeans, who were among the leading power engineering companies, had from the beginning approached gas turbine design from the viewpoint of power generation. Their gas turbines were characterised by large silo-type combustors mounted on top or to the side of the casing, while the American designs were born out of the aero engine technology from which their industry had developed and had a ring of combustor cans arranged around the machine body: the so-called can–annular system. The specific difference was in the fact that the actual burners in the American designed units were smaller than in the European machines with their large silo combustors. In their original configurations before the introduction of dry lowemissions burners, Siemens for the V94 gas turbine had eight burners in each of their two combustor silos. Brown Boveri in the Type 13 gas turbine had only one in a single top-mounted silo. The GE Frame 9E gas turbine had 14 combustor cans each with a single burner, as did Westinghouse with their 60 Hz Model W501D. Before 1980 it was not assumed that the gas turbine would always burn natural gas. Particularly in the Asian Pacific countries it was thought that heavy oil would be
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burned, and many saw that the European machines with their large silo combustors were better able to cope with heavy-liquid fuels. These gas turbines were much larger than the aero engines and their derivatives that had preceded them, but they ran at synchronous speed and could be started and run up from cold to full load in about 10 min, which was much quicker than a steam turbine of equivalent size. They had higher operating temperatures and consequently higher efficiency. In time this meant that they would support a high-pressure steam cycle which together would give a great boost to combined-cycle efficiency. These gas turbines also introduced a new combined-cycle concept as the repowered steam plant. Suitable plants for repowering would be those built in the early 1950s with steam turbines of 30–60 MW, or roughly half the capacity of the available gas turbines. Demolishing the fired boiler and replacing it with a new heat recovery boiler and a gas turbine would increase the output by about 200% and, since all the fuel was consumed by the gas turbine, the efficiency would be significantly improved from about 30% to at least 45%. Repowering is very much a niche market. While there were a few schemes in North America and Europe, and one in Japan, it was only when the much larger Fclass gas turbines came into the market after 1995 and could support the steam conditions of turbines up to 150 MW, that any further repowering schemes were undertaken in the 50 Hz market. In Europe, with its monolithic, publicly owned electricity supply industries in all but a few countries, the concept of a combined cycle then was of a mid-load plant which would start and stop once or twice a day and probably be shut down most weekends. It had a vertical heat recovery boiler with a single pressure to the steam turbine and a separate low-temperature preheater stage to hold up the temperature of the deaerator and so to avoid risk of dew-point corrosion through condensation in the top of the boiler. It was cheaper to operate than an old coal-fired plant that burned coal just to keep warm and to be ready to run for a few hours at peak time, as had been the case up to then. Dry running capability was a feature of these early heat recovery boilers but it was really an emergency measure and required the gas turbine exhaust temperature to be reduced. For the plant in Angleur the exhaust temperature of the W251B was 504 °C but, to run through a dry boiler, the exhaust temperature had to be held below 480 °C. The two gas turbines there, in fact, ran for nearly 6 months through dry boilers during a repair outage on the steam turbine generator in 1984. At this time there was a considerable degree of commonality between the combined-cycle designs of Europe and North America. The basic combined-cycle block had two gas turbines, two boilers and one steam turbine, and the gas turbines were rated at between 80 and 100 MW. The boilers were of vertical format with a single-pressure output to the steam turbine and a preheater loop through a deaerator to raise the feedwater temperature entering the main economiser. The only difference was that the American boilers, e.g. that in the Westinghouse PACE 360 combined-cycle package, with the more powerful W501D gas turbine, had
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duct burners to increase steam production and to compensate for the lower gas turbine output at higher ambient temperatures. It is a practice which has continued in the USA to the present day. Although combined-cycle designs had been accepted in the southern USA which in the early years was certainly the largest individual market, they were still relatively few in number. It was an initial move to deregulate the electricity supply industry and to encourage the deployment of combined heat and power schemes in industry that carried the gas turbine industry forward in the USA, but there was still little interest in combined-cycle design being shown in Europe. The Public Utilities Regulatory Powers Act (PURPA) of 1979 was a measure introduced by the Carter Administration to promote economy in energy production through combined heat and power. Under the Act, any operator was able to sell electricity to their local public utility at the market price from a combined heat and power plant but, to do this, a prospective operator had to find a qualifying steam host in order that the plant could be licensed and built. PURPA effectively revived the gas turbine market in North America. The steam host could be a paper mill, a chemical plant, a refrigeration plant or any other site with a large and regular demand for process steam. Many installations were of a size that required a gas turbine of less than 40 MW. Some installations used a 25 MW aero-derivative gas turbine with a heat recovery boiler and a small steam turbine with steam taken from the high-pressure header to process and from a steam turbine extraction point or back pressure, for low-pressure process steam. Generally the steam demand determined the number and size of the gas turbines. How much steam could be supplied from the unfired heat recovery boiler? In this way the gas turbines would be likely to have surplus power for sale. The way in which this worked in practice varied from state to state. In some states the industrial power plants were dispatched by the utilities and therefore had to install back-up boiler plant to guarantee supply to the steam host when the gas turbine was not operating. In other states the utility bought power from the independent generators and moved their own plants from base to mid-load and peaking duty. Southern California Edison in 1982 was the first public utility to announce that it would build no more power plants but would buy future supplies from independent suppliers. Many large combined cycles were built for combined heat and power schemes using the heavy-frame 60 Hz gas turbines of the time, which were rated between 75 and 100 MW. For these schemes, there might be two, three or four gas turbines with heat recovery boilers supplying a single steam turbine. There could be one or two process steam bleeds from the turbine and a back-up supply throttled down from the high-pressure steam header. The technology of these schemes was based on the requirement to run continuously for long periods. Hence an entirely different concept of heat recovery boiler was developed with the horizontal natural-circulation design. While this boiler may have been reliable in a combined heat and power scheme running continu-
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ously between production batches, which might shut down only twice or three times a year, it is a totally different application from load following in a public supply network with daily or weekly stops and starts. Many schemes, too, were combined cycles with small gas turbines including an aero-derivative turbine. However, in a country of more than 200 million with a largely uniform lifestyle, there were some very large process industries which supported a large combined cycle with supplementary firing of the boilers to balance steam and electric loads. PURPA’s consequence for the gas turbine industry was to bring innovation into the bottom end of the market. The companies such as Solar Gas Turbines, in San Diego, California, and Ruston Gas Turbines in Lincoln, UK, which had grown up as suppliers of mechanical drives to the oil and gas industry found a ready market for small combined heat and power units and developed new models to serve those markets. The aero engine makers, particularly Rolls-Royce and GE, were seeing a demand for units of 25–40 MW which could be met by the core engines of the large turbofan units which, by 1980, had been in airline service on international routes for 10 years. The growing demand for gas in many parts of the world had also created a market for compressor drivers on pipelines and offshore platforms. All these gas turbines had to meet the same environmental standards as the large gas turbines in utility service particularly in the reduction of nitrogen oxides (NOx). Much of the development over the next 10 years across the gas turbine industry was in the production of dry low-NOx combustion systems both for all the heavyframe gas turbines, including the small units below 10 MW and the large aero-derivative turbines which were finding increasing application in industrial combined heat and power schemes. The growing environmental movement during the 1970s had first focused on the consequences of acid rain due mainly to sulphur emissions from coal-fired power stations. The first stations to be fitted with flue-gas desulphurisation (FGD) systems started to come into service at the end of the 1970s in Germany and the USA. This had an immediate effect on the economics of coal-fired generation because it added to the capital cost without increasing the output and, because the FGD system created a back pressure on the boiler, it lowered the efficiency of the station. It had one benefit in that the limestone required to operate the system was transformed into calcium sulphate (gypsum) for which there was a ready market in the building industry for making plaster board for ceilings and partition walls. For the gas turbine industry the immediate concern was to reduce NOx emissions. Gas turbines produced visible yellow smoke when burning liquid fuel with high sulphur content, and the other problem that occurred because of their high firing temperatures was the brown colour of nitrogen dioxide. Very few gas fields have been termed sour gas, containing sulphur and the main concern for hightemperature combustion was NOx. Water injection went some way to alleviate the
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problem but the industry itself sought to develop a dry combustion system which would reduce the formation of NOx from the combustion air. For much of the 1980s the gas turbine market in Europe was quiet. The principle of the combined cycle was well understood in the few plants that were built and the industry was confident to bid contracts based on these designs in other countries. Discovery of new gas fields continued apace, particularly offshore Southeast Asia, in South America and in the northern North Sea. Gas was coming into Europe from North Africa and Siberia but, as natural gas entered the market, it first replaced coal gas in the domestic market. For most countries where there was no energy market for coal-derived gas but which had found natural gas, the only way to exploit this new resource was with a large end use such as a power plant that would put the new gas supply infrastructure in place. There were few opportunities for combined-cycle development, but those that were built effectively defined the technology for what would follow in the next decade. It was not until the discovery of gas in and offshore southeast Asia and Australia that the combined-cycle market started to develop with the start of a trade in LNG between the producers, principally Australia, Indonesia and the United Arab Emirates, and the utilities in Japan, South Korea and Taiwan. As the gas fields were developed and supplies came ashore, so the first moves were made to install combined cycles in Japan, Taiwan, Malaysia and Thailand in 1983, and later in India where three stations were built on a pipeline running from Mumbai to Delhi and taking gas from the Bombay High field in the Indian Ocean. For these plants the gas turbines were early versions of gas turbine models, some of which with further development are still available today. In 1979, a general measure of 75 vppm at the gas turbine exhaust was accepted as a target for the industry on which to improve. Then 10 years later the consensus was that for natural gas the limit would be 25 vol.ppm and, for oil, 42 vol.ppm which could only be met by steam or water injection into the combustor. Nearly 30 years later contracts still specify NOx capability at 25 vol.ppm when firing gas and 42 vol.ppm on oil, but in reality much lower values are attainable with gas. By 1986, Siemens and ABB, formed by the merger of Brown Boveri with the Swedish ASEA group, had their own dry low-emissions burners and were marketing them with their gas turbines where local rules required, but these were only active with natural gas and, for liquid fuel, water injection still had to be used. All the above values are as measured at the gas turbine exhaust flange. In some parts of the USA, however, emissions have been defined as measured at the outlet of the stack. In the New England states the requirement is for 3 ppm coming from the stack and, to meet this, a catalyst must be installed in the heat recovery boiler to promote a chemical reaction with ammonia to reduce NOx to nitrogen and water. The reaction works best above 300 °C and the catalyst is therefore placed in the boiler upstream of the low-pressure superheater. The three Asian Pacific countries were poor in energy resources and were
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obliged to buy all their oil and coal excess to their own production. They were as anxious as other countries to get oil out of power generation and went for nuclear power and natural gas. Nuclear plants were built first and then combined cycles, but there was still some concern about the availability of natural gas. In the decade from 1980 to 1990 the market for combined cycle was gradually expanding across the world with most activity focused on the Asian Pacific countries and southeast Asia. Interestingly in Japan which, like France, was developing a large nuclear power park, a large combined-cycle programme was also implemented for mid-load duty. Under Japanese law there is a requirement for the annual technical inspection of all steam-generating plant, which of course includes power station boilers. On a combined cycle every boiler must be inspected at once, which on a 2+2+1 combined cycle means shutting the whole plant down and losing the entire output for the duration of the inspection. Nevertheless the first of the Japanese combined cycles to enter service was at Tohoku Electric’s Higashi Niigata site 300 km north of Tokyo on the Sea of Japan coast. The combined cycle consisted of two blocks rated at 545 MW each with three M701D gas turbines unfired heat recovery boilers and a steam turbine. The notable feature of this plant is that it has the first gas turbines to enter service equipped with dry low-emissions combustors. Next Tokyo Electric Power at Futtsu installed 14 single combined-cycle units each consisting of one GE Frame 9E gas turbine, a heat recovery boiler and a steam turbine. Taiwan’s first combined-cycle plant at Tung Hsiao some 100 km south of Taipei on the west coast of the Island started as in Japan with blocks of 3+3+1 configuration which, being in a 60 Hz power system, were rated at about 360 MW. Two were supplied by GE each with three Frame 7EA gas turbines and a Toshiba steam turbine, and the third was by ABB with GT11N gas turbines. The GT11N with its silo combustor was chosen because of the initial requirement to burn heavy fuel oil. This also went into operation in 1983. Elsewhere in Asia, Thailand and Malaysia in particular exploited new gas fields in the gulf of Thailand, with Bang Pakong, 900 MW, in Thailand, and Paka, also 900 MW, in Malaysia. India had discovered the Bombay High field in the 1970s and constructed a pipeline from a shore terminal north of Mumbai to Delhi with three combined cycles along the route: Kawas, with four GE frame 9E gas turbines in two 300 MW blocks was the southernmost plant followed by Anta, with three Alstom GT13D gas turbines in a 3+3+1 arrangement, and Auraya, with a similar arrangement of Mitsubishi 701D gas turbines. In 1984, The Electricity Generating Authority of Thailand (EGAT) completed their first combined cycle at Bang Pakong about 120 km south of Bangkok. It had two blocks each with four of the Siemens interim Model V94.1 gas turbines and a steam turbine for a block capacity of 440 MW. The plant was intended to burn gas from the Erewan field in the Gulf but one block was designed for dual-fuel
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operation, and a fuel treatment system was installed so that it could if necessary run on liquid fuel at least until the extent of the Gulf fields was fully known. In reality, apart from being commissioned on oil, none has been burned since to generate electricity. In 2004 the plants were still running in base load after operation for 20 years. The early combined-cycle operators in India had an unusual problem of competition for fuel. Natural gas was required for fertilizer production and as a result there was a shortage of fuel for the combined cycles because of the demand of the fertilizer industry. The southernmost of the three combined cycles at Kawas, with four GE Frame 9E gas turbines in two 300 MW blocks, was only allowed to run one gas turbine in its early years, which meant cycling half-blocks between each gas turbine to even up wear. The answer was to burn naphtha, of which there was a surplus at Indian refineries, and the station, which was completed in 1993, was converted in 1996. In Turkey, a small gas field was discovered near Hamitabad in the European province and, with additional supply coming from Russia to Istanbul, the first combined-cycle plant contract was awarded to Brown Boveri (now the Alstom Gas Turbine Division) to be built in two stages and completed in 1989. In 1987, the catastrophic explosion of a reactor at the Chernobyl nuclear power station in the Ukraine spread radiation northwards over Belarus and across Scandinavia where it was first picked up 2 days later on radiation detectors at the Forsmark nuclear power station in Sweden. The event turned public opinion against nuclear power over much of Europe and no more so than in Italy at a time of government crisis. The price of a new Christian Democrat–Social Democrat coalition was the closure of the country’s three operating nuclear plants and the cessation of construction of a fourth at Montalto di Castro. Italy, denied nuclear power for political reasons and with all its hydro and geothermal resources used up, had no option than to import oil and gas and to use them at the greatest efficiency. For the domestic gas turbine industry there suddenly appeared a market for small industrial combined heat and power schemes and the repowering of the older oil-fired steam sets with gas turbines and heat recovery boilers replacing the original fired boilers. Two stations with 12 gas turbines in Italy and the Dublin North Wall scheme in Ireland account for the repowering schemes during the second combined cycle decade up to 1990. Another scheme which could be considered repowering was in the USA at Midland, Michigan, where construction of a nuclear power station had been stopped in the mid-1980s and it was decided to modify the steam turbines to accept the output of 12 heat recovery boilers behind ABB GT11N gas turbines. The gas turbines of 100–150 MW rating which accounted for the majority of combined cycles built during this period had higher exhaust mass flow and temperature and could support a higher-pressure steam cycle. The amount of exhaust energy was such that it could be best recovered with a two-pressure heat recovery boiler. There is a hint of this in the Angleur steam cycle where there is a
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feedwater preheater loop in the top of the boiler to extract as much of the low-grade heat left to hold up the deaerator temperature. For the much larger gas turbines the heat distribution through the boiler is sufficient to support a second evaporator and superheater at a lower pressure. With this arrangement efficiency was around 47– 49% and in some cases over 50%. By 1990, the combined-cycle market around the world had risen to 53 plants with 161 gas turbines and an aggregate capacity of 24 384 MW. Of these, 14 were in the USA with 48 gas turbines, 27 of which were in multishaft industrial combined heat and power schemes, including the Midland, Michigan, scheme with 12 gas turbines. In Japan there were four plants of which Tokyo Electric Power Company’s Futtsu site had 14 single-shaft blocks of Frame 9E gas turbines, and Chugoku Electric’s Yanai site had eight GE Frame 7 EA gas turbines. Six schemes in Italy were all repowering steam plants with two Fiat TG50 gas turbines repowering each of six steam turbines. Still there was little impact of the combined cycle in Europe. A number of small industrial combined heat and power schemes and district heating schemes had been built mainly in The Netherlands, Spain, Italy and Finland, but few large combined cycles. All this was about to change when in 1990 the first steps were taken to privatise the electricity supply industry of the UK. It resulted in the creation of five generating companies, namely National Power, Powergen, British Energy, Scottish Power and Scottish Hydro, with 12 regional electricity companies distributing electricity in England and Wales, and with the right to build their own generating plant; finally the National Grid Company managed the transmission network into which the generators had to sell their power. Put simply, the electricity supply industry was no longer run by the Government. Generation had been separated from transmission and anybody could generate electricity and sell it to the grid at the market price. The idea was copied around the world and, although some countries retained the transmission system in public ownership, the immediate effect was a sudden burst of activity into industrial combined heat and power where there had been none before, and a rush to build combined cycles to replace old and inefficient coal- and oil-fired capacity. The first combined cycle in the UK was installed at Roosecote, near Barrow-inFurness in northwest England, where a 225 MW combined cycle was erected in the turbine hall of a former 120 MW coal-fired power station which had four 30 MW steam sets. The refitted turbine hall and a few outbuildings were all that remained of the original power station. The rebuilt plant went into operation in 1991. Several other combined cycles followed in quick succession so that, by the end of 1995, 11 plants had been built with an aggregate capacity of 8000 MW and there was none of the former coal-fired power plants left in operation with generating sets of less than 200 MW. Some of the larger plants built since 1960, including Pembroke (four 500 MW oil-fired plants) and Drakelow (four 350 MW coal-fired plants) have since been demolished to prepare for the installation of new combined-cycle plants.
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2.3 Limay Bataan, Philippines: the country’s first combined cycle which was oil fired and went into service in 1994, 10 years before the arrival of gas in Batangas province.
In some countries where no gas was available, and there was a need to add new capacity, the combined cycle, with its higher efficiency and lower construction costs, still had advantages over an oil-fired steam plant, particularly if the country had to import all of its oil supplies. One such country was the Philippines where in 1994 the first combined cycle went into operation at Limay Bataan, located about 120 km from Manila around the north side of the bay (Fig. 2.3). It is oil fired and consists of two 450 MW blocks each with three Alstom GT11N gas turbines and a steam turbine. During construction the Malympaia gas field was discovered about 450 km offshore of Batangas, a port city in southwest Luzon. With no domestic gas market the only way to develop this field was to provide a concentrated market, which effectively meant power generation. Batangas is the location of the Shell refinery, and it was here that the gas would come ashore. Santa Rita with four single-shaft blocks of Siemens SGT6-3000F gas turbines which was completed in 1999 ran for 2 years on liquid fuel before gas came ashore. Two other combined cycles were later built in the same region. In the Middle East, Saudi Arabia, with large fleets of simple-cycle gas turbines running on crude oil, opted for its first combined cycle by converting eight simplecycle gas turbines at Rabigh, 150 km north of Jeddah on the Red Sea coast, into two combined-cycle blocks with eight heat recovery boilers and two steam turbines. For this project, since the gas turbines, early versions of the ABB Type GT11, were burning crude oil, the boilers had to be fitted with soot blowers to clean the high-
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pressure superheater tubes which were in the hottest zone of the boiler and therefore the first to encounter the incoming exhaust gas stream. Soot blowers are commonplace on oil-fired steam plants, but this was the first time that they had been used on a combined cycle. Saudi Arabia would later specify soot blowers on all the subsequent combined cycles. For these boilers, soot blowing using high-pressure steam is a daily occurrence lasting about an hour. In the rapidly growing economies of the Middle East and Asia, combined cycles were built as base-loaded plants to support the growth in electricity demand. On the majority of sites the gas turbines were installed first and commissioned to operate in simple cycle while the heat recovery boilers and steam turbine were erected behind them. Each gas turbine would have a valve in the base of the stack so that, when the boiler was connected behind it, the original stack served as a bypass. In Europe, none of the new combined cycles was built in stages and there was no economic justification for simple-cycle operation. They were built in mature power systems with low rates of growth in demand and significant reserve plant margins The majority of the initial installations were in 2+2+1 arrangement with vertical boilers. It was only when American developers came into the market and brought the horizontal-boiler technology with them that these boilers started to appear in Europe in any great number. The aero-derivative gas turbines which had come into utility service for peaking and standby duty in the 1960s were now much larger and with dry low-emissions combustion systems in the generator and mechanical drive versions could be operated anywhere. The GE LM6000, which was introduced in 1990, was a turbofan core engine rated at 42 MW and running at 3600 rev/min and could therefore drive a 60 Hz generator without the need for a gearbox. Several have been installed in combined heat and power systems. Rolls-Royce produced a 28 MW version of their RB211 turbofan engine which has been sold to industrial combined heat and power schemes in Europe and South America. During the early 1970s, Rolls-Royce built a number of generator packages based on their Olympus engine and had produced conceptual designs for the combined cycle based on the Olympus 593 engine of the Concorde supersonic airliner, and the RB211 turbofan which was then just coming into airline service. Then, 20 years later, four RB211 turbofans were installed in a combined cycle at Samarinda, on the Island of Borneo in Indonesia (Fig. 2.4). The station consists of two 75 MW blocks each with two RB211 turbofans and a 25 MW steam turbine. At the time, Rolls-Royce owned Northern Engineering Industries which included turbine maker CA Parsons, in Newcastle upon Tyne, and the boiler maker International Combustion, of Derby who had been a subcontractor to CMI on several of the combined cycles in the UK for which the Belgian firm had supplied the heat recovery boilers. In fact, for a few years, Rolls-Royce had the complete capability to design and build a combined-cycle power station, but this was not their main business; later Parsons was sold to Siemens and is now the steam turbine maintenance headquarters for the whole group. Switchgear and control systems
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2.4 Samarinda, Indonesia: one of the few combined cycles with aeroderivative gas turbines. It has four RB211 gas turbines in two 75 MW blocks on the Island of Borneo. (Photograph courtesy of Rolls-Royce.)
were sold to the Austrian group VA Tech, who themselves were taken over by Siemens in 2006. The combined-cycle market in the early 1990s was all based on multishaft plants with two, three or four gas turbines powering a single steam turbine. The most commonly used gas turbines at this time were uprated versions of the models introduced in the mid-1970s and with outputs between 120 and 150 MW, resulting in a combined-cycle block in the commonest arrangement of between 350 and 450 MW. All the major gas turbine companies had new models under development in 50 and 60 Hz versions which would enter service from 1992 onwards. The first F-class gas turbines had in fact appeared in the USA before 1990. GE announced the 150 MW Frame 7F gas turbine in 1988, and Westinghouse followed with the 501F gas turbine a year later. These were high-temperature machines with turbine inlet temperatures nearer to 1300 °C and were introduced with a number of common features. All drove the generator from the cold (intake) end of the machine, which meant that there was a straight exhaust gas path to the heat recovery boiler with fewer parasitic losses. Indeed the Frame 7F was the first heavy-frame gas turbine of GE that did not drive from the exhaust end. All had dry low-emissions burners as standard equipment. The starting system was based on a static frequency converter operating through the generator. The prototype Frame 7F gas turbine was installed at Virginia Electric Power’s Chesterfield site, initially for simple-cycle testing, and was converted to a combined cycle in 1992. The first examples of the Westinghouse W501F gas turbine went to a repowering scheme at Florida Power and Light’s Fort Lauderdale station in 1991. In Europe, Siemens launched three F-class gas turbines: the V64.3 at 60 MW in
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1988, the V84.3 in 1991 and the V94.3 in 1992. The first to appear on the market was the V64.3 at 53 MW of which two were sold to Helsinki Energy for a combined-cycle district heating scheme at Vuosaari in the eastern suburbs. The combined-cycle market in Europe started in 1990 with privatisation of the electricity supply in the UK. First the Central Electricity Generating Board (CEGB) was split into three generating companies: National Power, Powergen and British Energy, the nuclear plant operator. The 12 area distribution boards became regional electricity companies, with the right to build their own generating plant. Few decided to build but instead entered power purchase agreements with the independent plant operators. This coincided with the relaxation of a European Union ban on using natural gas for power generation and increasing concern for the environmental effects of power generation notably the acidification of some lakes in southern Sweden. The UK had a highly developed electricity supply system in which coal supplied 80% of the power demand from a series of large power stations with individual generating units of 500 and 660 MW. These were supported by older stations with smaller, less efficient units which were retained for load-following duty in a complex merit order. Almost all these smaller plants had been built before 1960. The first combined cycles were based on the 100–150 MW class of gas turbines of which the larger units achieved efficiencies of about 52%, compared with 36% for the best coal-fired stations. Very soon the impact of the new combined cycles was felt as one by one the oldest power stations were closed down and demolished so that, within 5 years, there were no coal-fired generating plants with units of less than 200 MW remaining in service. All this was happening at a time when British public opinion was coming to terms with the result of the many privatisations of state-run industries which preceded that of electricity. Public opinion was slow to take up choice of supplier and particularly of gas, which enjoyed a nationwide domestic market for cooking and space heating. The management of British Gas saw itself as a supplier to the domestic market and was taken aback by the sudden rush for gas-fired power generation. If they sold all their gas to the power stations there would be none left for domestic consumers, which was politically sensitive when there was still hostility to privatisation and much criticism of the salaries paid to the directors of the newly privatised industries. All the early combined cycles in the UK had water or steam injection for NOx control. This was because they were designed as dual-fuel systems with distillate oil as a back-up fuel for which they would in any case have to use water injection to achieve the guaranteed NOx levels, whether or not a dry low-emissions combustor was available. The price of gas was raised to power generators who could counter it by accepting an interruptible tariff. This meant that gas supply could be shut off for up to 20 days a year, which meant that developers would have to carry the additional
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cost of designing their gas turbines for dual-fuel operation with provision for water injection for NOx control when burning oil and provide tanks to hold at least 20 days’ supply of distillate. This was the turn of events which brought in other North Sea gas producers joining with power plant developers as their fuel supplier. An 1800 MW combined heat and power scheme serving the Imperial Chemical Industries (ICI) chemical works on Teesside was supplied from a special collector main linking a number of North Sea oil platforms so that the associated gas could be collected for use onshore instead of being flared off at the well heads. Powergen, one of the three generating companies, procured its own gas supply and built a pipeline from a terminal at Killingholme on the south Humber estuary, where they had a 900 MW combined cycle, to their Cottam power station, which was converted to dual firing with coal and gas. From Cottam the pipeline ran south to their Rye House combined cycle near Bedford and, from there, past London to their large oil-fired power station on the Isle of Grain. These moves freed up the gas supply and developers did not have to obtain fuel contracts from British Gas, although the gas supply was mostly transmitted through the British Gas trunk mains. It was the signal to introduce the new gas turbines. One of the first of the new machines was the ABB GT13E2 gas turbine announced in 1992. It was basically a GT13E in which the silo combustor had been replaced with an annular combustor incorporating their environmentally friendly cone-shaped (EV) low-emission burners, and improved compressor and turbine blading gave a 10% power increase. The first installation at Deeside in northwest England was a 500 MW block with an efficiency of 54%. In time it could be seen that this gas turbine was a test vehicle for the annular combustors of the larger Fclass gas turbines that would follow. In 1993, Siemens relaunched their family of F-class machines as three mutually scaled models with an annular combustor replacing the horizontal silo combustors of the previous models. Both ABB and Siemens, with their F-class gas turbines, had dispensed with the silo combustors and adopted an annular combustor arrangement that reduced the cooling load of the hot-gas path and resulted in a short direct path from the combustors to the turbine inlet. The GE and Westinghouse units retained the can– annular combustion system but with a dry low-emissions burner system in each can. By 1995, the first of the F-class gas turbines were in service in Europe and were not without their problems, which were made worse by the fact that the promise of significant improvements in performance attracted many companies to order off the drawing board. Not only this, but with the simultaneous launch of scaled models for 50 and 60 Hz applications there was the likelihood that a design problem in the 50 Hz machine would also appear in the 60 Hz machine and vice versa.
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This is what happened first with the GE F-class machines, and this was further complicated by the difference in operations and physical sizes of the units for 50 and 60 Hz systems. GE had launched the Frame 7F gas turbine first in the USA in 1988 and then, for the Frame 9F for the 50 Hz market, set up the same joint development and manufacture with Alstom as they had with the Frame 9E. The Frame 9F was first installed in 1992 as a simple-cycle unit on an EdF site at Genevilliers in the northern suburbs of Paris. The first utility order was in England in 1993 for two units for a 660 MW combined cycle at Keadby, on the former site of an old power station demolished some years before in the lower Trent valley, about 100 km east of Nottingham, with the aim for entry into service in 1995. When the Frame 9F was first announced, it was as a gas turbine specifically for combined-cycle applications. As such, it would achieve an efficiency of 55% compared with 52% which was being reported by operators of the combined cycles then coming into service in the UK and elsewhere. Marketing in Europe and Asia was with GEC Alstom and almost 30 gas turbines were in effect ordered off the drawing board before Keadby went into operation. By then, GE had announced upgraded versions of both machines as Frame 7FA and Frame 9FA. The initial problems which developed on the Frame 9F were confined to that gas turbine and were the result of a specific issue of manufacture with one European supplier of the rotor tie bolts. It did not affect the Frame 7F gas turbines assembled in the USA nor any of the upgraded FA machines. They had entirely different problems with materials used in the power turbine stages and, because of the different operating patterns, physical sizes and synchronous speeds, the Frame 9FA started to fail at about 1000 h and the Frame 7FA at 10 000 h. A massive repair programme was launched around the world and several actions were taken to alleviate the problems for different operators. By the end of 1995 all the problems had been resolved in both systems. GE marketing of their F-class gas turbines resumed shortly afterwards. GE were not the only supplier of F-class gas turbines to face problems. Mitsubishi had a problem with turbine inlet blade geometry on the 701F at full load which was not difficult to correct and only affected the first four machines at Wang Noi, Thailand. Siemens had combustor vibration, again on full load, which was simply a matter of fixing asymmetrical collars around some of the burners to disturb the parallel flow leaving them. Alstom had a problem of cooling in the second-stage turbine of their upgraded GT24 and GT26 at their introduction in 2001 which had wider implications than simply finding a solution to the problem but, by the summer of 2004, these problems had been resolved and a more powerful gas turbine has resulted with scope for further upgrade in the future. GE’s problems were the first and, since they covered so many operating gas turbines in both markets, they had the greatest influence on what followed. It took some time for the market for the F-class machines to pick up, but there were two consequences for the industry at large: in reorganisation and in gas turbine testing.
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First was the reorganisation of the gas turbine industry which has left four major players in the market for large combined-cycle power plants. It started with the break-up of European Gas Turbines, the gas turbine production company jointly owned by GE and Alstom, with factories in Belfort and Bourogne in eastern France, Essen in Germany and Lincoln in the UK. Alstom relinquished their GE licences and retained the Lincoln and Belfort works, except for the gas turbine production line at Belfort and the offices associated with it. These with the Bourogne and Essen works were incorporated in a new company GE Energy Products Europe (GEEPE). Later Alstom and ABB would merge and, in 2000, ABB would pull out of power generation and become an electronics company providing control equipment to the power and process industries. Alstom remained as an infrastructure company with its primary interests in power generation and rail transport. The final act was the takeover of Westinghouse non-nuclear power business by Siemens in 1999. This brought to an end the Westinghouse–Mitsubishi–Fiat partnership, with Mitsubishi retaining the large 50 Hz machines and the right to 60 Hz gas turbines that they had developed. Fiat pulled out of gas turbine manufacture and joined with Siemens as part of the Turbocare International Maintenance Group. The second change was that the industry could see that there had to be a better way of testing these very large gas turbines. Deregulation of electricity supply which created the independent power producers provided the answer. In the past, whenever a new large gas turbine was introduced, the manufacturer would seek, in Europe and North America, a first customer who would be prepared to give them access to their site for, say, the first 6 months to take performance measurements and to make any adjustments to what was in effect the production prototype. Since all these large gas turbines were destined for the combined-cycle market, the logical development would be to build their own power station. Deregulation brought an end to what had become an inherently unsatisfactory arrangement. The factory test stand, which allowed for a no-load test of a completed gas turbine just to check it out mechanically and to measure the temperature distribution, has been superseded by a load test of the gas turbine and generator in a specially built facility which would in reality be an independent power station owned by the manufacturer, who would be able to conduct extended load tests and to sell the output to the local utility just like any other independent power producer. Siemens built the Cottam development centre in England but have used it not so much as a test of their large 50 Hz gas turbine but rather as an evaluation of a combined cycle with a Benson once-through heat recovery boiler in a utility environment. Mitsubishi built a complete power station at their Takasago works as a test site for their steam-cooled M501G. The gas turbine is arranged in a combined cycle with a separate steam turbine and generator and sells its output to Kansai Electric.
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The power sales agreement has allowed a number of weeks a year for testing and, in 2 years, Mitsubishi had periods of several weeks’ operation with a steam-cooled rotor for the planned M501H but have since not continued with the development. Alstom installed a GT26 gas turbine in a bay of their factory at Birr, near Baden, Switzerland. They also set up an outdoor stand for the smaller GT8C2, feeding into the same busbar. Only one of the gas turbines can be operated at a time. Both engines are permanent units used for testing components and major design improvements. Just as the switch to annular combustion systems allowed the European manufacturers to develop more powerful designs running at higher temperatures, so the American manufacturers with their can–annular combustion systems moved to steam cooling to reduce the cooling air requirements. Steam cooling was applied to the transition ducts, sending the hot gas from the combustion chamber to the turbine inlet. Since there are 16 combustion cans, there are 16 steam paths between the two headers of the 60 Hz machines. The steam path through the gas turbine is integrated with the intermediate steam pressure and operates in parallel with the reheater when operating at full power. Compared with the air-cooled units on which they were based, steam cooling achieved a large increase in output at a higher turbine inlet temperature. The first units to attempt steam cooling were announced by Westinghouse and Mitsubishi in 1995 as the W501G and the M501G. The first Westinghouse unit was completed in 1998 and went into service at the Lakeland Electric power plant near Tampa, Florida. Initially it ran for 2 years in a simple cycle with a small oncethrough heat recovery boiler supplying cooling steam. It was later developed into a combined cycle which went into operation in the summer of 2001. The period between the installation of the Lakeland W501G and its conversion into a combined cycle spanned the takeover of the Westinghouse non-nuclear power business by Siemens and the conversion to combined cycle was a joint venture with Siemens factories in Germany contributing part of the steam turbine. The completed power plant went into commercial operation in April 2002. Mitsubishi also built a steam-cooled gas turbine and installed it in a purpose built combined-cycle power plant at their Takasago works, near Kobe, Japan. With two power systems operating at 60 Hz in the south and at 50 Hz in the north of the country, they also developed the M701G and installed the first two in a 900 MW combined cycle at Tohoku Electric’s Higashi Niigata station in 2000. Most of the steam-cooled gas turbines are installed in the USA, although the first contract to Mitsubishi was from Korea Electric Power Corporation for an independent power project in the Philippines. Located at Ilijan on the main island of Luzon near the city of Batangas (Fig. 2.5), it was one of three combined cycles built in the area to provide a market for the Malympaia gas field 450 km offshore, which was discovered in 1990. The plant consists of four gas turbines and two steam turbines arranged in two 600 MW blocks and went into operation in June 2002. The other steam-cooled unit is the GE Frame 9H in which steam cooling is also
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2.5 Ilijan, Philippines: inside one of the M501g packages at the power station looking towards the intake with the steam manifolds nearest the camera.
applied to rotating components. The first unit was installed in a combined cycle in the UK at Baglan Bay, near Swansea (Fig. 2.6). It is the only example of its type in operation. Tokyo Electric Power have ordered three units for their Futtsu, Tokyo, site, but these will not be in operation until 2008 at the earliest. The first Frame 7H, a scaled version for the 60 Hz market, is under construction at a site in California. Although a number of steam-cooled gas turbines have been installed in the USA and Japan, there has been very little interest elsewhere and none in the 50 Hz market for a larger unit outside Japan until, in October 2006, Electrabel ordered three of the uprated M701G2 to be supplied in three single-shaft blocks for a new combined cycle at Morata de Tajuna, in Spain. Steam cooling inevitably ties the gas turbine into the steam cycle which complicates start-up, but Mitsubishi use auxiliary boilers that provide coolingsteam supply to the gas turbine until the steam turbine is up to speed and the reheater flow is firmly established. The M701G is not expected to extend significantly the start-up time to full load. However, there is another issue which is of growing importance in the European and Asian markets and that is reliability. Development of the F-class gas turbines was not without problems, but all four companies have put it behind them and report F-class gas turbine reliability up to the levels of the preceding E-class machines.
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2.6 Baglan Bay, UK: the first and only commercial installation in the power station of the GE Frame 9H gas turbine in a 480 MW combined cycle officially opened in September 2003.
The designation H in the type name is not indicative of steam cooling, but rather of the turbine inlet temperature. In September 2005, Siemens announced the SGT5-8000H, a 340 MW gas turbine without steam cooling and intended for application only in a combined cycle. Furthermore the combined cycle will be supplied only with a Benson heat recovery boiler and the target efficiency is over 60%. Initial testing of the gas turbine at a power station in Germany is intended to validate the design, and only then will it be converted to a combined cycle. Both H-class gas turbines are to be marketed only as combined cycles, but development has come at different times. Baglan Bay had been in commercial operation for nearly 2 years before the new Siemens gas turbine was announced, and market conditions have significantly changed. Development of the Frame 9H had started in the early 1990s when it was seen as a logical step forwards from the F-class machines for base-load duty. Baglan Bay effectively continues commercial testing of the Frame 9H. The argument has always been that it would require optimisation of the steam turbine to push the efficiency over 60% and that is expected to be achieved with the first commercial order in Japan in 2008. Siemens, on the other hand, have designed a combined cycle which is flexible and clearly aimed for 60% with a combination of a higher temperature and therefore more efficient gas turbine, and a much higher steam pressure which again achieves a higher efficiency on the steam side. With this arrangement, 60% is not impossible given that the stated efficiency of the current single-shaft combinedcycle block with the SGT5-4000F is 58.5%. What is different is that the combined cycle for the new gas turbine is designed for greater operational flexibility. For the F-class the preferred form of a combined cycle in Europe is now as one
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2.7 Connah’s Quay, near Chester, UK: one of the first stations with single-shaft blocks to be installed in Europe with four 390 MW units. (Photograph courtesy of GEEPE.)
or more identical single-shaft blocks. Some of the first were installed by GE at Connah’s Quay, near Chester in northwest England with four units (Fig. 2.7), and at Eemscentrale, at Eemshafen, The Netherlands, with five units and Gent Ringvaart, with a single unit in Belgium which went into service in 1997. Eight single-shaft units were installed at Black Point, Hong Kong. The majority of single-shaft systems have been supplied in the 50 Hz market, by the European manufacturers. Each single-shaft block can be supplied as a standalone 400 MW power station or in a group of two or three separate units with shared facilities such as water treatment and control room. The first European-designed installation was Siemens’ King’s Lynn project in eastern England (Fig. 2.8), which defined the basic arrangement adopted by both European manufacturers. The gas turbine is directly coupled to the generator and at the other end there is a clutch linking it to the steam turbine, which can then be separated at shutdown. The gas turbine exhausts straight into the heat recovery boiler at one end and the steam turbine is exhausting axially into the condenser at the other. With this arrangement there is no need for an auxiliary boiler since the heat recovery boiler can supply gland sealing steam to the turbine which at start-up is disengaged from the power train by the clutch. Normally the only visible departure from a completely standard design would be in the heat recovery boiler and in the cooling system. The boiler is frequently a separate contract and may be chosen because of customer preference for a
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2.8 King’s Lynn, UK: the first single-shaft block for the Siemens interim Model V93.4, which set the basic design for the many blocks that have since been built with the SGT5-4000F.
particular supplier or the existence of local manufacturing capability, or because of the operating arrangements, whether base load or mid-load requiring frequent stops and starts. The cooling arrangement is either an air condenser as at King’s Lynn or a wetcooling system, depending on the availability of water. A third variant is the hybrid unit in which the water is initially cooled in a heat exchanger mounted between the wet section and the fan before it falls into the wet section. The arrangement has advantages on sites beside busy roads and bridges since the dry precooling lowers the temperature in the wet section and reduces the formation of vapour plumes which could present a severe traffic hazard at certain times of the year. Several American operators have found it quicker and easier to obtain a licence for an air condenser system where there may be contentious issues concerning water extraction. At Hays County, Texas, with four 250 MW single-shaft blocks, treated sewage effluent is used as a cooling medium on two blocks, and air condensers are used for the other two. King’s Lynn went into service in November 1996. The first single-shaft combined cycle to be installed in the USA was at St Francis, Alabama, as the first of two 250 MW blocks of the Siemens 60 Hz Model V84.3 gas turbine in 1999, with a second block following 2 years later. The Alstom GT24 single-shaft blocks were the first attempt to produce a standard power plant based on a common power train. In this case the plant is rated at 250 MW for the 60 Hz market. The power train consists of a gas turbine, generator and steam turbine on a single shaft with the gas turbine feeding into the
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heat recovery boiler at one end and the steam turbine exhausting to the condenser at the other. For these plants the heat recovery boiler is a two-pressure design with a oncethrough high-pressure section operating at 160 bar at 540 °C, which is the highest operating pressure for a combined cycle anywhere. The low-pressure section is a conventional drum type. The single shaft is now the most common arrangement for a large combined cycle and manufacturers have made considerable effort to refine the design and to achieve a standard power train system which can operate under all conditions with high reliability. Furthermore operators can have a common basic design for all their power plants with all the advantages of a common spares inventory and ease of maintenance. Flexibility has become more important for the combined cycle as more have been built to meet system growth and to replace old steam plants at the end of their lives. They cannot all be built for base-load duty; somebody has to provide the power for peak demand and that has always required a plant which could run up to full power for 12 h or less on weekdays and may be shut down overnight and at the weekend. Another factor is the increasing renewable energy capacity in many countries. There has always been renewable capacity in the hydropower plants and pumped storage schemes, but water can be stored. Germany has one of the largest components of wind energy, on its system, with over 14 000 MW at the end of 2005, and wind, like electricity, cannot be stored; therefore a back-up power system is required that can respond quickly to changing wind conditions which can affect the amount of power produced at different times of the year. As gas turbines have increased in output, the steam pressures have risen and the high-pressure section of a three-pressure reheat cycle can be up to 135 bar at 560 °C. The F-class gas turbines have all been fitted with variable-inlet guide vanes as a control measure at start-up and also to allow them to run at part load. This could be simply a national requirement to carry a certain amount of spinning reserve for system security, or to run down to part load on weekday nights. This has shown up problems with the horizontal natural-circulation boilers as they are moved to mid-load operation with up to 200 starts/year. This has come to light with the increasing contribution of combined cycles to the power supply. At the end of 2005 in the UK, gas provided over 40% of electricty supply; yet 15 years earlier the country had depended 80% on coal. With the advent of nuclear power, there followed the concept of pumped storage to compensate for their inflexibility of operation by holding up the load factors overnight. If water was pumped from a lake to a reservoir constructed on a hill top, it could be run down to provide peak power during the daytime. In fact, these plants are often used to cover the start-up of gas turbine plants at times of system emergency when a power plant trips out. There is now in effect a merit order of combined cycle. At the top are the single-
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shaft combined cycles, many with horizontal natural-circulation boilers and with the lowest production costs at a thermal efficiency between 56% and 58%. These would be considered base-load plants although, as in some parts of Europe and the USA, they may be required to run less frequently because of the contribution of large nuclear and modern coal-fired stations. Below these are the combined cycles of the E-class gas turbines built between 1980 and 1995, with an efficiency of 50–54%. These have multishaft configurations with gas turbines from 95 to 150 MW. In Europe at least, most of these have vertical heat recovery boilers and single- or dual-pressure steam cycles with highpressure outputs between 50 and 90 bar. Many of these have for several years been engaged in load-following duties and operating daily in perhaps two 4 h sessions. The same division of boiler design exists between Europe and North America as with gas turbine design. Almost all the combined cycles have horizontal naturalcirculation boilers, and attempts to operate a similar merit order have shown up serious problems with the horizontal-boiler designs. At the higher steam pressures there is the additional problem of the time taken to start up from cold. These boilers were designed initially from the original combined-cycle concept with a small gas turbine as a base-load feedwater heater. With further development they became the standard format for the combined heat and power schemes built under the PURPA directive. As such, these plants depended on steam demand for a continuous process with perhaps only 1 or 2 starts/year which the horizontal boilers were well able to handle. As soon as these older combined cycles go into mid-load operation the problems start, with fatigue failure of welds particularly between tubes and drums and consequent loss of availability. The exceptions are the small number of plants which have once-through boilers of low thermal inertia and which were designed for mid-load duty in the competitive merchant plant market. Until now the performance improvements which have raised the efficiency of a combined-cycle plant have been nearly all due to the gas turbine. Gains in efficiency which come from the steam cycle are the result of the higher gas turbine output and the ability to support higher steam pressures and temperatures, together with the recovery of various waste heat outputs from the gas turbine fabric. Preheating fuel to about 160 °C is a common practice with all combined cycles. For the Alstom GT24 and GT26 the pressure ratio of 32 to 1 means that air bled from the compressor for turbine blade cooling must itself be cooled giving up heat to the high-pressure steam cycle. On the steam-cooled gas turbines which all have the can–annular combustor system, part of the the returning flow to the reheater is connected to the inlet manifold of the transition ducts, and the outlet is returned to the reheater outlet. Experience over 50 years has shown us that the combined cycle is inherently a flexible system which can be operated in different ways over its lifetime. This is a feature that we cannot afford to overlook in a system which is turning more to gas as the fossil fuel of choice.
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3 Some early schemes
The first combined cycles were built at a time in Europe when the electricity supply industry in many countries was in state control and the power stations were mostly large steam plants either coal or oil fired but, even as early as 1960, there were worries about the cost of fuel and the need to improve the efficiency of power generation to meet an ever-rising demand for electricity. A few countries in Europe, which had depended mainly on hydropower up to then, were starting to build thermal power plants either because their hydropower potential was all used up, or as in parts of North America it was too far away to develop economically. So the cost of fuel, at a time of rising electricity demand, provided the incentive for combined-cycle development. The first examples certainly showed improved efficiency, but the results were hampered by the low operating temperatures of those first gas turbines. By 1960, the maximum gas turbine output available for both aero engines and the heavy-frame industrial gas turbines was little more than 25 MW. It was such a gas turbine, the Brown Boveri GT12, which was used for the first European installation, Korneuburg A, which came into operation in that year. All these early gas turbines had low firing temperatures and low exhaust temperatures, which meant that supplementary firing, similar in action to the afterburner on an aero engine, but operating continuously, was required to raise the gas temperature entering the heat recovery boiler so as to produce sufficient quality and quantity of steam for the turbine. However, burning additional fuel was not efficient and it would require a higher power gas turbine with an exhaust temperature around 500 °C to eliminate it. This first plant, however, ran as a base-load unit for 14 years and logged 6000 h/year. It was therefore able not only to demonstrate the performance of the combined cycle but also to impart knowledge of the maintenance requirements of a gas turbine and particularly the life of turbine blades exposed to high-temperature gases. Then 9 years later, in Belgium, a Sulzer N1101 gas turbine rated at 23 MW formed a combined cycle with a fired boiler since the exhaust temperature was less than 400 °C (Fig. 3.1). Angleur was very much built to study the performance of 41 WPNL2204
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3.1 Angleur, Belgium: the Sulzer N1101, an early European gas turbine rated at 23 MW, with multicylinder design and free-standing combustion chamber. (Photograph courtesy of CMI.)
the heat recovery boiler, which was designed for mid-load duty with daily start and stop, and to see how the gas turbine and steam turbine would respond to load changes and faults on either side of the boiler. Initially it was seen that a fault on the steam turbine would not propagate back to the gas turbine and that a common grid fault shutting down both generators would damage neither turbine. Angleur had no bypass stack but was provided with a steam bypass straight to the condenser. There was no need to run the gas turbine independently and so there was no need for a bypass stack which would add to the cost and the maintenance burden. Also the exhaust silencer of the gas turbine was moved to the top of the boiler. Further development had to wait for the arrival of more powerful gas turbines, but these two plants had demonstrated the principles of the modern combined cycle which still hold good today. It would be another 10 years before the availability of large gas turbines rated at around 100 MW and running at synchronous speed would launch the combined-cycle market in the world at large. Gas turbine development in Europe continued to focus on power generation and, by 1973, Brown Boveri had introduced two new models, both of which ran at synchronous speeds. These were the GT11 for 60 Hz markets, launched in 1968, and which was assembled in the USA at the company’s factory in St Cloud, Minnesota, and, in 1971, the GT13 for 50 Hz markets which was initially rated at 62 MW. By 1970, application of the gas turbine as a means to improve the efficiency of power generation was widely accepted. In the USA, both GE and Westinghouse
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3.2 Korneuburg B, Austria: a combined cycle completed in 1980 and still operating 25 years later after a gas turbine upgrade.
had introduced the first gas turbines designed specifically for power generation and related applications and a few combined cycles had been built in the southern USA and Mexico. By 1974, Brown Boveri had uprated the GT13D gas turbine to 76.5 MW which with an exhaust temperature of 491 °C could be the basis of a 120 MW combined cycle. The first order for a combined cycle based on this gas turbine was from the Dutch utility PNEM at their Donge site which went into service in 1975. With an efficiency of 45.6% and with an unfired heat recovery boiler, it was the most efficient combined-cycle plant so far built and pointed to further improvements over the fully fired units with which it then competed. Then 4 years later NEWAG decided on a similar combined-cycle plant to be built as Korneuburg B with an uprated version of the gas turbine from 76.5 to 81 MW and a slightly modified steam cycle (Fig. 3.2). It is an indisputable fact that hot gas rises and that therefore the logical arrangement of a heat recovery boiler should be vertical. This is not now what is found at the majority of new combined-cycle sites but, for these early projects, designers did indeed configure the heat recovery boiler with a vertical gas path. The boiler is the key to the performance of the combined cycle, and the object of its design is to obtain the maximum energy recovery from the gas turbine exhaust. It can be regarded as a stack of heat exchangers with the economiser at the top above the evaporator, and the superheater at the bottom, which is repeated for each pressure level. In a vertical heat recovery boiler the tubes are arranged horizontally across the
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rising gas flow. They are small-bore finned tubes supported in tube plates which hang from the top of the boiler frame. These early boilers had relatively low steam pressures and were therefore of assisted circulation design with pumps in the evaporator section. Two pumps of 100% capacity were generally installed to drive the water through the evaporator and so to ensure that the steam would leave the drum to go to the superheater and not flow back to the economiser. These are small-capacity pumps of which one runs continuously with the other on standby, and they have proven to be extremely reliable in operation. They also contribute to the rapid starting capability of these boilers since they are circulating a smaller volume of water than would be possible with a boiler of naturalcirculation design. As gas turbine outputs and operating temperatures increased, it became possible to capture more energy, first by preheating the feedwater and later by adding a full second-pressure stream of an economiser–evaporator and superheater to recover the maximum amount of the gas turbine exhaust energy entering the boiler. Gas entering the boiler at, say 500 °C, would emerge from the stack at about 110 °C. The steam cycle for Korneuburg B is of this type with the second pressure obtained by booster pumps which are supplied from the low-pressure drum. Condensate returns from the steam turbine to a deaerator which is heated by a pegging steam supply bled from the turbine. The low-pressure feed pump then sends the feedwater to an economiser and thence to the evaporator and superheater. The high-pressure flow is pumped from the low-pressure drum to a second economiser and thence to the high-pressure evaporator and superheater. Korneuburg B was commissioned in 1980 and at the time was the most efficient combined cycle to have been developed so far with a maximum output of 129 MW at a net efficiency of 46.6%. It continued in operation until 2003 when the gas turbine was refurbished, upgraded and returned to service in the autumn of 2004. Combined-cycle development in Europe initially followed two routes: firstly, the fully fired combined cycle, with a small gas turbine integrated into the steam cycle of a coal- or oil-fired steam set; secondly, the unfired combined cycle which was the forerunner of the system in use today. In the USA at this time the combined cycle was considered to be the use of a small gas turbine integrated with the steam cycle of a large power plant as a feedwater heater. The arrival of gas in western Europe had led first to the application of natural gas to the traditional applications of manufactured coal gas for cooking and space heating. Power generation would be a large competing market and initial applications were limited. Some of the new large gas turbines were applied to repowering and to district heating plants, notably in Vienna and Munich. In the fully fired combined cycle the gas turbine exhaust was fed to the burners of the fired boiler. The mass flow through the gas turbine had to match the combustion airflow into the burners. On the way to the burners the gas turbine exhaust passed through a series of heat exchangers which replaced some of the original feedwater heaters of the steam plant.
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3.3 Drogenbos, Belgium: a repowering scheme dating from 1976 and still available as a standby unit on the Electrobel system.
The advantage of this was that the gas turbine would provide additional output both with its own generator and by the reduction of steam bled from the turbine for feedwater heating which gave a small increase in power to the steam turbine. In all, 15 plants of this type were built in Germany and Austria, between 1965 and 1978 and, some 10 years later, ten steam plants were similarly converted in The Netherlands. The advantage of these units was the high efficiency at between 43% and 45% which was a significant improvement compared with even large coalfired plant with high-pressure reheat steam cycles which could only reach 36% with coal. In Austria, by 1974, the first combined cycle at Korneuburg had been operating for 14 years and at an efficiency of 32.6% was no longer economic to operate as a base-load unit. A further application envisaged for the combined cycle was in repowering old steam turbines. The large gas turbines introduced around 1975 were able to support a steam turbine of 30–50 MW such as had been installed in Europe in the late 1940s. These turbines had low-steam conditions with no reheat and a typical efficiency of between 25% and 30%.The new gas turbines under development ran at sufficiently high temperatures that they could support the original steam cycle without the need for supplementary firing. Drogenbos power station in the southern suburbs of Brussels was such a plant (Fig. 3.3). It was built in 1947 with three 37 MW steam turbines which had originally been coal fired and had later been converted to burn oil. Also in Belgium, at that time, ACEC had formed an alliance with Westinghouse, principally in connection with the seven nuclear reactors which were then being built in Belgium, but Westinghouse also produced gas turbines and had developed the 90 MW Model W1101 which was aimed at countries operating on a 50 Hz power system. The first unit was installed at the Drogenbos station in Brussels. Worried
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about the rising price of gas, Inter Brabant, the operator at Drogenbos, decided to convert the simple-cycle gas turbine to a combined cycle. CMI, of Seraing, near Liège, were given the order for the heat recovery boiler and the modification of the power station to connect the new boiler to the best of the steam turbines. The boiler was specifically designed to operate at peak times which would involve running for a few hours twice a day. For this reason a single pressure steam cycle was used which at 51 bar at 460 °C was the highest pressure then attempted for a combined cycle. The repowered plant went back into service in 1976. The output was 119 MW at an efficiency of 42%. Although it had slightly lower output than Korneuburg B, its lower efficiency was due to the use of a single-pressure heat recovery boiler to enhance flexibility of operation. In daily operation the gas turbine could run up to full load in 15 min with the steam turbine reaching full load after about 40 min. This is how it operated for most of its life with, on average, 156 starts/year, each time delivering full power within an hour of pushing the start button on the gas turbine. This is a pattern of operation which has carried forward to modern combinedcycle plants. With larger gas turbines and more complex steam cycles, it is still possible to operate in load-following mode with a daily start-up. It is still possible after an overnight shutdown to bring the combined cycle up to full load of nearly 400 MW in an hour. Several features were incorporated which have stood the test of time and can be seen in combined-cycle plants being built today. Firstly, there is no bypass stack to allow the gas turbine to operate independently of the steam turbine. The gas turbine and steam turbine are regarded as an integrated whole, Instead there is a steam dump straight to the condenser which is used during start up to receive steam as the boiler heats up, until the quality is suitable to be passed to the steam turbine. A second feature was the dry running capability. If, for example, the steam turbine generator developed a fault, the gas turbine could still be operated alone, exhausting through the boiler from which the water had been drained. This was not a problem with the low exhaust temperatures of the gas turbines then available but, as outputs and operating temperatures increased, fewer boilers could be so operated, because it would mean reducing the exhaust temperature of the gas turbine to about 480 °C. The Drogenbos plant was an important reference but the idea was slow to become popular in Europe. Again the combined cycle had to fit into the operating pattern of a state-run utility system operating in a heavily interconnected European network with a growing nuclear capacity that would be running in base load. It would be the district heating plants and a few large industrial combined heat and power schemes that would provide a small European gas turbine market in the years up to 1990. During this time there were few suitable steam turbines available for repowering and, although it was suggested at the time that it would be a natural application for the gas turbine, there were very few opportunities, but it was a difficult market in
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Europe. Those countries with state-owned companies holding a monopoly in power generation, chiefly the UK, France and Italy, showed little interest in the technology. Those which had investor-owned or municipally owned generating companies, mainly Sweden, The Netherlands, Germany and Spain, were more receptive and installed some of the first gas-turbine-powered district heating and industrial combined heat and power schemes. The Republic of Ireland was one country where there were opportunities. It was an isolated network, politically disconnected from a larger network in the six counties of Northern Ireland, and with, in 1980, a maximum electricity demand of about 3500 MW. Until gas was discovered offshore County Wicklow in the mid1970s the only indigenous fuel was peat. Unlike the situation in the UK, there was no domestic gas market and so the only way to exploit this new resource was in power generation which would guarantee a large enough load to allow the supply infrastructure to be put in place. The Marina power station near Cork had two 30 MW steam turbines and had been completed in 1954. In 1979 it was decided to repower one of the steam turbines. Engineers from the Electricity Supply Board had seen Drogenbos, which by then had been in operation nearly 3 years, and awarded the contract for the boiler to CMI. The unit was similar to Drogenbos except that it had an additional preheater section above the economiser which heated the returning feedwater before passing it to the deaerator where it was further heated by pegging steam from the steam turbine before being pumped to the main economiser at the design pressure of 45 bar. The gas turbine in this case was the GE Frame 9B which was rated at 87 MW with an exhaust flow rate of 340 kg/s at 510 °C. The scheme was arranged so that either one of the steam turbines could be used. For this reason there is a separate dump condenser connected in parallel with the steam turbine condensers. Other features followed the Drogenbos arrangements. There was no bypass stack and the boiler was designed for dry running. In fact the gas turbine ran for 500 h on a dry boiler during commissioning. The repowered station went into operation in December 1979. While this was going on in Europe, Westinghouse was commissioning the third of their combined-cycle plants at the Putnam power station of Florida Power and Light, at East Palatka, Florida. The station had four of the W501B gas turbines, each rated at 70 MW and arranged in two blocks with two gas turbines and heat recovery boilers powering one steam turbine. The first block went into service in May 1976 and the second 4 months later in September. For the first 6 years it ran on liquid fuel, mainly residual oil, and was switched to gas firing in the summer of 1982. As in Europe, Putnam was operating in a network with large base-loaded steam plants and was operated as a mid merit plant. Until natural gas was introduced to the site, the plant ran for 2500 h/year with over 200 starts/year. Also in 1982, the Dublin North Wall station was repowered. The station had
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been built originally as a peaking plant with three 15 MW oil-fired steam turbines, two of which had been installed in 1953, and the third in 1964. Repowering was the first application of the 120 MW uprated Frame 9E gas turbine, and North Wall is the only station arranged with one large gas turbine and heat recovery boiler supplying steam to three turbines. In this plant there was a low-pressure evaporator, the drum of which incorporated the deaerator. The pressure of the steam output was at 30 bar at 430 °C, matching that of the original boilers. The repowered station went back into operation in May 1983 and for the next 3 years this, and the Marina station at Cork, ran in base load until a 1200 MW coal-fired power plant was completed at Money Point, County Galway, in 1986. By this time in Europe there were four large gas turbines with operating experience in combined cycles, ranging from the Brown Boveri GT13 at 81 MW to the latest GE Frame 9E at 120 MW. In 1974, Siemens had introduced their Model V94.2 gas turbine to succeed the Model V93.2. Their first installations were in district heating plants in Vienna and Munich. The gas turbine was initially rated at 90 MW which was later increased to 105 MW and eventually to 150 MW. However, orders in Europe were few and far between and it was the growing economies of southeast Asia and Japan that would provide much of the market for the European and American manufacturers until 1990. Gas had been found in southeast Asia, and particularly the Erewan field in the Gulf of Thailand. Countries in the region were developing and there was experience of combined cycle with all the large gas turbines then available in Europe. Gas was piped west to the Malaysian peninsula where it came ashore near Paka, and north to the Thai terminal at Rayong about 150 km south of Bangkok. The first combined cycles were built in the region and came into operation in 1983. At Bang Pakong, about 80 km south of Bangkok, Siemens supplied two 440 MW blocks, each consisting of four of their Model V93.3 gas turbines, site rated at 70 MW, at 32 °C (Fig. 3.4). Four single-pressure heat recovery boilers fed a 160 MW steam turbine. At the time, the extent of gas reserves in the Gulf of Thailand were not fully known and the gas turbines of one block were set up for dual-fuel operation with oil as a back-up fuel, but apart from commissioning on oil the gas turbines have never burned it in commercial operation. In fact, 20 years later, both blocks were still running in base load and at least five large combined cycles and a number of smaller combined heat and power plants were taking fuel from the same source. In Malaysia, Alsthom, who were then a licensee and manufacturing associate of GE and had collaborated with them on the development of the Frame 9E, were awarded a turnkey contract for three 300 MW blocks each consisting of two Frame 9E gas turbines, which were site rated at 103 MW, and a 100 MW steam turbine. These were installed on the east coast of the peninsula at Paka. Much of the output was intended for a steel works being built along the coast to the south.
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3.4 Bang Pakong, Thailand: the country’s first combined cycle which consists of two 440 MW blocks was completed in December 1993 and ran for 22 years. A decision to redevelop the site was taken in 2006.
Japan, Taiwan and later Korea were also installing their first combined cycles and importing LNG from Australia, Indonesia and Abu Dhabi. Japan had an innovative gas turbine industry founded on American licences and with both system frequencies in the country could develop gas turbines for both 50 and 60 Hz operations. Mitsubishi focused on the northern utilities in the 50 Hz network and launched their M701 gas turbine at 130 MW with a dry low-emission combustion system in 1983. Another country that had acquired a gas supply and discovered some of its own was Turkey. In the early 1980s gas was already being piped from Russia to western Europe with branches extending south through Romania and Bulgaria into Turkey. A small gas field was also discovered in Turkey’s European province at Hamitabad, some 100 km north of Istanbul. This site and another at Ambarli near Istanbul were the first combined-cycle sites in Turkey. At Hamitabad, the Turkish Electricity Authority in December 1984 awarded the then Brown Boveri AG, acting in consortium with Turkish civil contractors ENKA, a contract for two blocks each consisting of two of their Type 13D gas turbines and a 100 MW steam turbine (Fig. 3.5). A repeat order was awarded for two more blocks in July 1986. As shown in Fig. 3.5, many of the early combined cycles had bypass stacks between the gas turbine and the heat recovery boiler. In the case of Hamitabad this was to allow the gas turbines to be installed early and to run in simple cycle while the boilers and steam turbines were being erected. Alhough not strictly necessary, and completely absent from the single-shaft blocks which would follow at the end of the century, the bypass stacks are generally indicative of staged construction in a country with high rates of growth of electricity demand.
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3.5 Hamitabad, Turkey: a plant which consists of four 300 MW blocks on a small gas field in the European province of Turkey and was the country’s first combined cycle completed in September 1989.
Many of the developed countries of Europe and North America had seen their rate of growth of electricity demand drop and continue at lower rates from the mid1970s onwards. The nuclear and coal-fired plants which had reduced the use of oil for power generation had also created large reserve plant margins. Growing concern for environmental issues meant that much retrofit work was carried out, particularly on the coal-fired stations to fit FGD systems and low NOx burners. These measures on the largest and newest coal-fired stations did not increase their output but ensured at least that these power plants could stay in operation under the new environmental rules. In the early 1990s, the combined-cycle market exploded in southeast Asia where, in the fast-growing economies of Thailand, Malaysia and Indonesia, rates of growth in electricity demand were of the order of 15%/year. In this situation a 300 MW combined-cycle block would be built by installing the two gas turbines to run in simple-cycle mode during which time 200 MW of gas turbine power would be available, and it would come into operation between 9 months and 1 year from the date of order. The gas turbines would then operate for up to 18 months in simple-cycle mode while the heat recovery boilers and steam turbine were erected. The stack would have a diverter valve in place so that all that had to be done to complete the combined cycle would be to shut down the gas turbine behind the closed damper while the duct connection to the boiler was installed, after which there would be a period to commission the steam turbine and to perform a reliability run of the whole block. The original stack and damper remain as a bypass.
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As the market took off in southeast Asia, so the first steps were taken in the deregulation of electricity supply in Europe. Privatisation of the British electricity supply system which began in 1990 brought about the so-called ‘dash for gas’ in which several combined-cycle power stations were built, including some large industrial combined heat and power schemes. At the same time, all the small coalfired power stations were closed down so that, by 1995, there were no steam plants with units of less than 200 MW in operation in the UK. It was little more than 20 years since the first experimental projects had gone into service in Austria and Belgium and in that time gas turbine development had resulted in more efficient units and cleaner combustion with low emissions of carbon monoxide and NOx. At the same time that the industry had reorganised, it was the gas turbine suppliers who became the combined-cycle designers and builders. This was not surprising given that at the top end of the market the gas turbine builders also were the traditional suppliers of steam turbines, and in one case at least had a boiler division. The pattern of ordering at this time was that the contract would be between the generating company and the gas turbine supplier. It would define the power plant to be built in terms of output, siting conditions, emission standards and responsibility for procurement of balance of plant. Sometimes the gas turbine supplier would procure the heat recovery boiler and at other times the customer would procure it. The first independent combined-cycle plant in the UK was installed in northwest England at Roosecote, near Barrow-in-Furness in October 1991. A group of four engineers of the former CEGB had formed a company to buy a 120 MW coal-fired power plant, which had been closed in 1986, and to redevelop it. The four 30 MW generating sets were removed, the boiler house and stacks were demolished but the cooling system of the original plant was refurbished and three small ancillary buildings were retained, housing the rebuilt control room, offices and workshops. The 225 MW combined cycle was installed in the former turbine hall. It consists of a single Type GT13E gas turbine with water injection for NOx control and a 63 MW steam turbine mounted on either side of a centrally mounted heat recovery boiler. By 1990, combined cycles were generally based on gas turbines of 120–150 MW in the 50 Hz market with up to three gas turbines and one steam turbine. There would be a two-pressure steam cycle with which there would be either a lowprofile wet mechanical-draught-cooling system or an air condenser. The determining factors as to what form the steam cycle would take are the exhaust energy of the gas turbine and the customer’s intended use for the station. If it were intended for a base-load operation, then a two-pressure steam cycle would be used on the assumption that the plant would run continuously for long periods. For a plant that was intended for load-following duty, a single-pressure steam cycle might be used. With only one drum and one operating pressure level the
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3.6 Peterborough, UK: a typical 350 MW combined cycle for northern Europe using E-class gas turbines, which now runs to service the peak demands with over 200 starts/year.
boiler would have a lower thermal inertia and so would heat up more quickly. If the gas turbine could be synchronised and loaded within 15 min, it was clearly in the operator’s interest to have full output within half an hour if the plant was to be run for, say, 4 h during the morning peak, shut down for 5 h, and then started up again to run for another 4 h over the evening peak. This was the typical operating pattern assumed in Europe for the first combined-cycle plants which were installed in utility systems with large coal-fired and nuclear sets providing the base load. It soon became very clear that the repowering of old steam plants which had been among the first applications would not be a lucrative market for the gas turbine industry. Steam power plants with suitable sets to repower were few in number and, in any case, the largest gas turbines available before 1990 were around 100–120 MW capacity with exhaust temperatures of 520 °C or less. Even if a power station had been available with a suitable steam turbine the gas turbine would have to be chosen and the heat recovery boiler would have to be optimised to the existing steam conditions. It was far better to build a brand new combined cycle with a gas turbine, heat recovery boiler and steam turbine optimised to the purpose. Until 1995 the combined cycle was always a multishaft concept: two, three or four gas turbines each with its heat recovery boiler feeding common steam ranges supplying a single steam turbine. A typical arrangement for a combined cycle of the time, based on a 120 MW gas turbine, is shown in Fig. 3.6 which represents the steam cycle at Centrica’s Peterborough power station about 150 km north of London.
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Completed in November 1993, the station was for the first 7 years operated as a base-load station by Eastern Electricity. It is now one of seven combined cycles operated by Centrica. Under new electricity trading arrangements introduced in April 2001 the station is now operated on a daily load cycle to supply Centrica’s mainly domestic customer base in eastern England. Peak time is in the evening as consumers return home from work and a typical operation is to start up at 5.00 pm, to run through to 11.00 pm and then to shut down. In winter time the plant may run through to the following morning to charge up night storage heaters. This pattern of operation emphasises the operating flexibility of the combined cycle over its lifetime, since Peterborough started life in 1993 as a base-load power station. Flexibility is becoming increasingly important as more gas-fired power plants are added to networks. The steam cycle for Peterborough is a typical two-pressure system for a site in northern Europe. The design ambient temperature was 10 °C and the temperature on site ranges over the year from –5 to +25 °C. The station is also set up for dualfuel operation with an interruptible gas tariff which allows for gas to be shut off for up to 20 days a year, during which time the gas turbines burn a light fuel oil. Almost all combined cycles built in Europe, and by European companies in Asia and the Middle East at this time, had vertically configured heat recovery boilers. This is not surprising given the circumstances in which the first combined-cycle projects were developed. They were built on congested urban sites for district heating plants, or on existing power station sites where a vertical arrangement would save space. By the time that the combined-cycle market started to open up in Europe and the Far East at the end of the 1980s these early projects had all been operating for between 5 and 10 years and had demonstrated their operational flexibility and reliability. However, there was increasing competition from American developers who had fixed ideas as to the design of the heat recovery boiler. They had used horizontal natural-circulation boilers on their PURPA combined heat and power schemes with gas turbines of which the largest was rated at 105 MW and therefore they could be used on the combined cycles behind the larger 50 Hz gas turbines. The first horizontal boilers appeared in England in 1991 but, 4 years earlier, a vertical natural-circulation boiler had been developed by Austrian Energy and Environment (AEE) and installed behind a 150 MW gas turbine at Leopoldau district heating plant in Vienna, and a number were also installed on combined cycles in Indonesia and Singapore. The argument against the vertical boiler had always been that it was not natural circulation, and that being vertical it was more difficult to erect and needed long expansion loops in the downcomers and risers between the evaporators and the circulation pumps all of which would add to the cost. Vertical natural-circulation designs did not really come into favour until the arrival of the larger F-class gas turbines wich were capable of supporting a threepressure steam cycle. A typical steam cycle for the early F-class would have
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100 bar for the high pressure, 30 bar for the intermediate pressure and 5 bar for the low pressure. The intermediate- and high-pressure economisers were interspersed through the stack of heat exchangers, which in turn meant that the evaporators were lower in the stack. The drums mounted on top of the boiler frame would now have a large static head for each evaporator which would replace the circulating pumps. Most of the early European combined cycles used vertical assisted circulation boilers that were designed for dual-fuel operation. After 1995, as gas supplies seemed more assured, more plants were built for gas firing only with consequently lower capital cost. Peterborough is one of several combined cycles in the UK which have been supplied with an air condenser. The station is situated on the edge of the city with open farmland on two sides. There is no convenient water body for cooling so that an air condenser with 16 cells is used. The combined cycle, of course, has a much smaller cooling load than a steam plant of the same capacity. In this example the steam turbine is only 120 MW as it contributes only about one third of the total output Air condensers, of course, add to the auxiliary load of the station and were previously used mainly in desert areas, but they have advantages in Europe and North America where either there is no available source of cooling water or difficulties in obtaining water extraction rights for cooling. One advantage over wet cooling systems is that there is no low-level vapour plume, which in certain weather conditions could give rise to fog on roads passing the station site and create a traffic hazard. A variant of the wet mechanical-draught-cooling tower is the hybrid unit which has an air-cooled dry section immediately below the fan that initially cools the water and passes it to the wet section below; in most weather conditions, this is cool enough not to cause a vapour plume. Several of these units have been installed at plants on urban sites and beside motorway bridges. Combined cycles in Finland, Russia and other countries with extremely low winter temperatures have the additional problem of intake icing to contend with. In very cold climates there could be a separate preheater stage in the boiler as part of a closed loop to the gas turbine intake which uses ethylene glycol as the working fluid as is done at many sites in Finland. In a less severe climate this could be a separate water loop, perhaps fed by a bleed from the steam turbine. Some plants may have district heating condensers fed from the steam turbine with just a small condensing tail at the peak heating time. The amount of extraction will vary with the time of year so that in summer time there could be no heat load and the plant would be running as a pure combined cycle with maximum electrical output. In some countries, notably Indonesia, combined cycles installed on coastal sites will have a steam turbine with a bleed going off to a multistage flash distillation unit so that seawater can be distilled to provide demineralized water for boiler
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make-up. Where this has been done, it is with combined cycles with 130 MW gas turbines in 3+3+1 configuration, giving a steam turbine of nearly 200 MW capacity. As more experience of gas turbine operation was gained, it could be seen that not only did the output vary with ambient temperature but also there would be a degradation of output with time due to compressor fouling. The best filters will still pass fine dust and aerosols which can deposit on the first compressor blades and cause a sharp drop in output over a few days. Online compressor washing came into the market in 1991. For some time, gas turbines had been equipped for offline washing, and among operators it had become a matter of principle that after any outage a compressor wash would be performed before the gas turbine was restarted. There are many different causes of fouling. The extent to which gas turbine output degrades with time depends on where it is located and the quality of the intake filters and their maintenance. On an urban site beside a busy road junction leading to an industrial estate, a combined heat and power plant serving it could see a complex cocktail of traffic fumes and process emissions which could cause the loss of 2 MW output a week from a 100 MW gas turbine. In a rural site an ostensibly clean environment could carry pollen and fine dust particles at different times of year, and on coastal sites there is the problem of salt spray. Online washing does not completely eliminate fouling but regular washing can greatly reduce the rate of fouling. A daily wash can recover, say, 75% of the power loss since the last online wash and the same each time so that the period is extended between offline washes. The online wash system is a series of nozzles strategically placed in the intake duct such that the greatest wetting of the first-stage blades can be achieved. The nozzles are supplied from a manifold fed from a mixing skid which prepares the detergent and solvent in the correct mixture. Many companies can supply the detergents but only a few provide the complete kit of nozzles and mixing skids. A problem with online washing is the pressure at which the cleaner is delivered to the compressor intake. Too high a pressure, and therefore flow rate, and a high frequency of washing can lead to blade erosion particularly if a high rate of intake air flow forces the cleaning fluid to concentrate at the blade root. Consequently low-pressure systems and nozzle designs have been developed to provide complete wetting of even the largest gas turbines. Until 1994 there was no change in the general concept of what a combined cycle should be. Such increases in power and efficiency as had been made were the result of improvements to the gas turbines. The best efficiency with the 150 MW gas turbines was about 52.5% Larger gas turbines operating at higher temperatures were under development and there was talk of higher-pressure steam cycles with efficiency approaching 60%. However, the lessons of these early schemes are important for the future. The design life of these early plants was 25 years and this was confirmed with
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Korneuburg B when it broke down in 2003. The thermal block was judged to be at the end of its life but Alstom had a new block in storage for a GT13D which had never been built and this replaced the damaged unit. A new combustor incorporating the low-emissions EV burners was also installed together with the turbine upgrade package and the unit went back into service in late 2004 with about 10% increase in power over that of the original unit. What is possible now is to apply the technology of the latest F-class gas turbines in compressor and turbine blading and turbine blade cooling to give a small gain in performance without losing the basic flexibility of the original combined cycle. In load-following mode the simpler steam cycles at lower pressures were able to run up much faster than the large steam plants on the network. In a typical operation in a developed industrial county the power plant could start with a 7.00 am run for, say, 3 h and then shut down until 4.00 pm to restart for the evening peak. No fuel is being burned to keep the plant warm during the shutdown period, although the steam turbine would still be warm and would be rotating slowly on its turning gear. Up to about 1994 all combined cycles had been ordered with long-term power sales agreements. A merchant plant has no long-term contract but bids to supply every day on the basis of its generating cost and availability. Contracts could run for several weeks to cover, say, a refuelling and maintenance outage at a nuclear plant or simply to provide mid-load power on weekdays. Another contract could be to an industrial customer to supply power for a particular period of production. These are all situations demanding flexibility of operation. The challenge has been to provide it with combined cycles with the larger F-class gas turbines which because of their higher power density and higher operating temperatures have been designed mainly for base-load operation with horizontal natural-circulation boilers and high steam pressures, shutting down once or twice a year according to the demands of maintenance. However, what happens when these combined cycles are overtaken in turn by even more powerful gas turbines in future? This makes it all the more inportant that future combined cycles be designed for greater flexibility.
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4 Gas turbine developments
Of the three gas turbines that were developed at the end of the 1930s, two were designed as aircraft engines, and during the Second World War this line of development continued up to 1945. Gas-turbine-powered aircraft entered service with the British Royal Air Force as the war came to an end, and for a long time afterwards the public perception of the gas turbine was as the jet engine of an aircraft. After the war, gas turbine technology was made available to the USA and other countries, and it was principally those countries with a significant aircraft industry who continued the development of the gas turbine as an aero engine. Some further applications in transport were studied. In England, the Rover Car Company experimented with a gas-turbine-powered car and, in Switzerland, Brown Boveri designed a gas-turbine-powered locomotive. However, neither went into commercial production. As understanding of the technology grew, the first industrial gas turbines went into production. Ruston, at Lincoln, some 250 km north of London, began development in 1946 of a small gas turbine which, in 1949, was announced as the Model TA1750. This unit was primarily intended as a mechanical driver for the oil and gas industry. Its initial rating was 970 kW with a design speed of 11 800 rev/min and the turbine inlet temperature was 726 °C. The first unit went into service in 1953 and, in the next 30 years, 820 were sold around the world. By then the output had been increased to 1390 kW with the turbine inlet temperature at 825 °C. In the USA, GE had spearheaded gas turbine development with the Frame 3 which was introduced as a mechanical drive unit rated initially at 3730 kW at 7100 rev/min and had a thermal efficiency of 26.4%. It was a two-shaft design for mechanical drive application on pipelines, on production platforms and in process industries. A few single-shaft units were supplied for power generation, and some found their way into the early American combined-cycle projects which were based on large steam plants with small gas turbines incorporated into the steam cycle as a feedwater heater. Sweden, which had remained neutral during the war, had an aircraft industry and 57 WPNL2204
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in 1952 had started development of a gas turbine engine for the Swedish Air Force. This engine was successfully flight tested but, when it came to choosing an engine for a new generation of fighter aircraft, the Swedish Air Force opted for the RollsRoyce Avon. The developers, Stal Laval Turbin AB, located at Finspong, some 150 km south of Stockholm, decided to adapt their design for power generation and industrial applications. The modified engine was launched in 1957 as the GT35 and is still in production 50 years later. The majority of applications have been to power plants and industrial combined heat and power schemes, but some have been applied to mechanical drive and several have been installed on North Sea oil and gas platforms. It has been progressively upgraded over the years to its present rating of 17 MW, and the can–annular combustor system has been fitted with the ABBdesigned low-emissions EV burners since 1995. Now that the Finspong works is part of Siemens Industrial Turbomachinery, this gas turbine has been renamed the SGT500. By 1960, the first long-range aircraft with pure gas turbine engines were coming into service with the airlines: the long-range Mk 4 Comet with four Rolls-Royce Avon engines, and the short-range French-built Caravelle with two Avon engines, in Europe, and the Boeing 707 and Douglas DC8 in the USA each with four Pratt & Whitney JT4 engines, on trans-Atlantic and transcontinental services. These aero engines were of a size at their initial ratings where they could be adapted for use on the ground at constant output as a compressor or generator driver. Rolls-Royce had also investigated using the Avon as an industrial engine running on oil or natural gas. Then in 1963 a power system failure in the northeastern USA, extending from New York city to Toronto, in Canada, led to the start of aero engine application to power generation. An aircraft engine was a compact design of low inertia and quick starting. Therefore, it was argued, if there was another failure of the power system, surely a gas turbine generating set could run up to full power in no more time than if it were on an aircraft. The following year Boston Edison ordered four gas turbine generator sets from the UK. Each consisted of a Rolls-Royce Avon engine and associated power turbine linked to the generator through a synchronous self-shifting clutch. Manufactured by SSS Gears Ltd at Sunbury on Thames, some 40 km southwest of London, the clutch separated the gas turbine from the generator so that it could operate as a synchronous compensator at times of low power demand over long transmission lines. Besides these dual-purpose units a number of gas turbine peaking sets were installed consisting of two aero-derivative engines driving at either end of a common generator. Three such stations were installed in New Zealand in 1982 with the arrival of Maui Gas in the North Island (Fig. 4.1). At that time hydro stations on the South Island supplied the North through an HVDC link. Two of the plants were installed in the south of the North Island to cover periods of low rainfall or power station or transmission line outages in the South Island.
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4.1 Whiranaki, New Zealand: a plant with four 30 MW JT4 twin packs installed in 1982 to provide back-up for the HVDC link transmitting power from the South Island.
By 1970, the arrival of the wide-bodied aircraft with large turbofan engines gave further stimulus to the market for aero-derivative engines in power generation. The core engine without the fan section was used and, as with the earlier aero engine designs, the combustion system was modified to burn gas, and a bespoke free power turbine in the exhaust duct was the basis of a larger and more efficient generator package of between 25 and 33 MW depending on the gas turbine type. The main engine types were the Rolls-Royce RB211 from the Boeing 747 and Lockheed L1011, and the GE CF6 series from the DC10 tri-jet and the first Airbus models, from which were derived the LM2500 (Fig. 4.2) at 25 MW and the LM 3000 at 33 MW. These engines competed directly with the GE Frame 5 industrial gas turbine, which had also been upgraded in 1970 in a single-shaft version for power generation applications. The large markets for aero-derivative engines have been in the oil and gas industry. Their compactness was an advantage on an offshore platform and they have been installed on oil and gas production platforms all over the world, both to drive compressors and pumps and to provide power generation. The large aeroderivatives, notably the GE LM 6000 and Rolls-Royce RB211 and Trent, are now the main compressor drivers on the world’s gas pipelines. These types, on account of their high efficiency, have also found application in generating sets and also a growing number of industrial combined heat and power schemes. Of the smaller aero gas turbines, only the Allison Model 501 at 3.5 MW has been widely used for industrial combined heat and power schemes in the USA, and also through its licensed packagers, principally Centrax Ltd at Newton Abbot in southwest England, for Europe and the Middle East.
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4.2 Air New Zealand, which is one of several airlines that maintain aero-derivative gas turbines for industrial customers. Shown here in the Auckland base is an LM2500 for a Pacific Island utility.
Few industries installing a combined heat and power scheme for the first time had experience of gas turbine operations and the attraction of an aero-derivative gas turbine was due to not only its flexibility of operation, because of its rapid starting capability, but also the presence of a large body of experience in the airline industry who operate and maintain these gas turbines. Many airline operators opened their maintenance shops to industrial and utility customers in their countries to provide aero-derivative gas turbine maintenance services. Outside the aero engine scene, gas turbine development did not really improve until the late 1970s when large gas turbines capable of operating at synchronous speed became available. The peaking and emergency sets using aero engines had shown that they could be adapted and applied to power generation which, at constant output and ambient conditions on the ground, was vastly different from the normal operating environment for which the engines had originally been designed. Some of the early heavy-frame machines had been applied to power generation but, in comparison with the aero engines, were low-temperature machines, running at high speed and therefore requiring a gearbox to drive a generator at synchronous speed. The challenge was to produce a gas turbine running at 3600 rev/min for 60 Hz and at 3000 rev/min for 50 Hz generators. In 1960, the largest gas turbines were rated 25 MW; by 1970 the largest units in Europe were 50 MW, but larger gas turbines were under development. In fact, the first gas turbines operating at the 3600 rev/min had already appeared in the North
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American market and it would only be a matter of time before the equivalent 50 Hz models would be launched in the European market. In fact, the first of the so-called E-class could be considered to be the GE Frame 7 which was announced in 1968 at an initial rating of 55 MW and by 1971 had been uprated to 80 MW at 32.1% efficiency as the Frame 7E. This gas turbine is still in production as the Frame 7EA at an ISO rating of 85.1 MW, with an exhaust temperature of 536 °C. It was the first GE gas turbine to be designed to drive the generator directly at synchronous speed and it is this property and exhaust temperatures of 500 °C or more that really define the E-class rather than absolute power. Brown Boveri in 1968 had introduced the first of three gas turbines of a new compact design characterized by a single shaft driving from the cold end, which had a straight-through exhaust duct to the heat recovery boiler, with a single silo combustor mounted on top of the casing and housing a single burner. This was the Type 11, rated at 49.5 MW and running at 3600 rev/min. In the following year, Westinghouse introduced the W501A at 66 MW, which in 1972 was scaled up by Fiat to produce the TG50 as a 90 MW unit running at 3000 rev/min. By this time, Westinghouse had uprated their 501A to the W501D at 107 MW and 34% efficiency. Brown Boveri introduced their large 50 Hz machine in 1973 as the Type 13 initially rated at 60.7 MW but, before this in 1969, they had introduced the Type 9 at 35.4 MW and operating at 4500 rev/min and driving the generator through a gearbox for either system frequency. All these large gas turbines were able to support a combined cycle without supplementary firing, but there was growing interest in Europe and North America in another market that was starting to appear: large industries, such as pulp and paper mills, and petrochemical plants, with large process steam loads were looking to install gas turbine combined heat and power units as production expanded and a gas turbine and heat recovery boiler would meet their process steam requirements and some of if not all their electricity demand. Few industries would require upwards of 60 MW of power and there were few opportunities to export surplus power at a fair market price. So there was a definite need for a smaller gas turbine to perform this duty. GE had in 1970 announced the Frame 5P specifically for power generation applications. It was a single-shaft design with a 17-stage compressor and an inlet guide vane. It ran at 5100 rev/min, and so was supplied with a gearbox for either 50 or 60 Hz operation. The Frame 5P was offered through GE and their business associates and, by 1982, more than 2000 had been sold and achieved over 40 million cumulative operating hours. Brown Boveri’s Type 9 was also aimed at this market and a number were sold to district heating plants. Siemens also had a 50 MW gas turbine in the Model V93.2 and were preparing to replace it with a larger unit, Model V94.0, which was announced at an initial rating of 90 MW in 1974. The period from 1968 to about 1980 was one of frantic development in the gas
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turbine industry. Effectively there emerged four basic designs of gas turbine for the electric power market representing the technology of GE, Westinghouse, Brown Boveri and Siemens. 60 Hz machines had been scaled up by European and Japanese licensees for the 50 Hz market, and there were at least ten companies around the world that could supply one of these large gas turbines for a power project or industrial combined heat and power system. Development was given additional impetus by the Middle East war and the resulting oil crisis in the autumn of 1973. While combined cycle held out the prospect of higher efficiency of power generation, and natural gas rarely contained any sulphur at all, the reduction in particular of NOx and carbon monoxide was to become an issue for the gas turbine manufacturers. The basic principle of the gas turbine is that air is compressed and then heated by burning fuel. The hot gas then passes through a turbine which drives the compressor and also the driven unit, in this case a generator. To increase the output of the gas turbine more air must be passed through it and heated to a higher temperature. High-temperature materials from the aero engine technology and manufacturing techniques were developed to produce improved air cooling passages through turbine blades and vanes. As temperatures increased so the tendency of nitrogen in the combustion air to oxidise above 800 °C leads to a visible brown discolouration of the exhaust gases due to the presence of nitrogen dioxide. Reactions to the 1973 oil crisis varied from country to country around the world. The industrial nations of Europe, North America and Japan decided to take oil out of power generation. At the time the alternatives were either nuclear power, such hydropower as could be economically developed, or other fossil fuels, which meant either coal or natural gas. Coal was known to be in abundant supply in many parts of the world but worries about its environmental impact were beginning to surface in North America and Europe. Natural gas was associated with oil and much of it was still being flared off at well heads in the Middle East and elsewhere as a useless by-product. In Europe, natural gas had been discovered near Groningen in the northeast of The Netherlands and in 1964 in the southern North Sea offshore Great Yarmouth. Gas fields were also being discovered in other parts of the world. Important discoveries were made on the North West Shelf, about 100 km off Dampier, Western Australia, in the Bass Strait, between the Australian mainland and Tasmania, and in the Cooper Basin in the middle of the continent. In time, these discoveries would lay the foundations for a growing trade in LNG to supply in particular Japan, South Korea and Taiwan. Also, the mid-1970s saw the emergence of a new social phenomenon: the rise of organised protest against damage to the environment, and in particular gaseous emissions from cars and power plants. Acid rain was a direct consequence of sulphur oxides released in the combustion of coal and oil and carried on the prevailing wind from tall power station stacks. This led directly to the development
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of FGD systems which are now standard equipment on all large modern coal-fired power plants. Natural gas was held to be a clean fuel. It was delivered by pipeline at a high pressure. Unlike coal there was no solid residue to be disposed of, and no energyintensive preparation before it could be used, as was the case with fuel oils and uranium. In 1973 the largest available gas turbines were about 100 MW and the first large gas turbine applications to industry were starting to appear in the Middle East with the power plants for the aluminium smelters in Bahrain and later in Dubai, and a large desalination plant at Ras Abu Fontas, in Qatar. As soon as a market appeared, there was an incentive to develop larger gas turbines and, as these started to be deployed, so the exploration and development of new gas fields gathered momentum. The American manufacturers dominated the early market through promotion of their technology to companies that were their licensees for other energy technologies, particularly nuclear reactors and steam turbines. Among the aero engine companies, neither GE nor Rolls-Royce packaged their gas turbines for mechanical drive applications, preferring instead to leave this job to the compressor manufacturers. Rolls-Royce did package some gas turbines as generating sets at the end of the 1960s but have since taken over the American compressor company Cooper as Cooper–Rolls for compressors and generator packages and more than 30 years later licensed the Swiss company Turbomach to package the RB211 for generating sets and industrial combined heat and power schemes in Europe. Similarly GE placed generator packages with Stewart and Stevenson, in Houston, whom they have since taken over, and their compressor packager is Dresser Rand. GE at this time had all its heavy-frame gas turbine production lines located at Schenectady, in upper New York State. Initially all its industrial gas turbines were manufactured there and these would require gearboxes to be fitted to achieve the 50 Hz synchronous speed. Their largest gas turbine model, Frame 7E, ran at 3600 rev/min which is one of the two commonest 60 Hz synchronous speeds. When, however, it was decided to build the Frame 9 as the equivalent model for 50 Hz networks, the development was carried out jointly with Alstom, at their Belfort factory in eastern France. A factory was set up in the neighbouring town of Bourogne to manufacture rotors for the new gas turbine. The first of the new generation of heavy-frame gas turbines for power generation were launched in Europe, between 1970 and 1975. Brown Boveri, as the combined-cycle pioneers at Korneuburg, were first with the Type 13. This was followed by the first GE Frame 9, which was installed by EdF as a peaking plant on a site near Valenciennes, in northern France. Siemens launched their Model V94.0 with the first installations at district heating stations in Vienna Leopoldau and south Munich. Westinghouse installed their W1101 initially as a simple-cycle unit at Drogenbos power station in the southern suburbs of Brussels in 1975. This gas turbine was one
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of three rated at about 92 MW which were scaled up from the original W501 60 Hz model. Although it was the only one built, the equivalent Mitsubishi and Fiat designs, as the MW701 and TG50 respectively, continued in production and have sold well in Europe, the Middle East and Asia, reaching a final rating of 133 MW. For these new gas turbines there were two design concepts: the American system as presented by GE and Westinghouse, which is reminiscent of the early aero engines with the airflow from the compressor divided into a ring of combustion cans and thence through transition ducts linking them back to the turbine inlet; the so-called can–annular system which has continued to the present day. The two American designs were similar, the only difference being that the Westinghouse gas turbines coupled the driven unit at the cold end of the machine whereas, until their first F-class gas turbines appeared, in 1988 all GE gas turbines drove from the hot end so that the exhaust had to be diverted upwards or to the side to clear the driven unit. The two European manufacturers were frequently accused of designing their gas turbines like steam turbines, and the early models were indeed complex multicylinder assemblies with large free-standing combustion chambers. By 1970 this had given way to the compact structure reminiscent of the aero engine, but with one important difference. The combustion chambers were retained as outboard silos with one unit on the top of the casing for the Brown Boveri models and one at each side on the Siemens design. There were three other features of the European designs which were significant to the future market. The machines all had a cold-end drive, with the generator coupled to the intake end of the gas turbine. This allowed an uninterrupted straightthrough path for the exhaust gases to a heat recovery boiler, which would incur fewer losses. In a single-shaft combined-cycle arrangement this also enables the steam turbine to be connected at the other end of the generator and separated from it by a synchronous self-shifting clutch. The European rotor construction was definitely a follow-on from steam turbine practice. Brown Boveri had a solid forged rotor, which was machined to receive the channels into which the blades were placed. Siemens used individual discs which were machined with the Hirth gear on both faces of the disc so that adjacent discs were solidly interlocked by the gear surfaces. A large central tie bolt completed the assembly. The American designs following aero engine practice used discs with radial retaining keys and secured by a ring of tie bolts. The starting method of the European gas turbines was also different. Instead of a diesel or electric starter motor and a torque converter, both companies used the static frequency converter. This is a solid-state electronic device which works on the generator by pulsing each phase winding of the stator in turn, causing the generator to rotate and accelerate from rest as though it were an electric motor. As soon as the gas turbine has been fired up and is in stable operation the system switches off, the excitation is returned to its normal operation mode and the generator starts to load as the gas turbine reaches synchronous speed.
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The system is elegantly simple with a low maintenance burden, and turbines so equipped have shown superior start reliability in service. The only moving part is the ventilation fan of the cabinet housing the electronic racks. On a multishaft combined cycle with two or three gas turbines, one electronic starter might be shared between all gas turbines but, for a station with two or more single-shaft blocks, each would have its own starter system. Although it would be nearly 30 years before the arrival of the single-shaft combined cycle on the scene, the electronic starting system could have been made for it and this is now the universal starting arrangement for all the large F-class gas turbines. By 1980, the four gas turbine models had been defined that, in their 50 and 60 Hz versions, would be the basis of the designs that followed. Very quickly after introduction these large gas turbines were produced in upgraded versions. By 1983, Brown Boveri had upgraded the GT13D from its initial rating of 60.7 MW to 89 MW with a turbine inlet temperature of 990 °C. In 1984 they introduced the GT13E rated at 149 MW with an efficiency of 33.7% and exhaust mass flow of 506 kg/s at 525 °C. The GE Frame 9B, introduced in 1975 at 85 MW, had by 1983 become the Frame 9E at 106.7 MW, which by the end of the decade would be further increased to 123.4 MW. Siemens who had introduced their Model V94 at 90 MW had in two steps raised the output to 125 MW and by 1990 had raised it further to 150 MW. Of the four major manufacturers, Siemens did not have a gas turbine for the 60 Hz market. The Model V84.2 was not launched until 1984 as a scaled derivative of the existing 50 Hz Model V94.2, with an initial base-load rating of 82 MW on natural gas, and an exhaust temperature of 512 °C. During the 1980s, the main developments were in the design of low-emissions combustion systems (Fig. 4.3 and Fig. 4.4). At the end of the 1970s an American standard for NOx emission was defined at 75 vppm at 15% oxygen. It was not a particularly severe standard and gas turbines that could not meet it could use water or steam injection to achieve it. However, this has disadvantages because, although there is a power gain from the additional mass flow of the water or steam, it is achieved at a lower efficiency as the object of the injection is to reduce NOx by diluting the flame, and this reduces the temperature at the turbine inlet. The first dry low-NOx combustion system was developed in Japan by Mitsubishi. It was applied to three M701 gas turbines, forming a combined-cycle extension of Tohoku Electric’s Higashi Niigata power station and went into service at the end of 1983. As a prototype system it produced NOx levels of about 55 vppm, which was a good reduction from the 75 ppm standard and would be decreased by further development. Low-NOx combustion is a two-stage process. In the first stage, known as the lean premix stage, only enough combustion air is used to ensure total combustion of the fuel mixed with it. The rest of the fuel is added in a second stage with the rest of the
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Air
NOx water Cylindrical burner outlet
Gas (premix)
Swirlers
Oil return Oil (diffusion, pilot for premix)
Oil (premix) Gas (diffusion)
4.3 The Siemens low-emissions burner developed for the E-class gas turbines with silo combusters, and later for the F-class machines with annular combustors. (Courtesy of Siemens.)
Dilution air Combustion air
Spray evaporation
Liquid fuel
Ignition
Fuel gas
Vortex breakdown
Fuel gas
Swirl nozzle to atomize
Flame front
4.4 The EV burner introduced on the GT13E2, which is now used on all Alstom gas turbines. A modified version is used for the second combustors of the GT24 and GT26. (Diagram courtesy of Alstom.)
combustion air that dilutes the flame temperature to a level which can be withstood by the materials of the hot-gas path. The combustor also has a high-temperature valve on each can which reduces the airflow to the premix section as the load decreases so as to retain the same fuel–air mixture and so maintain a reduced NOx level down to about 25% load. Without this valve the low-NOx condition is met at full load and is sustained down to about 50% load, and the NOx level would then start to increase. At the relatively low firing temperatures of around 1000 °C of these early gas
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turbines, it was fairly easy to obtain low NOx readings and both Siemens and Brown Boveri with their large silo combustors reported single figures of NOx in commercial installations. The Brown Boveri design used an asymmetric cone with a slot down the side. Gas was introduced through holes in the edge of the slot and mixed with the air entering through the slot in a concentrated vortex. As soon as the vortex leaves the cone, it breaks down in free space to create a lean combustion flame. A particular feature of this combustor is that, because the flame is not attached to it, the burner surfaces remain very clean. The EV burner has been applied to every one of the company’s gas turbines and has carried over to all of their current models. In the 1980s, there was a major development in low-emissions combustors across the industry with every manufacturer producing a dry low-emissions combustor that could be fitted in place of the original design. By the end of the decade there was effectively agreement by all on an NOx standard that could be guaranteed in a contract. A gas turbine would guarantee NOx at 25 vppm on gas and 42 vppm on liquid fuel. At the time the natural gas figure could be met dry, but with oil firing was only attainable with water or steam injection. In setting a common standard it was felt that this would not complicate matters for the industry if a system was developed which could achieve even lower emissions. The fear was that it might inspire some Green-tinged centre-left government, particularly in Europe, to bring in legislation to reduce emissions still further to levels that would cause industry problems and focus development in a different direction. In fact, for the 250 MW class gas turbines today, contracts still specify upper limits for NOx at 25 vppm on gas and 42 vppm on oil with water injection, but in practice these gas turbines can all achieve less than 15 vppm on gas, and some claim even single-figure values Only in the USA have emission levels been driven down further but, as measured at the top of the stack, rather than at the gas turbine exhaust flange. In New England the value is 2 vppm leaving the stack, which means that, to meet this, every heat recovery boiler is fitted with a catalyst system that, since it operates best at about 300 °C, is placed in the gas path upstream of the low-pressure superheater. The reaction is between ammonia and NOx to produce nitrogen and water. This standard for low-emissions combustion was, for many years, directed to the gas turbine users in power generation and industrial combined heat and power schemes. In countries with strict environmental policies, users were supplied with the low emission combustor. Elsewhere, if national emission standards were not yet in force, it was a matter of customer preference. However, there was the concern that a further increase in firing temperature in future more powerful gas turbines would mean that they might not be able to attain the low NOx levels achieved on the current generation of machines. For all the manufacturers it meant developing an improved cooling system so that more air could be used for combustion. For the European designs, with their outboard silo combustors, the answer was to replace the silos with an annular
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combustion system. This would eliminate the large hot metal mass which diverted the airflows from the compressor to the combustor and back to the turbine stages. In the new arrangement there would be a short annular passage across which the burners faced the power turbine inlet guide vanes. There were no transition ducts but the annulus was lined with heat-resistant tiles. Access to the annulus was possible for borescope inspections of the turbine inlet stages and the individual burners could be withdrawn from outside for inspection and repair of individual units. The dry low-emissions combustor was standard on each unit. If it was a dual-fuel machine, a special mixing skid was installed. This created an oil–water emulsion that could be fed straight to the burner and so removed the need to instal a separate water injection manifold, greatly simplifying the fuel system hardware of the gas turbine. With this, the steam turbine market was subtly changing. Low growth in electricity demand in Europe had reduced demand for large steam sets for coal- or oil-fired or nuclear power plants, and countries which had discovered gas and had previously built steam plants with 120–200 MW steam sets were now installing combined cycles for which a 350 MW unit would require a steam turbine of only about 120 MW and operating on a different steam cycle. Even for the largest single-shaft combined-cycle systems with the H-class gas turbines the steam turbine will still be less than 200 MW. Gas turbine developers who also made steam turbines were better able to cope with the changing demand than companies which had built only the very large turbines for steam plants, for which there was then a very small international market. Already the first large changes had taken place in the industry. ASEA, the Swedish power engineering company, had joined forces with Brown Boveri to create ASEA Brown Boveri (ABB). ASEA brought to the union ASEA Stal, thereby creating a company with production lines for the large Brown Boveridesigned gas turbines in Mannheim, Germany, and the small industrial gas turbines produced in Finspong; these were retained as separate operating divisions with a defined product range. To start with, only the GT35 was produced in Finspong but in 1992 they acquired the design and production of GT10, a 22 MW gas turbine which had been developed in Switzerland by Sulzer. Following this, Sulzer pulled out of gas turbine manufacture and has since built up a global compressor, pump and gas turbine maintenance business. Further development of GT10 continued at Finspong culminating in the production of a higher-power version for specific applications in compressor drive and industrial combined heat and power schemes. In 1988, an Anglo-French group was formed as GEC Alstom. The British company GEC had developed an 85 MW gas turbine in the EM 610 which had limited success in simple-cycle applications for power generation and mechanical drive. They also packaged Rolls-Royce aero-derivative gas turbines in their Leicester works. Ruston Gas Turbines, at Lincoln, with their small industrial range were also in the GEC Group.
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Alstom were the GE licensee for gas turbines with their main factory at Belfort in eastern France and had collaborated with GE in the development of the Frame 9 models. From the merger was born a new company, European Gas Turbines (EGT), with GE and Alstom as the shareholders. The EM610 was discontinued together with the packaging of the Rolls-Royce engines. Gas turbine production in the UK was concentrated in the Ruston factory in Lincoln, which took over the packaging of the GE aero-derivative gas turbines. In France, Alstom expanded their gas turbine operations in Belfort. Later GE’s German business associate, AEG Kanis, of Essen, was incorporated into EGT and a new factory was built there, principally for the assembly of the smaller GE gas turbines (Frames 3, 5 and 6) for the emerging east European and Commonwealth of Independent States (CIS) markets. The European market picked up after 1990 with privatisation of the electricity supply in the UK. Elsewhere in the world, at about the same time, a broader range of gas turbine fuels was being considered where natural gas was not available or in short supply; naphtha, gas condensates, heavy oils and crude oil, and hydrogen have all been used as gas turbine fuels. Particularly in India, naphtha was being considered as an alternative fuel to overcome a conflict of interest in natural gas which was required not only for power generation but also to make fertiliser. With the discovery of gas in the Indian Ocean a pipeline had been laid from a shore terminal north of Mumbai to Delhi, and three combined cycles had been built along the route. However, beyond Delhi the line terminated at Babrala, the site of the Tata Chemicals fertilizer factory which had a 50 MW combined heat and power unit supplying power and process steam to the factory which used the rest of the gas as a feedstock. With a growing rural population, a strong demand for natural gas for the fertiliser industry to increase food production conflicted with demand for power generation. For example, Kawas, a 600 MW combined cycle at the southern end of the pipeline, with four GE Frame 9E gas turbines in two 300 MW blocks was for much of the first 3 years constrained to use only one gas turbine (half a block) because of demand from the fertiliser industry for natural gas. Naphtha, of which there was a production surplus at Indian refineries, was seen as a way round the problem, and the four gas turbines at Kawas were converted to naphtha firing in 1996. Naphtha is a difficult corrosive fuel with a low flash point and poor lubricity, which requires the use of a lubricity enhancer. This is an additive which creates a lubricating film on the surface of the pipe carrying it. Early enhancers were essentially corrosion inhibitors designed for use in pipelines. In the much smaller dimensions of gas turbine fuel systems, these compounds were forming sticky deposits by reaction with the contaminants in the naphtha, which were collecting in mechanical flow dividers and fuel filters. Some gas turbines are more affected than others, notably those with can–annular combustion systems incorporating flow dividers. Those gas turbines with different combustion
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systems are less susceptible, but the properties of naphtha have to be considered as it can still form deposits in pumps and pipes. The search for a solution lies with the companies making fuel treatment additives for oil-fired gas turbines which required some kind of treatment system to remove traces of sodium, potassium and vanadium from the fuel. Lubricity enhancers were developed which can provide protection for critical fuel system components. Generally the naphtha-fired gas turbines are found in the smaller industrial combined heat and power schemes, but gas condensates are found in many fields and provide an alternative liquid fuel; however, generally these are separated out before they reach the power plant. In the UK the increasing number of gas producers entering the market caused some generators to take the risk and to design only for gas, which offered a significant reduction in the price of the gas turbine as well as the elimination of oil treatment and storage. Sour gas, containing hydrogen sulphide, could not be fed into the public system and could only be burned in power stations. The Liverpool Bay sour-gas field supplies the Connah’s Quay station. It was because of this that the station obtained planning consent when the British Government was again under political pressure to slow down gas developments and to give more support to a declining coal industry. In the background to all this there was in progress a development of larger gas turbines that could support higher steam conditions with reheat and even oncethrough steam cycles, which would raise combined-cycle efficiency to almost 60%. More powerful gas turbines would be able to generate more steam at higher pressures to achieve greater efficiency but, if this meant going to higher firing temperatures, the question was whether the single-figure NOx levels would be lost. There were two aspects of the development of these large gas turbines: greater controllability of the gas turbine at higher power output and better distribution of combustion and cooling air to retain low emission levels. The first gas turbines of this new F-class were ordered in 1988 for a combined-cycle power plant at Chesterfield, Virginia some 40 km south of the state capital, Richmond. This was the GE Frame 7F initially rated at 159 MW. Then 4 years later the scaled-up 50 Hz model, the Frame 9F, which was initially rated at 220 MW, went into operation on an EdF site at Gennevilliers in the northern suburbs of Paris. Westinghouse had meanwhile concentrated on the development of a competing unit, the 501F, which was launched in 1989 at an initial rating of 153 MW. Their first four units were installed in a repowering scheme for Florida Power and Light at the Fort Lauderdale power station, which went back into service in June 1993. In fact, the Westinghouse units had remarkably trouble-free entry into service and several were sold to South America and the 60 Hz countries of Asia, for which a separate production line was set up at Ulsan, in South Korea. The air entering a gas turbine has two purposes: as combustion air to produce the power output and as cooling air for the power turbine blades and vanes. The
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question then was how to reduce the amount of cooling air required and to reassign it to combustion as temperatures increased. For the European designs there was a very large hot metal mass in the centre of the machine directing the compressor output to the combustor silos and returning the heated gas to the power turbine. If this could be replaced with an annular combustor system similar to that of the latest turbofan aero engines a significant amount of air could be released to combustion and lower NOx levels would be attainable at higher firing temperatures. The first of the new European gas turbines to be announced was ABB’s type GT13E2 of which the first examples were installed in the Deeside power station, near Chester in northwest England, and to a district heating plant at Diemen, The Netherlands. It offered a modest power increase over the GT13E, from 150 to 165 MW but had an exhaust output of 532.5 kg/s at 610 °C. For this design the silo of the earlier GT13E was removed and replaced with an annular combustor with 57 of the so-called EV burners. By adopting an annular combustor, more air was used for flame dilution to control emission levels. Also by removing the silo combustor it eliminated the large hot metal mass. The straight-through duct from the burners to the turbine inlet was a much simpler construction with a greatly reduced cooling load. Deeside went into operation in 1994 and was the first station in service with a three-pressure steam cycle, but without reheat, and the efficiency was 54%. A reheat steam cycle would be introduced with the larger GT24 and GT26 gas turbines, and the GT13E2 has served as a proof test of the annular combustor which has since been installed on all current Alstom models except the GT11N2. In September 1993, ABB had announced two new gas turbine models: the 165 MW GT24 for the 60 Hz market and the 240 MW GT26 for 50 Hz systems. They were common scaled designs which incorporated a sequential combustion system. The company had inherited the Brown Boveri gas turbine fleet which included 11 of 26 units of an earlier sequential combustion design that were still in operation. The first sequential combustion gas turbine was installed as a simple-cycle unit at Beznau, Switzerland, in 1948 which operated on liquid fuel. Sequential combustion has two combustors separated by a single power turbine stage. The first combustion with a heavily diluted low-NOx flame has enough oxygen for a second stage of combustion. Expansion through the high-pressure turbine stage reduces its temperature so that more fuel can be added in a second burner but not to raise the firing temperature above that in the upstream combustor. The original sequential combustion machine at Beznau had a turbine inlet temperature of 575 °C, which is less than half that of the current models, yet as an oil-fired unit in simple-cycle operation it had 30% efficiency, which was significantly higher than was achievable with some of the other gas turbines of the time. The GT24 and GT26 have two annular combustors. The first has the standard EV burners as on all the current Alstom gas turbines. The standard EV burner in the second stages is a simpler device which receives gas that is lower in oxygen content and completes combustion without any more NOx being formed.
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The other benefit of sequential combustion is the high part-load efficiency. In any gas turbine, most of the work is done in the first blade rows. In the sequential system the first turbine stage is placed between the two combustor stages. To go to part load, the inlet guide vanes and the fuel flow to the first combustor are the main control actions. This determines the mass flow and temperature to set the energy level. The gas leaving this first stage then goes to the second-stage combustor for which the fuel flow has not changed. The gas continues to expand but the exit temperature is still set for a full load and the exhaust temperature is higher than with a conventional single-stage combustor; therefore the efficiency of the steam turbine is higher at part load. Other features of the new gas turbines were a much higher power density than the competing models owing to the pressure ratio of 30:1, which was double that of the Frame 9FA. Since then, the latest upgrade with new compressor blading, released in 2005, has a pressure ratio of 32:1. Then, at the end of 1996, Siemens introduced a redesign of their three F-class gas turbines of which the first examples had horizontal silo combustors (Fig. 4.5 and Fig. 4.6). The main feature of the redesigned gas turbines was the replacement of the silo combustors with an annular combustor utilising smaller versions of the low-emissions burners used in the original silos. Models V94.3A, V84.3A and V64.3A were all announced together in 1996 as a scaled family according to mathematical laws of similarity. Behind this there was the development of new high-temperature alloys and in particular single-crystal blades that would be used in the hottest first-stage blades of the power turbines. All the three gas turbines drove the generator from the inlet end and used the static converter starting system. Variable-inlet guide vanes were introduced as an additional control measure. In many markets a requirement is for operators to carry a spinning reserve of, say, 10% of output. For a large gas turbine, the easiest way to achieve this is to hold the guide vanes partially closed with a corresponding reduction in fuel flow to the burners. While these developments were going on, problems were starting to appear with the GE Frame 9F. For the 50 Hz market, GE had again entered a joint development with Alstom, but by this time they had moved their large gas turbine production and development to a new factory at Greenville, South Carolina. Production of the 50 Hz gas turbines was shared between Greenville and Belfort, with Belfort handling more of the early production. The new gas turbine known as the Frame 9F was initially rated at 220 MW and the first unit was installed in the autumn of 1992 on an EdF site at Gennevilliers in the northern suburbs of Paris. In the European market the Frame 9F was the first of the 50 Hz F-class gas turbines to be announced. The Frame 9E was well known and was a market leader. What made the 9F attractive was the higher power and firing temperature which made it possible for the first time to use a reheat steam cycle and to achieve a combined-cycle efficiency of 55%. At a time of rising gas prices this was particularly attractive when compared with other combined cycles of the time
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4.5 Seraing, Belgium: one of two units of the Siemens Model SGT53000E (V94.2) in the second of three 450 MW combined-cycle stations installed mainly for mid-load duty.
4.6 Tapada do Outeiro, Portugal: one of the first examples of the Siemens Model SGT5-4000F (V94.3A) during installation in 1997. The intake structure is visible on the left.
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using the gas turbines then available which at best achieved an efficiency of about 52%. The first combined-cycle application was at Keadby ordered in 1992 to be built on a former power station site in the Trent valley, for Scottish Hydroelectric. The plant was to have two gas turbines and a steam turbine to make a 700 MW combined-cycle plant. In the 2 years that followed while the station was built, GE continued development and brought out an improved version, the Frame 7FA, for the 60 Hz market and had acquired a number of combined-cycle orders in the USA and Mexico. In Europe, EGT launched the 9FA and orders continued to be received by Alstom and GE so that, by the time that Keadby was commissioned, some 39 units of Frame 9FA had effectively been ordered off the drawing board. Then problems struck. The Keadby units had not been running for more than a few hundred hours when excessive rotor vibration was noted in both machines. This resulted in the unusual precedent of removing the rotors and airlifting them back to Greenville for examination. The problem did not stop there, as one by one the other 9F sites reported similar problems at about the same running time. This first problem was confined to the European-assembled Frame 9F gas turbines and was due to a weakness and cracking of some rotor tie bolts from a particular source. This was cured by redesign of the bolts and did not affect any of the 60 Hz machines. The second problem was in the design of the power turbine in the upgraded FA models. In particular it was due to differential expansion in the inter-stage disc spacers, which required a change in some material and a redesign of the affected component. This problem was complicated because all of the FA machines were affected at both frequencies, The Frame 7FA had been introduced first and several had been in commercial operation by the time that the first Frame 9FA gas turbines started to be commissioned. Because of the different dimensions and operating speeds the Frame 7FA gas turbines started to fail at around 10 000 equivalent operating hours while for the Frame 9FA gas turbines the problems started to appear with excessive vibration at about 1000 equivalent operating hours. In real time this meant that all the problems appeared within a few months of each other. A major programme of works between GE and EGT resulted in a redesign of the rotor and all the operating plants were refitted with new rotors; a few new units from the original order book were shipped with the new rotors installed. Two units for the South Bangkok plant of the EGAT were shipped intact with the old rotors which were stripped out on site and sent to the GE maintenance base in Singapore for rebuilding. By arranging it in this way, since EGAT were one of the last to order the Frame 9FA in the original batch, they could install the lower casing of the gas turbine and all the auxiliary connections while the rotors were being repaired, and as a result there was hardly any time lost in their original commissioning schedule. Since then the Frame 7FA and 9FA models have held their own in the market,
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4.7 The water brake at the Siemens Berlin works, which can load test both 50 Hz and 60 Hz machines. Rated at 180 MW, it is shown here in March 2004 while testing a Westinghouse-designed SGT6-4000F gas turbine.
but the GE experience, because of the number of units involved, caused the power generators to think again about the new 250 MW class gas turbines and there was a slowdown in the rate of ordering of all types. One result was the decision of some of the gas turbine manufacturers to build their own test facilities that could be operated as an independent power plant in a working utility environment. There were two consequences flowing from the GE problems. Until this time, most manufacturers had a no-load facility to test the mechanical integrity of their gas turbines but depended on an obliging first customer who would allow them on site for the first few months to take measurements and to validate their design. Only Siemens with a 150 MW water brake in their West Berlin factory and Mitsubishi with a 130 MW resistance bank at their Takasago works could test any of their previous gas turbines at full load before shipping them. For Siemens it had been an absolute necessity because, until 1990, they were behind the infamous Berlin Wall with no access to a gas supply. When, in 1996, Siemens announced three new gas turbine models to a common scaled design according to mathematical laws of similarity, they had by then upgraded the water brake (Fig. 4.7) and were able to test the validity of the principle of similarity on the two smaller machines. Under this principle, if geometrically similar machines are rotating with the same circumferential velocities, they will have the same aerodynamic performances. Mass flow and output are proportional to the square of the linear dimensions. All the blades in each machine have the same profile but are inversely proportional in their linear dimensions. The three gas turbines were the V64.3A at 67 MW, the V84.3A at 185 MW and
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the V94.3A at 272 MW. By scaling in this way and with the water brake able to test the two smaller machines, they would be able to see that the principle of similarity was valid and extrapolate from the measurements taken to manufacture the largest machine. The first unit was the V64.3A, which runs at 5400 rev/min and drives the generator through a gearbox. This established the basic parameters of the design, and it was then a case of taking the same measurements with the larger Model V84.3A running at 3600 rev/min. Both units were found to conform to the similarity law within the range of manufacturing tolerance so that dimensions could be extrapolated to Model V94.3A. In the deregulated market, with the need to test the large F-class gas turbines, and even larger models in the future, it would be possible to build a power plant specifically as a test bed and to sell the power to the local utility like any other independent power producer. Since most deregulated markets used a bidding arrangement 24 h in advance, it was easy to specify the time of a test and the amount of power that could be produced. Siemens built the Cottam Development Centre in England and installed a singleshaft combined cycle as a test bed for Model V94.3A and later gas turbines. This went into service in 1999 and also had the first working example of the Benson heat recovery boiler. ABB had an empty bay in the factory at Birr, near Baden, and there installed the prototype GT26; subsequently it was used extensively to work out design improvements for the uprated B machines Again by announcing two scaled models the 50 Hz GT26 would be backed up by field tests of the GT24 prototype in the USA. For the next generation of gas turbines to follow their 60 Hz F-class gas turbine, Mitsubishi built a power station beside their Takasago works and ran the steamcooled M501G as an independent power producer, selling their output to Kansai Electric. The other consequence of the GE gas turbine problems was the restructuring of the gas turbine industry, starting with the break-up of EGT. GE started to buy into some of its manufacturing associates, creating out of Nuovo Pignone in Italy, GE Oil and Gas. Kvaerner, their Norwegian associate, became the main packager of the GE aero-derivative gas turbines. Other European business associates became regional maintenance centres for GE gas turbine models and driven units. Alstom, as a major French power engineering company in their own right, were unwilling to become a subsidiary division of GE. They gave up their GE licences and pulled out of the European gas turbines joint venture. GE continue to manufacture in a part of the Belfort works and took over the former EGT offices there together with the factory in Essen. The GE power engineering business in Europe became GE Energy Products with headquarters at Bracknell in the UK. About a year later, Alstom acquired the power engineering business of ABB and the gas turbine business remained with the headquarters in Baden, Switzerland.
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4.8 Blackstone, USA: inside the GT24 package looking towards the turbine. Large-diameter pipes carry bled air to be cooled before it is returned to the power turbine stages.
The large machines over 50 MW continued to be assembled in the former ABB factories in Switzerland, Germany and Poland, and a small industrial gas turbine division was created, based on the Lincoln, UK, factory, formerly of EGT, and the former ABB Stal plant in Finspong, Sweden. An assembly line for the GT11N2 was built as an extension to the ABB turbomachinery maintenance centre in Richmond, Virginia, and continued to supply that market. Alstom also acquired the former ABB joint venture with Kawasaki as Japan Gas Turbine KK. Kawasaki Heavy Industries at Kobe had earlier supplied to the combined cycle at Limay Bataan, Philippines, the six GT11N and the heat recovery boilers, for which they held a licence from the American company Vogt. This relationship was further developed and Kawasaki have supplied Alstom gas turbines to the Asian 60 Hz market, and also supplied GT11N2 for customers in the USA. Kawasaki were also given the development of the combustion system for low BTU gas and have two examples of gas turbines applied to the GT11N2 at the Baoshan steelworks in China and at Mizushima, Japan. Besides this they also manufactured the GT26 for the Chiba Mill combined cycle in Japan, and the Tocopilla project in northern Chile. Alstom became the designers and principal producers of all the former ABBdesigned gas turbines including the GT24 (Fig. 4.8) and GT26 which were just
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entering the market. With many GT13E2 by then in operation the EV low NOx burner was a proven design in the first stage combustors of GT24 and GT26. The original GT26 units on four combined-cycle plants in the UK, Germany, Argentina and New Zealand worked well and demonstrated the operational features of the sequential combustion system. It was when the more powerful B version of the gas turbines was introduced late in 2000 that troubles appeared, stemming from a misdirection of cooling air flow in the second stage of the lowpressure power turbine. Like GE before them, they too had a large order book for which they had to find a common solution that would be applied to some units out in the field and to the remaining few in production in the factory. Where Alstom’s problem had differed was that operating units could carry the fault simply by running at a lower temperature and mass flow. This meant that operators could still earn some revenue but with a plant running at part load which could not meet its contracted performance guarantees. Consequently Alstom, in designing and testing new components which would result in a more powerful gas turbine than they had offered previously, also had to cope with compensation payments to customers and occasionally litigation over missing performance guarantees. Improvement occurred in stages. The first step was to amend the cooling arrangement and to make some other changes to turbine blading to prepare for the planned power upgrade. This was given to all existing operators. The second step was the new compressor that offered a set of blades which could replace the originals in situ at a major maintenance outage. The result of these changes is an increase in power for GT24 from 183 to 188 MW, with a compression ratio of 32:1 (30:1) and exhaust mass flow of 445 kg/s at 612 °C. For the GT26, the power is up from 265 to 281 MW, the pressure ratio is up from 30:1 to 32.1:1 with an exhaust mass flow of 632 kg/s at 615 °C. While seeking solutions, Alstom had focused on their smaller gas turbines and won several contracts for GT13E2 and GT11N2. They also won several orders for steam turbines and for the maintenance and refurbishment of gas turbines, steam turbines and hydro turbines, but the litigation associated with the GT24 and GT26 contracts and the redevelopment costs of these gas turbines had resulted in a financial ‘black hole’ amounting to some €6 billion in their accounts for the fiscal year 2002–2003. The decision was therefore taken to dispose of the small gas turbine and industrial steam turbine divisions based in Lincoln in England, Finspong in Sweden, Nürnburg in Germany, and Brno in the Czech Republic. There was a ready buyer to hand in Europe. While Alstom had been grappling with their gas turbine problems, Siemens had followed their takeover of Westinghouse with first the aquisition of the gas turbine maintenance group Turbocare and then Demag Delaval, makers of pipeline and process compressors and small steam turbines. With this they created a new industrial power division with headquarters in Oberhausen. The Lincoln and Finspong divisions of Alstom were a source of gas turbines that
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would fit comfortably into the new industrial division and this led to the creation of Siemens Industrial Turbomachinery. The steam turbine activities at Finspong are now linked to the industrial steam turbine division with headquarters in Görlitz, Germany. At the end of 2003 the transfers were complete and Alstom had also started to market the GT24 and GT26 again. A first order from the Spanish utility Gaz Natural for a combined-cycle plant with three blocks of GT26 at the final rating was confirmed in December 2004. A consequence of the development of these large gas turbines has been the application of their technology to the previous generation of units as performance upgrades, and the production, by scaling down, of a machine of about 60 MW, capable of running on either 50 or 60 Hz networks and addressed to the larger combined heat and power schemes and medium-sized combined cycles in a 2+2+1 configuration. GE were the first with the Frame 6FA, at 70 MW, in 1994. It had a pressure ratio of 15.7:1 and ran at 5254 rev/min. Siemens, meanwhile had developed the equivalent model as SGT-1000F (V64.3A) which was released in 1996 as one of three scaled F-class machines. This had a 15.8:1 pressure ratio and an annular combustor and ran at 5400 rev/min. The third member of the group was independently developed as the ABB Type GT8 at 46.4 MW in January 1985. Successive upgrades and replacement of the original silo combustor by an annular combuster with EV low-emission burners, and application of computer-profiled blading as on Alstom’s large sequential combustion machines, have resulted in the GT8C2 rated 56.3 MW. It has the highest pressure ratio of the three at 17.6:1 and runs at 6219 rev/min. All three of these intermediate-sized F-class gas turbines have found application in industrial combined heat and power schemes. A large market has been in the former East Germany where Siemens, in particular, has sold a number of combined-cycle plants each with two gas turbines and a steam turbine as a rebuild of district heating stations in Dresden, Leipzig, Chemnitz and Halle. In addition to these, a number of the advanced technology features have been built into upgrade kits for the E-class gas turbines. Computer-profiled blade design has led to higher blade efficiency with fewer losses. Better base materials and coatings have led to modest temperature increases in power turbines with more efficient cooling. Changes are mainly improved compressor blades to increase mass flow, and changed turbine blades and the associated vane carriers with superior cooling arrangements. Generally upgrades are concentrated in the turbine section where more power can be achieved by the combination of more efficient blades at a marginally higher working temperature with improved cooling. About a 10% increase in power output is possible on a 100 MW gas turbine. However, larger gas turbines are on the way. The European manufacturers by moving to an annular combustion system for their F-class units gained the extra
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combustion air which enabled them to hold down emission levels to those of the previous generation of gas turbines. The American manufacturers with their can– annular combustion system did not have an obvious design feature that could be changed and in any case could wait for the next development at even higher firing temperatures before they needed to address the issue of redistributing airflow. The first model to be introduced with steam cooling of the hot-gas path was the Westinghouse Model W501G announced in 1995. This was basically the Model W501F with an increased pressure ratio from 17.4:1 to 20:1 and steam cooling applied to the transition ducts connecting individual combustor cans to the turbine inlet. In fact, compared with the W501F, the exhaust conditions give a 22.4% higher mass flow for an output of 266 MW and an increase of exhaust temperature from 576 to 597 °C. Effectively steam cooling has raised the output almost to that of the equivalent 50 Hz model of the F-class air-cooled gas turbine. The prototype W501G was installed at the Lakeland power plant in Florida, in 1998, and for 2 years operated in simple-cycle mode for testing and validation of the basic design. The gas turbine has a can–annular combustion system with 16 cans and a turbine inlet temperature of 1400 °C. Steam cooling is applied to the transition pieces, giving 16 cooling paths through the gas turbine between the inlet and outlet manifolds of the steam circuit. Initially, cooling steam was supplied by a small once-through heat recovery boiler using a portion of the exhaust gas flow. It was later converted to a combined cycle with a new three-pressure drum-type heat recovery boiler, and a steam turbine and generator. It went back into commercial operation in April 2001. The temporary once-through boiler was shut down. In any steam-cooled gas turbine the steam pressure must be higher than the working gas pressure of the machine. Since the gas turbine pressure ratio is 20:1, intermediate-pressure steam at 30 bar is used. If there were to be any leakage in the steam path, moisture would go into the gas turbine where it could be easily detected, and not gas into the steam cycle. In a normal three-pressure reheat steam cycle the intermediate-pressure output of the heat recovery boiler joins the returning cold reheat line from the steam turbine and the combined flow goes through the reheater. At low loads, below 20%, there is no steam flow through the transition pieces and all of the intermediate-pressure output goes to the cold reheater inlet as in a conventional three-pressure heat recovery boiler. As the load builds up, the intermediate-pressure flow to the cold reheater is gradually reduced as steam is diverted to the transition pieces. By the time that the gas turbine reaches full load, most of the intermediate-pressure steam is going through the transition pieces, where it enters at 275 °C and leaves at 485 °C. Development of these gas turbines started when Westinghouse was still linked to Mitsubishi, who because of their dual-frequency domestic market also developed a 50 Hz version as the M701G. Only two have been built and are installed in
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a further combined-cycle extension of Tohoku Electric’s Higashi Niigata power station where they have been running since 1999. Fiat, the third member of the group, did not build a steam-cooled unit. They only served the 50 Hz market and there was no demand for an even larger gas turbine than the 701F at 252 MW. Steam-cooled gas turbines are very much intended for base-loaded plants since the cooling steam flow is integrated with the steam cycle to improve the efficiency. Because they have to utilize steam cooling as they run up, they take longer to start than an air-cooled unit. Mitsubishi uses an auxiliary boiler to provide cooling steam for the gas turbine start-up and there is therefore no change from air to steam cooling as the gas turbine runs up. The company has also experimented with steam-cooled rotor components and has tested rotors on their Takasago test plant, but the general view is that it is not worth pursuing for the small power gain that results and the added complexity needed to achieve it. Meanwhile Mitsubishi has supplied four M501G for the 1200 MW Ilijan combined-cycle project in the Philippines and has supplied several units to combined-cycle projects in the USA. One other development which was brought to completion at the end of 2003 was the Baglan Bay combined cycle near Swansea in South Wales, which was the first commercial installation of the steam-cooled GE Frame 9H gas turbine. Where this differed from the Mitsubishi and Westinghouse units is in having steam cooling of the rotating turbine blades. The gas turbine has been promoted as the entry model for 60% combined-cycle efficiency but, as a first unit, GE have paid more attention to testing the gas turbine and Baglan itself will not reach 60%, which will require a different steam turbine. It was less than 10 years since the 9F problems, magnified by the number of units ordered off the drawing board, and they were taking no chances. The Frame 9H is probably the most extensively tested gas turbine ever. Even before it arrived in the UK, tests of individual components and subassemblies preceded actual assembly to be followed by factory tests at no load, as it is a 50 Hz machine, and an extended period of testing on the British grid was undertaken before the unit was handed over to the customer at the end of 2003. The Frame 9H gains 25% more power with 8% higher mass flow as compared with the air-cooled Frame 9F. It has an 18-stage compressor with a pressure ratio of 23.2:1. The steam-cooled components are the transition ducts and the first two rows of vanes and blades of the four-stage power turbine. The third stage is conventionally air cooled, but the air bled from the compressor is cooled and the surplus heat goes to the fuel-gas preheater. In other respects Baglan Bay is a conventional single-shaft block with a three-pressure steam cycle, but using a drum-type boiler at 152 bar and 565 °C. The Baglan gas turbine has the performance that would achieve 60% with an optimised steam cycle. That will come with the first three production units which are destined for Tokyo Electric Power’s Futtsu extension which is expected to start
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up in 2008. The first of the three gas turbines for this project was shipped in the summer of 2006. Development of the steam-cooled gas turbines spanned the period of the last major changes in the industry. In the summer of 1998, Siemens took over the non-nuclear power business of Westinghouse at a time when there appeared to be a growing American demand for combined cycles. Siemens had already acquired the Turbocare gas turbine maintenance group and would go on to take over Demag Delaval to create an industrial power division. With the Westinghouse merger, they acquired the gas turbine production plant at Hamilton, Ontario, which they have since integrated with their Berlin operation. Gas turbine research and development was centred on Germany with specific contributions from the former Westinghouse design centre in Orlando. The water brake in Berlin has been uprated so as to be able to test design improvements to the W501F. For a while, before the American market collapsed at the end of 2001, they produced a number of 501F gas turbines in a new workshop in Berlin to relieve pressure on the Hamilton factory and to familiarise their German workers with the American design. With the development of these new large gas turbines and the reshaping of the industry supplying them there has been a redesign of the combined cycle itself. In part this is an initiative of the gas turbine industry and in part also of some of their customers. However, it was not until the 250 MW class gas turbines appeared that the first single-shaft designs appeared in Europe. Since the gas turbine companies were the successors to the great power engineering companies of the early twentieth century, they also built steam turbines, generators, switchgear and control systems. It was an easy move from here to design a combined cycle on the basis of the energy output of the gas turbine expressed as so many tons per hour of steam at a particular temperature and pressure and to design a steam turbine to handle it, then you have the beginnings of a standard power train with the gas turbine and steam turbine with the generator in the middle of the line. The power system in the USA differs from that in most other countries in having installed a large number of heavy-frame gas turbines which operate in simplecycle mode as peaking units. Many combined cycles have been created by adding two or more heat recovery boilers and a steam turbine to gas turbines on the same site. The only single-shaft combined-cycle blocks there are those which have been installed by European contractors. The other American development is the IGCC which has been applied commercially with a three-shaft combined-cycle arrangement using two GE Frame 7FB gas turbines (Fig. 4.9). This is the largest of the 60 Hz GE F-class machines with an ISO rating on natural gas of 184.4 MW mainly from an improved compressor design. As the S207 combined cycle, it has an output of 562.5 MW at an efficiency of 57.5%. In its IGCC application with the additional mass flow of the nitrogen returned from
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4.9 A GE Frame 7FB awaiting shipment from the Greenville, South Carolina, factory. A version of this with a modified combustor is being offered to the first IGCC schemes. (Photograph courtesy of GE.)
the air separation plant the combined-cycle output rises to 630 MW, but efficiency from coal to electricity will be at best only 40%. For most of the twentieth century the efficiency of steam power plants was gradually improved by the development of larger steam turbines with higher steam conditions so that by 1970 a large coal-fired power station with three 660 MW reheat steam sets and input steam conditions of 160 bar and 550 °C would have an efficiency of about 37%. Introduction of mild supercritical steam cycles with high pressures but the same temperatures, in the 1980s raised the efficiency of pulverised coal-fired plants to about 41%. The largest gas turbines operating alone with natural gas have efficiencies of about 38%, which is the main contribution to the combined-cycle efficiency of 58% in the case of a single-shaft system on the 50 Hz network. With some of the largest gas turbines, steam cooling has supplied a further energy input to the steam cycle. For the Alstom GT24 and GT26 the high compression ratio of 32:1 in the latest versions means that the air bled off from the compressor is too hot for effective cooling of the power turbine blades and vanes. For these gas turbines, which are basically air-cooled machines, there are two cooling air bleeds from the compressor; the air is passed through two once-through coolers which divert high-pressure feedwater from the economiser exit and recombine it with the main steam flow at the superheater output. The notable aspect of this sytem is that the cooling circuits do not impinge on the gas turbine operation. The compressor is running at synchronous speed at all times and it is only the setting of the inlet guide vanes and the fuel supply to the
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4.10 A rotor of the prototype SGT5-8000H gas turbine at the Siemens Berlin works. The gas turbine left the factory in April 2007 for Irsching, for testing which began in December 2007. (Photograph courtesy of Siemens.)
combustor stages which determines the output of the gas turbine, so that at all levels of load there is a cooling requirement for the cooling-air supply to the turbine stages. At the end of 2005, Siemens quietly announced that they would build a new gas turbine with a 21% increase in power output as compared with the SGT5-4000F, currently their largest 50 Hz gas turbine model. Very little has been revealed except that it is the first new gas turbine from the integrated Siemens and Westinghouse design teams and that it is designed specifically for combined-cycle application. It is an air-cooled design which suggests that most of the power gain has come from higher mass flow with a modest increase in firing temperature. Designated SGT58000H, it is rated 340 MW at an efficiency of 40% (Fig. 4.10). Unusually the announcement of the new gas turbines was couched in rather philosophical terms. A more powerful and efficient gas turbine is required to meet the demands of a growing world population and an expanding rate of growth of electricity demand, but most of this will occur in the newly developing industrial countries who are expected to account for 45% of demand in 2020 compared with 29% in 2000. New construction relates to growth in demand for electricity; it does not consider the hidden costs of replacing old power stations or upgrading some of
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them to take advantage of new technologies and gain output. Two 530 MW singleshaft blocks of the new gas turbine would replace a 1000 MW coal-fired power station with four 250 MW generating sets dating from around 1960 and would take half as long as the original station to build. Specific design issues have been tested in Berlin, but the prototype has been shipped to a site of E.ON Kraftwerke, at Irsching, Bavaria. There it will undergo proof tests in simple-cycle operation, and only when the performance has been evaluated and confirmed for commercial application will it be converted to a combined cycle. The prototype was completed in March 2007 and shipped out of the Berlin works in mid-April. It was dismantled into major sections for transport through Berlin to the canal dock where it was reassembled for shipment and, although Irsching is only about 5 hours by car from Berlin, at 17 m long and 5 m in diameter, and of mass 400 t, it would take at least 3 days by canal to reach the site on the Danube. In many ways, Siemens’ decision to develop the gas turbine is more interesting. It comes at a time of growing world population, the rapid industrial development of China and India, and the growing concerns of global warming. So the emphasis is on higher power and higher efficiency for lower fuel consumption and consequently lower emissions, but it has also come at a time when there is mounting concern at improving the flexibility of operation of the combined cycle. The definitive combined cycle for SGT5 8000H is rated at 530 MW and 60% efficiency, which points to lower costs of operation and maintenance. As an aircooled machine it is aiming for high flexibility of operation which is reinforced by the standard combined-cycle design which will only use a Benson boiler. Testing of the SGT5-8000H started in Irsching in December 2007. When these tests are complete and the design validated, the decision will be taken to add the heat recovery boiler and steam turbine. At the same time the scaled 60 Hz version rated at about 240 MW will be developed. However, the main concern underlying the development of the H-class machines is reliability. The problems with the F-class machines when these first went into commercial operation are still fresh in the memory. GE subjected components of Frame 9H to extensive testing before they were assembled into the prototype. It was then tested at no load in the Greenville, South Carolina, assembly plant before being shipped to the site in south Wales where it had further simple-cycle tests before the combined cycle was completed. Baglan Bay will have been running for 5 years and completed one full maintenance cycle, before the first unit goes into service in 2008 at Tokyo Electric Power’s Futtsu site. The H-class gas turbines are aiming at economy of scale, but as a combined cycle. Both gas turbines have been announced specifically for combined-cycle application. So who will provide the peak load? The oldest combined cycles have already fallen into this role in Europe and, provided that the F-class units have the required flexibility of operation, they also will handle peaks but the great demand for a base-load combined cycle will be in
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places with a large hydro output but no more that can be economically developed; alternatively countries with large coal reserves may follow the IGCC route. The development of gas turbines which began after 1960 has taken output from 25 MW to over 300 MW, and the higher mass flows and exhaust temperatures that have accompanied this have opened the way to a wide range of applications and demonstrated not only high efficiency of generation but also a considerable reduction in emissions. The E-class gas turbines raised combined-cycle efficiency from 47% to 52%; F-class further raised efficiency from 54% to over 58% . H-class promises over 60%. Of the many fuels that have been used, the most difficult is coal. However, coalfired gas turbines have seen limited application, and coal-derived gas is on the point of application. An IGCC will produce a clean fuel, principally hydrogen, and may also have an economic benefit in reducing the import of fuel and also in the recovery of trace elements such as sulphur and mercury for which there might also be an import trade that could be reduced or stopped altogether. At present, one gasifier per F-class gas turbine seems to be the optimum arrangement. While this may be the cleanest and most efficient coal-fired power system the challenge is to improve efficiency by maximising process energy recovery to give it a real advantage over the pulverised coal steam plant and not just an emissions advantage. This will undoubtedly require a larger and more efficient gas turbine than the current F-class machines. In fact GE have studied their 60 Hz Frame 7H and suggested that it could offer significant improvement in efficiency up to 50% if applied to an IGCC. Meanwhile, what will become of the present concept of natural-gas-fired combined cycle? Will it continue to be the system of choice for capacity addition or will the price of gas force application into the mid-load strategy that was the normal operating mode for many of the early combined cycles? If the gas turbine defines the combined-cycle output, it is the flexibility of the heat recovery boiler that determines how best it can be used. Since the end of 2005 a number of combined cycles have been ordered in Europe with once-through boilers to achieve faster start-up in mid-load duty, with more than 200 starts/year. This would suggest that operators are starting to ask for combined cycles that are designed to take greater account of future applications over the whole of the plant’s lifetime.
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There are two basic designs of heat recovery steam generator: drum-type and oncethrough designs. The vast majority of heat recovery boilers on combined cycles today are of the drum type, which can be in a horizontal or a vertical format. The horizontal boiler is a specifically American concept, and the vertical boiler exclusively a European and Japanese design. Both designs have spread around the world as developers have taken their technology with them. The once-through boiler was developed more than 80 years ago and has been used with many large coal-fired steam sets. In the move to higher performance with supercritical steam conditions, an increasing number of large steam plants around the world have once-through boilers, but it was only in 1996 that the first highpressure once-through boiler was applied to a combined cycle. This was in a repowering scheme at Badenwerke’s Rheinhafen power station in Karlsruhe, Germany. Since then, 36 gas turbines have been installed in 15 power plants with once-through boilers. Another 15 in nine plants, all in Europe, are under construction and six in a single project in Japan. By contrast there are almost 2000 large gas turbines installed in combined-cycle power plants around the world; so the once-through boiler is very much in its infancy of combined-cycle application. However, of the 51 gas turbines listed, 33 have boilers with a high-pressure output of 160 bar. The highest-pressure output on a drum-type boiler is about 135 bar on a vertical boiler with assisted circulation. In the last 10 years, more combined cycles have been built specifically for baseload duty and the constructors have in some cases acquired or licensed boiler manufacturers to produce their boiler designs (Table 5.1). As a result the majority of projects have the American-designed horizontal natural-circulation boiler installed behind the largest gas turbines. The vertical boiler is generally chosen if there is a particular requirement of the customer or the circumstances of the site require it, and usually when the developer is a European electric utility, either acting alone or leading an international consortium. With the development of the combined cycle with larger, more efficient gas turbines, which can support higher-temperature steam cycles, the drum-type boiler is reaching the performance limit. There are vertical boilers in operation with high87 WPNL2204
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Table 5.1 Combined cycles with once-through boilers: March 2008 Project
Owner/operator
Country
Gas turbines
Service date
Rheinhafen Badenwerke
Germany
1 × GT26
1997
Cottam
E.ON (UK)
UK
1 × SGT5-4000F 1999
Agawam
Berkshire Power
USA
1 × GT24
2000
Rosarito
CFE
Mexico
1 × GT24
2001
Monterrey
CFE
Mexico
3 × GT24
2002
Midlothian
American National Power
USA
6 × GT24
2002
Hays County
American National Power
USA
4 × GT24
2002
Blackstone
American National Power
USA
2 × GT24
2002
Lake Road
Lake Road Generation
USA
3 × GT24
2002
Bellingham American National Power
USA
2 × GT24
2003
Meriden
USA
2 × GT24
2003
Berkshire Power
Milford
Berkshire Power
USA
2 × GT24
2003
Monterrey
Iberdrola
Mexico
4 × GT24
2003
Hermosillo
Union Fenosa
Mexico
1 × GT24
2003
Herdecke
Stadtkraft/E-Mark
Germany
1 × SGT5-4000F 2007
HammUentrop
Trianel Power
Germany
2 × SGT5-4000F 2007
Irsching 5
E.ON Kraftwerke
Germany
2 × SGT5-4000F 2008
Langage
Centrica plc
UK
2 × GT26
2009
Sloecentrale Delta NV/EDF
Netherlands 2 × SGT5-4000F 2009
Lingen
RWE
Germany
2 × GT26
Uskmouth
Severn Power
UK
2 × SGT5-4000F 2010
Pego
EDP
Portugal
2 × SGT5-4000F 2010
Gönyü
E.ON Erömüvek
Hungary
1 × SGT5-4000F 2010
Malzenice
Slovensk Elektrarne
Slovakia
1 × SGT5-4000F 2010
Irsching 4
E.ON Kraftwerke
Germany
1 × SGT5-8000H 2011
Johetsu
Chubu Electric
Japan
6 × Frame 7FA
2009
2011
pressure outputs at about 135 bar, which have been designed specifically for loadfollowing duty. This is becoming a critical issue in combined-cycle operation since there is an increasing need for operators to cover peak demand periods. How this is achieved varies: some of the largest plants run down to about 50% load on weekday nights and shut down completely at weekends; smaller, more flexible plants may only operate no more than 14 h/day. Although the thermodynamic principles are the same for both the horizontal and vertical drum types, there are basic differences between the two designs which dictate how they can operate and, although the vertical design is now in the
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minority of new applications, it has the advantage in terms of what it can do for the operator in power generation, load following and frequency control. Operation for 30 years in Europe has shown that the combined cycle with vertical heat recovery boilers is an inherently flexible power plant with a potentially fast response. Whether or not this can continue depends on the type of boiler fitted to the plants that eventually replace them. Combined cycle design has until recently focused on high power and efficiency, but operational flexibility is of increasing importance. The catalyst for this was Siemens’ magnanimous gesture in 2005 in offering the licence for their Benson heat recovery boiler to all the companies around the world who are designing and building heat recovery boilers. However, the traditional drum-type heat recovery boilers are still the preferred choice. If there should be a requirement for flexible performance on a single-shaft block with a large gas turbine, then the industry has the option of being able to offer either a drum-type or a once-through boiler design if the customer wants it. There might today be only four main suppliers of large gas turbines to the combined-cycle market, but there are many times that number of companies that can manufacture all or part of the heat recovery boiler. In any case, it accounts for about 30% of the total contract and, although it is the key to the operation of the combined cycle, it is generally the gas turbine manufacturer who, as the builder of the plant, has to procure the heat recovery boiler under the terms of a turnkey contract. Of the four gas turbine companies, only two have their own boiler divisions, but these are not used for all their projects. Mitsubishi’s boiler operation at Nagasaki produces mainly vertical boilers and supplies to projects in Japan and other Asian markets. Alstom own the former Combustion Engineering in Windsor, Connecticut, but again use other suppliers in specific markets. Engineering any sort of boiler is a job that can be performed by many companies around the world. First of all there may be a term in the turnkey contract for a combined cycle which requires a high degree of local content. Generally this means local firms for site preparation and erection of basic structures of power house and auxiliary buildings. There may be a pump manufacturer working as a licensee of a European or American producer, which might result in the use of a particular manufacturer’s pumps. Where there is a boiler company, it may have no experience of building a large heat recovery boiler but may have worked on large fired boilers for steam power plants previously installed in that country and therefore has many of the basic skills. There are many examples where these companies have worked on combined cycles with the main contractor to build some of the low-pressure drums and heat exchangers and to perform erection under supervision of the boiler contractor. Compared with 10 years ago there are now a number of boiler alliances, particularly in Europe, where the main boiler contractor can call on some of the other companies to build parts for each of the boilers in a large combined-cycle
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5.1 Rio Bravo, Mexico: two of six heat recovery boilers on the site. The high-pressure output of 133 bar at 566 °C is near the limit of performance of the traditional drum-type unit.
contract. Technology transfer will have given these companies the same tools and equipment, and the only difference between one country and another is the productivity of the factory and the rates of pay for the workers. The first combined cycles in Europe all had vertical boilers. It was the natural direction of flow of hot gas, and they were being built on existing power station sites where space was limited, either to add capacity or to repower an old steam plant. AEE designed and built the first units at Korneuburg, Austria and, in Belgium, CMI supplied the boiler at Angleur near Liège, and later at Drogenbos. These two companies have the most knowledge and experience of combined-cycle development, although not necessarily the greatest number of installations. Both companies have retained the vertical design and, because of this, there is in Europe a huge experience of utility operation in load-following duty which is hardly known or understood in North America. There, all but a few combined cycles have horizontal natural-circulation boilers, the exceptions being the small combined cycles and industrial combined heat and power schemes which have the vertical once-through boiler from the Canadian firm, Innovative Steam Technology (IST). Three combined-cycle blocks at Rio Bravo, Mexico, have a total of six vertical drum-type boilers (Fig. 5.1). EdF International, who had entered Mexico as an independent power project developer, had taken the site for three 500 MW combined-cycle blocks on a 25 year build–own–transfer deal. Located about
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60 km south of Harlingen, Texas, the surrounding communities are developing and have a large air-conditioning load in the summer, and a much lower load for the rest of the year. EdF ordered the boilers from CMI because they had experience of them in Europe and saw the need to run at lower output at night and to shut down at weekends in the off-peak season. The Brighton Beach combined cycle in Canada, near Windsor, Ontario, which went into service in 2003 similarly has two vertical drum-type boilers from AEE which were specified because the owners wanted the plant primarily for loadfollowing operation and frequency control. A large power system with predominantly thermal capacity will carry a component of spinning reserve which will cover the loss of the largest generating set on the system. What this means in practice is that the power plants will run at reduced output so that, if one of them loses a set for whatever reason, the others can increase output quickly to restore the lost capacity. Even in normal operation the removal or addition of load will be expressed as a change in frequency which must be held between very fine limits, a frequency of 50 Hz may in practice mean anything between 49.9 and 50.1 Hz and, if it goes outside these limits, then either the plant output must be increased or load must be shed to compensate. The traditional way in a utility system with mainly steam plants would be to set up a merit order of performance under which those with the highest efficiency and lowest production costs would be base loaded with, below them, a progression in order of operation down to the least efficient and most expensive. The exception to this rule would be the nuclear plants which are limited in their load-following capability and generally have the lowest operating costs and therefore carry the base load, and hydro stations which are highly flexible in operation and can be assigned to peaks and frequency control where they exist. The early combined cycles in Europe were in predominantly thermal power systems in Austria, Belgium, Germany and Ireland and were designed for flexible mid-load operation. They would have to start once if not twice per day and would therefore require a rapid-start capability. Many of these early plants had been created by repowering small steam turbines. As more combined-cycle capacity has been introduced, so there has appeared a gradation of performance based on the type of the gas turbine and the steam cycle that could be supported on its exhaust conditions. The first plants had relatively small gas turbines and a single-pressure steam cycle. The second combined cycle to be built at Angleur, Belgium, which first went into operation in 1978, started life as a base-load unit but in nearly 30 years, as more efficient combined cycles have come into service, it has gradually declined until today it runs for about 2000 h/year, which on average is still more than 5 h/day. Belgium is an interesting country with seven nuclear reactors generating over 50% of the total electricity supply and supported by a number of combined cycles built at different times and with different steam cycles. Indeed the nuclear and gas-
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5.2 Brugg Herdersbrug, Belgium: a typical example of a combined cycle with E-class gas turbines in a 2 + 2 + 1 arrangement, with a twopressure steam cycle and air condenser.
fired plants provide most of the electricity supply backed up with entitlements to the output of jointly owned nuclear and combined-cycle plants on the French frontier and the Coo-Trois-Ponts pumped storage scheme in the Ardennes region. After the completion of the second plant at Angleur a number of industrial combined heat and power schemes were built, but the next combined cycles were three similar 450 MW blocks based on the Siemens Model V94.2 in a 2+2+1 arrangement with a two-pressure steam cycle; efficiency was about 52%. The first two plants in service were Drogenbos, alongside the original repowered set from 1976, in the southern suburbs of Brussels, and Seraing, some 20 km west of Liège in the Meuse valley; both went into operation in the summer of 1993. The third plant, Brugg Herdersbrug, went into service in February 1998 (Fig. 5.2). Before this last plant came into service the first F-class combined cycle was installed at Gent Ringvaart as a GE Frame 9FA in a single-shaft block rated at 380 MW. The steam cycle here is a three-pressure system with reheat and the base-load efficiency is 57%. For the first 2 years it ran in a base-load regime and then moved to a mid-load regime, dropping to 50% load on weekday nights with a 36 h shutdown at weekends. Effectively in Belgium there are three generations of combined cycles operating in a merit order in support of a large nuclear base-load capacity. All the combined cycles have vertical heat recovery boilers and all are operating in load-following mode up to 6000 h with around 150 starts/year. The oldest plants still work on strategic reserve, which means that they must be able to start quickly to respond to a sudden increase in demand, e.g. a television peak.
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Studies carried out on the later plants during the 10 years that they have been operating have shown that there is no problem with the boilers and that, if there is a weak point in the system, calculations have shown it to be the pipe from the superheater outlet to the steam turbine. This is a remarkable testimony to the vertical boiler in peaking operation, and all it shows is that, if the steam pipe will show fatigue, it will do so before the boiler does. Furthermore, with a daily start regime, the gas turbine is adding equivalent operating hours, which in turn shortens the maintenance intervals. However, there are in Belgium a number of combined cycles of different ages which are running in cyclic mode with various numbers of starts per year and no discernible problem of fatigue failures in welds to drums or headers in their heat recovery boilers. The thermal design of the heat recovery boiler aims to remove as much of the exhaust energy of the gas turbine as possible. It depends on the mass flow and temperature of the exhaust gases which determine how many pressures can be used and what will be the temperature at the top of the stack. Thermal inertia is defined as resistance to application of heat. The contents of a tube with narrow wall thickness will heat up more quickly than in a tube with thicker walls, and therein is the difference between the horizontal natural-circulation and the vertical assisted-circulation designs. For the first combined cycles, single-pressure boilers were used with an outlet pressure of around 30 bar. The E-class gas turbines which started to appear in about 1975 operated with higher exhaust temperatures over 500 °C but, with more gas at higher temperature, a greater surface area would be required for heat transfer. The critical boiler parameter is the pinch point, which is the local temperature difference between the saturated steam in the evaporator and the cooled gas leaving it. Reducing the pinch temperature means that more heat must be taken from the gas flow, which means a higher surface area in the evaporator. This can only be taken so far before it becomes uneconomical to manufacture and assemble. To overcome this limitation and to produce more steam, a second pressure level was introduced for the larger gas turbines in combined cycles as distinct from repowering schemes when the original steam conditions determined the boiler output. In a purpose-built combined cycle, using a second lower pressure allows more steam production from two small evaporators rather than from one very large evaporator (Fig. 5.3). This requires a change in the design of the steam turbine, to introduce a lowpressure steam input. This is usually placed at the cross-over from the high-pressure to the low-pressure cylinder. The turbine is then said to be operating in slidingpressure mode with the low-pressure input following the changes in the high-pressure output as the load varies. The first two-pressure combined cycles were supplied by Brown Boveri at Korneuburg, Austria, and at Donge, The Netherlands, in about 1980 with the type GT13D gas turbine, then at a rating of 81 MW. The high pressure was 33 bar and the low pressure 4 bar.
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5.3 A simplified heat balance diagram from GTPro for a two-pressure steam cycle with a GE Frame 6FA in a single-shaft block. (Picture courtesy of Thermoflow Inc.)
Then 4 years later with the gas turbine uprated to 97 MW the company received the first of two contracts from the Turkish utility TEK at Hamitabad about 100 km north of Istanbul. With the greater gas turbine power and 510 °C exhaust temperature the high-pressure output was at 52 bar at 480 °C with a low pressure of 5.2 bar at 200 °C. Further development saw high pressures at about 90 bar with some of the larger E-class gas turbines having exhaust gas temperatures up to 550 °C. Introduction of the F-class gas turbines with exhaust temperatures of around 600 °C introduced the possibility of a three-pressure steam cycle with reheat. Again the largest output is the high pressure with steam pressures now at 110–125 bar. With this the intermediate pressure is set at the same value as that of the returning cold flow to the reheater. With a hotter exhaust, and therefore higher operating temperatures, the steam cycle has become more complex. With a higher compression ratio this means that the air entering the combustor could be hotter than the gas flow; so, if a part of the intermediate-pressure steam production is taken to a fuel gas preheater and thence to the condenser, the fuel gas is heated and therefore less is required to heat the air to its final temperature going into the power turbine. For this the intermediate pressure at least has to be used because, at typically about 30 bar in a three-pressure steam cycle, it is higher than the gas pressure in the combustor. This is for safety
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reasons since it ensures that, in the event of a leakage, moisture would enter the combustor and not gas into the steam path. The other energy trade is in the air bled from the compressor for blade cooling. If because of the high-pressure ratio it is too hot, then its temperature must be reduced for effective cooling in the turbine inlet blades and vanes. The Alstom GT24 and GT26 with 32:1 pressure have once-through coolers for the bled air which on the steam side are coupled in parallel with the high-pressure superheater. Heat recovery in particular now with the single-shaft blocks contributes to their higher efficiency. The other cooling measure is the steam cooling of certain gas turbine models. This is due to the higher firing temperatures and to the need for more air dilution for emissions control in a can–annular combustion system. Here the gas turbine cooling stream is an intermediate-pressure flow ultimately feeding the recovered energy into the reheater. These flows are irrelevant to the layout of the boiler either horizontal or vertical, but the speed of start-up is very much dependent on the design of the boiler and has revealed specific problems now that high-pressure outputs are over 120 bar. This is particularly true of the large horizontal natural-circulation boilers with the largest gas turbines. The horizontal heat recovery boiler was developed in the USA and has been adopted by all the major boiler companies there. The argument was that it could be built in easily transportable factory assemblies which on arrival at site could be stood on end and bolted together. The drums would be mounted on top of the structure. Furthermore, with the strict emissions policies in some states it would be easy to place a selective catalytic reduction unit at the appropriate position in the line of tube modules. The gas flow is horizontal but the exhaust gas has to fan out from the diameter of the gas turbine exhaust to the tall rectangular cross-section of the boiler. In a combined heat and power unit this transition duct can also house burners for supplementary firing, which can lead to considerable turbulence unless baffle plates are strategically placed to even out the flow in the duct connecting the gas turbine to the boiler inlet and the first tubes which carry the superheater outlet. Within the boiler the heat transfer tubes hang vertically from the drum and other headers in a structure known as a harp. Water circulation to and from the drum depends on the fact that there is a temperature gradient between the downcomer and riser. The riser is the first tube row of the evaporator met by the incoming gas and the downcomer is the second row which is colder; so the denser water pushes the evaporating water up to the drum where separated steam is passed to the inlet header of the superheater, and the process is repeated in the superheater with steam at the design pressure going from the outlet header to the steam turbine (Fig. 5.4). It all sounds elegantly simple and the horizontal boiler really became successful in the 1980s with the PURPA legislation which promoted combined heat and power as a way of improving energy efficiency. These issues apart, one of the
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5.4 Vilvoorde, Belgium: a plant with a high-pressure–low-pressure preheater module assembly with the first of three low-pressure economiser–evaporator sections in place. It is a repowering scheme with a Siemens SGT5-4000F gas turbine.
reasons why the horizontal design has succeeded was undoubtedly the small size of the 60 Hz gas turbine models. A typical boiler with one or two output pressures would be a series of single modules, behind a gas turbine of less than 100 MW capacity. Until the 150 MW Frame 7F was announced in 1988, the largest gas turbine produced in the USA for 60 Hz networks was the 105 MW Westinghouse W501D, but the majority of gas turbines at the time were rated 80 MW or less and many installations were with smaller gas turbines of 25–40 MW and supplying process pressures of 40 bar and less. Furthermore these installations were tied to processs industries with long operating runs and were required to shut down only twice or three times per year. As gas turbines became larger and with rising steam pressures, the first changes appeared in the design of the boiler. Not only was the cross-section increased to accommodate the larger gas flow, but so also were the tube dimensions. Any device hanging vertically is carrying its own weight; so tubes in the horizontal boiler have alway been marginally thicker to acommodate this. However, a higher pressure means even thicker tubes, which in turn means a lower rate of conductivity of heat. Therefore the rate of evaporation is reduced and the boiler takes longer to heat up to its full steam temperature. The advantages of the horizontal design held for the small gas turbines of the PURPA industrial combined heat and power schemes and throughout the USA market 20 years ago but, as soon as the F-class gas turbines arrived, the dimensions of the gas path increased, and it was recognized that the fully assembled heat transfer module to go behind a 150 MW gas turbine would be too large for road or rail transport.
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Two smaller parallel modules would have to be fabricated, shipped separately and welded together at site. The completed modules are then assembled in line and scaffolding erected to enable the drums to be fitted and the connections made to them, with a large number of welds performed some 20 m, or more, above ground. These problems are not so acute with the vertical-boiler types because, although thicker tubes must be used at higher pressures, they do not support their own weight, but are threaded through vertical tube plates which are incorporated in the modules and hang from the top of the boiler frame. Parallel modules must still be installed with the larger gas turbines, but their assembly can be performed at ground level before the completed section is lifted into position. The erection of the vertical heat recovery boiler is now less complicated with the larger gas turbines and it has a number of advantages in service. First a frame is erected and a series of jacks are mounted on the top of it. Structurally the frame is stabilised by floor beams at three or four levels and with stairways linking them, and these floors will become the maintenance galleries in the operating boiler. The drums are also mounted on top of the frame, since with natural circulation this arrangement creates the largest static head for the evaporators. The inclusion in the first boilers of assisted-circulation pumps in the evaporator not only directed the flow around it and prevented steaming in the economiser but also speeded up the flow as compared with a natural-circulation system which depended on a temperature difference to establish it. Consequently in a vertical boiler the combination of forced flow through thin-walled tubes means that it had a lower thermal inertia than a horizontal unit and could start up much more quickly: within an hour from a warm start, as would be the case after a weekend shutdown. One of the largest contracts to be awarded for vertical heat recovery boilers was awarded in April 1996 to CMI, by Saudi Consolidated Electric Company (Central Region). This was for 16 units for Riyadh Power Plant 9, to be installed in four 320 MW blocks each having four GE Frame 7EA gas turbines site rated at 56 MW and a 100 MW steam turbine. In fact, it was quite a simple steam cycle with a single live pressure output and a low-pressure section supplying steam to a common deaerator in order to achieve a high inlet temperature to the economisers. The challenge of this contract was the number of units, with the first block to be ready by December 1997 and the other blocks following at intervals of 12 months. In effect the contract required four boilers to be installed in each of four consecutive years. Looking at the boiler design it was possible to divide it into three sections: lowpressure preheater; high-pressure economiser and evaporator; high-pressure superheater. Dividing the boiler in this way, the tubes of each section could be assembled in an insulated box frame in the factory in Belgium and welded to their headers to form a module. Low-temperature modules had internal insulation but the highpressure superheater had external insulation which still had to be fitted on site. The modules were designed so that the sides could interlock with the unit above and
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below to form a continuous gas duct. Each module was completely assembled and inspected under factory conditions before shipment. The boilers at Riyadh were relatively small. For a 250 MW gas turbine with a three-pressure reheat steam cycle the modules would be assembled as two or three parallel sections for ease of transport and joined together on site, but the benefits of modular construction were the same; better quality control through complete factory assembly; ease of erection on site. The tube bundles are made up from a series of parallel serpentine paths between two headers. The path is built up by welding end pieces between adjacent tubes, so that in a matrix of 100 tubes there will be ten parallel paths each made up from ten tubes one above the other, with nine end pieces joining each to the tube above it, and with the free ends of the top and bottom tubes welded to a header. The advantage of this construction with a large gas turbine is that it is now much easier to erect than a horizontal type. The individual modules are wheeled under the boiler frame and, where there are two or three parallel modules, there is one large weld at each end between straight tubes to join the headers before they can be lifted as one. On a large boiler with three parallel tube modules there would be about 100 large-diameter welds to be completed on site to join the modules and to link them to drums, feed pumps, output headers and blowdown tank, and all accessible from the boiler frame. No scaffolding is needed to access welds on the top of the unit and the complete boiler for a 280 MW gas turbine can be erected in less than a month. The accessibility of the vertical boiler means that it can be repaired easily. When a weld fails or a tube cracks, it can be located, the tube replaced and new end pieces welded to restore the path. The pressure tubes are supported horizontally in tube plates hanging in the frame and they are reachable from the maintenance galleries. Damaged sections of tube can be withdrawn simply by cutting out the end pieces and pulling it out with a crane. By being able to repair accessible sections of tube in this way the full heat transfer capability of the bundle can be restored. Welding can be performed acurately from a stable position on the maintenance gallery. In any case, if there is any stress cracking, it is more likely to be in the curved end pieces and the connections to the module headers. With the largest gas turbines there might be two or even three parallel stacks for which the headers have to be welded together before the row is lifted. On a greenfield site there could be only two parallel stacks whereas on an existing site where there may be space restrictions the gas path has the same area but it might be in a more square format and so has three shorter parallel stacks although in each case the overall cross-sectional area of the vertical gas path would be the same. Once the heat transfer tube modules have been erected, there are generally only a small number of welds required to connect the module headers to drums, steam turbines and feed pumps. Much of this work can be carried out from the floors built into the frame so that there is no requirement to erect scaffolding to perform welding above ground.
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The modern vertical boiler with prefabricated factory-assembled heat exchange modules and minimal on-site welding can be erected quickly and to an extent tailored to the dimensions of the site. It has lost none of the flexibility that was inherent in the original single-pressure designs of the early 1980s. What has differed is the customer. The first vertical boilers were built for utility customers who would be operating the power plant for the whole of its life. They knew that the technology would be overtaken by later additions to the network and wanted flexibility of operation to be built in. These boilers were designed for assisted circulation with two small circulating pumps of a few kilowatts each of which one is always running and the other is on standby. These were usually mounted on the ground and these boilers were characterised by the large expansion loops in the connecting pipes to and from the evaporators. In the modern high-pressure designs the pump is suspended from the pipes and driven by a fixed electric motor through a cardan shaft to accommodate movement of the pump for pipe expansion. With the arrival of larger gas turbines and higher steam pressures, natural circulation has become possible in a vertical boiler. The first vertical naturalcirculation boiler was developed by AEE in 1987 and installed at the Leopoldau district heating plant in Vienna. It works in the same way as the horizontal design except that the hot gas is rising and the circulating water is falling from the drum on to the boiler frame into a higher-temperature region until it comes to the bottom header which turns it back up to the drum. Vertical natural-circulation boilers are now firmly established in the combinedcycle market, but in one respect they share a problem with horizontal boilers as pressures increase. The rate of heating with thicker tubes is decreased but not so seriously. Gravity is supporting the circulation (Fig. 5.5). On the other hand, the return to assisted circulation would reduce the water volume in the boiler and further increase the rate of heating. There is clearly still a demand for vertical boilers with either natural or assisted circulation. The question has to be asked as to whether opinion is moving back towards the vertical system. First is the fact that the combined cycles built 10–20 years ago with vertical assisted-circulation boilers are still operating as mid-load plants with up to 150 starts/year or more, and some of the oldest units are retained as strategic reserve. There have been no instances of fatigue failure in any of the boilers. Further, there is an advantage for the vertical boiler in mid-load operation. The starting sequence of any gas-fired combined cycle begins with the gas turbine being turned, unfired, on the starter to blow cold air through the system and to purge it. The plant is on a daily load cycle so that the cold air blows on tubes containing steam which has been cooling gradually since the shutdown on the previous evening, some of which condenses in the superheater and has to be drained into a blowdown tank.
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5.5 Schematic diagram of a vertical natural-circulation boiler showing the position of the blowdown tank which can be drained by gravity.
In a large vertical boiler the high-pressure superheater at the bottom of the heat transfer stack is at least 8 m off the ground, leaving ample room underneath it for the blowdown tank which, being above ground, can be easily drained and there is never any risk that this purge condensate floods back into the superheater. In a horizontal boiler the tubes are vertical and the bottom headers are close to the ground. The only place for a blowdown tank to receive this condensate is below the bottom headers so that they drain naturally into it. This means digging a pit under the evaporator section to hold the tank, which then itself has to be emptied if the purge condensate is not to flood back into the headers. The water can only be pumped out, which is an engineered solution with a specific maintenance burden. However, whether it has a vertical or a horizontal boiler the combined cycle must be designed to function over its entire service live with the same reliability and availability. Also, the type of boiler that will be required for the even more powerful gas turbines which are on the brink of application must be considered. Already greater flexibility of design is being sought with the problem of fatigue cracking that has been observed on some boilers designed for base load which are attempting load following in a merchant environment. Some engineered solutions are possible to reduce this since it stems from thermal shock with frequent restarts. To be able to run a combined cycle with a high-pressure boiler in a mid-load duty requires an auxiliary boiler to keep the steam turbine casings, drums and connecting pipework warm overnight. As the gas turbines start up, they start to generate steam which is fed through pipes to the turbine, all of which have been held closer to the operating temperature with the turbine slowly rotating on its turning gear. Effectively, the steam turbine can work more quickly, but the high pressure still means slower heating of the boiler on gas turbine exhaust to avoid overstressing it. A unit designed for base-load duty with perhaps no more than 3 starts/year is trying
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to fit into an operating regime with 150 starts/year or more. Further improvements could be made to the gas turbine control system to allow it to load more quickly. Without these measures a hot start for a large combined cycle with horizontal boilers with a high-pressure output of 120 bar or more could be at least 3 h. These are engineered systems for existing power plants. For new plants the Benson boiler is now widely available and the first units are being installed with combined cycles in Europe and Japan. Of the new gas turbines, the new Siemens 330 MW SGT5-8000H which was announced in September 2005 has been specifically designed for fast start-up with air rather than with steam cooling and is to be offered only in combined cycle with a Benson boiler operating at 160 bar. The Benson heat recovery boiler is the first major new development in the steam cycle since the first combined cycles appeared more than 40 years ago. It is a highpressure once-through design, that has no drum and thus has a much lower thermal inertia, which makes it ideal for plants operating in mid-load duty with 1 or 2 starts/ day. Siemens have had a boiler research facility since they first took a licence from Mark Benson in 1924. As a builder of generators and steam turbines, the company had ideas of adding boilers to their production so that they would be able to design and build the complete power station. Benson was a German engineer who had emigrated to the USA before the First World War. He became concerned about the problems of the early boilers which had drums made from riveted plates, and which were frequently exploding with often disastrous consequences. His idea was to discard the drum and to have a continuous tube for the economiser and evaporator which would be filled with water when cold, and heated at supercritical pressure so that dry steam would be produced at the outlet of a valve at the far end. Having failed to get an American patent, Benson applied for a patent in Germany, which was awarded in 1922. Then, 2 years later, Siemens acquired the patent rights.They built their first boiler with an output of 30 t/h in 1926 for the Berlin Gartenfeld power station, but they only built three Benson boilers before they decided, in 1933, to license the design to boiler firms in Europe and North America. They continued research to support the industry and retained the name Benson as a trademark. All Benson boilers are once-through boilers, but not all once-through boilers are Benson boilers. These boilers became fully recognized with the introduction of high-pressure subcritical steam cycles with reheat in the 1950s. A power plant designed for base-load duty would have a drum-type boiler and perhaps shut down once a year for planned maintenance. A plant designed for mid-load duty with daily or weekly start-and-stop operation would have a once-through boiler. Already there are a number of combined cycles operating with once-through boilers at a high-pressure output of 160 bar. The standard boiler for the Alstom GT24 single-shaft block is a two-pressure boiler with a once-through high-
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pressure stage at 160 bar. These plants were designed specifically for the North American market as merchant plants for which a rapid start capability was essential. The Benson boiler is designed not only to start rapidly but also to work at higher operating pressures. The one operating plant at Cottam in the UK was an experimental unit designed to work at a pressure of 160 bar but has only operated at 125 bar with the present gas turbine. Since being commercially operated in 1999 there have been periods of mid-load operation with up to 190 starts/year and no forced outage due to the boiler during that time. By June 2007 the plant has recorded 1008 starts during its lifetime. Since offering their Benson licence to the boiler makers, a number of combined cycles have been ordered in Europe with once-through boilers. The first plants to be ordered with Benson boilers instead of the conventional drum types are on two combined-cycle blocks in Germany. These plants, however, have the 280 MW SGT5-4000F gas turbine and so have a Benson high-pressure stage running at 125 bar. A third German plant with the Alstom GT26 gas turbine, and another in England have a high-pressure output of 160 bar which the gas turbine can support with an exhaust temperature of 630 °C. Alstom will monitor these plants to see how they perform and, with the GT24 experience as well, they are reportedly aiming to supply all future combined cycles with Benson boilers. Why is it necessary for plants to be able to start quickly? Because electricity cannot be stored, the power system must adjust to changes in demand as they happen. How this is done is based on a complex system of prediction which takes account of known variables, looking at weather forecasts, television schedules and special social events which can create their own particular variations in demand. The grid managers determine a probable pattern of demand and the generators bid to supply it. On a normal weekday in an industrial country, demand will start to rise rapidly after about 6.00 am as people wake up, lights go on, sewage and water supplies become more active causing more pumps to start up, demand for public transport increases, computers are switched on and machinery is started in hundreds of workplaces so that, in a very short time, electricity demand may have doubled. In hot countries the air-conditioning load will start to build up during the morning as the ambient temperature rises. One by one, power plants start to operate to meet the growing demand. If the demand for power grows more quickly than the power plants can meet, then either circuit breakers trip out to shed some of the load to match it, or the frequency drops and small adjustments have to be made to increase power to restore it. A new situation arises with the growing number of wind farms with intermittent operation. The weather becomes hot and sultry, and none of the generators is turning. There is a higher air-conditioning load which the wind farm cannot help to supply and this is when the strategic reserve starts to operate. What then happens
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is the instant start-up of a pumped storage or other hydro plant to cover the startup of an old 100 MW combined cycle of low efficiency which can become fully operational in about an hour. The hydro plant then shuts down and the combined cycle stays in operation until the wind farm output returns. There can also be spikes in demand from specific events. The commonest is the television peak. A major sporting event comes to a thrilling finish and the winning team wins by only one point scored in the last minutes of the game. As soon as the game ends, activity restarts. Lights go on in thousands of homes, people use the lavatory, which starts up water and sewage pumps, and kettles are switched on to make tea. It is not a large increase in demand, but it occurs suddenly, is repeated in thousands of homes and may last for perhaps 30 minutes, after which demand drops back to its previous level and continues to fall, since many television peaks occur at the end of the day. Demand at night is lower than in the daytime and utilities have in the past devised ways of increasing it to improve the load factor of specific power plants. Pumped storage was intoduced to hold up nuclear load factors by pumping water from a lake into a small reservoir constructed on a nearby hilltop. The water would then flow back through a turbine to generate electricity at peak times during the following day. Even before this, in Europe, electric storage heating was introduced. Thermal storage blocks were heated by electricity over 7 h at night (from midnight to 7.00 am) and then cooled by controlled leakage of heat into the room. In the UK this was charged on a special night tariff of about one third of the daytime rate, the charging was determined by switching scales on a meter, so that in effect all electricity consumption during the charging period was available at the night tariff and anybody could program a dishwasher or a washing machine to operate during that time and save on their electricity bill, while the utility had the additional night load to improve the performance of its power plants. So an electricity supply network is a potentially unstable system. It must be held at a constant frequency and it must meet all the demand required as it happens. There must be not only enough power plants operating to meet demand but also enough held in reserve to come into operation if any of them break down or a grid connection fails. How important is it for a plant to be able to start quickly? The particular property of a combined cycle is that, when it starts up, two thirds of its output is available quickly from the gas turbines, and the rest is available in as long a time as it takes to heat up the steam turbine and to bring it to full load. Generally speaking, a cold start is defined as the restart of the plant from cold, e.g. after a maintenance outage of several days. A typical warm start occurs after a weekend shutdown; the gas turbine will have been at rest for up to 48 h, but the steam turbine would still be warm and running at a low speed on its turning gear. The hot start after an overnight shutdown is typical of a mid-load operation on weekday mornings after, say, 10 h, or for a plant which may shut down after the morning peak and come back on in the evening after perhaps only 5 h at rest.
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In Europe, combined cycles with vertical boilers operate in this fashion. The older plants with single-pressure boilers at less than 50 bar can perform a hot start to full load in little more than 40 min. This includes some of the earliest combined cycles which after almost 30 years are still held on strategic reserve to be able to operate quickly in response to sudden increases in demand. They may only run for less than 500 h/year but are kept on high availability just for that duty. With a large number of power plants burning the same fuel the most efficient will have the lowest operating costs and will therefore displace today’s combined cycles from base-load duty. It is not surprising therefore that there is a growing number of plants around the world which are being specified for future loadfollowing duty either by having vertical boilers or Benson boilers to guarantee future operation under different conditions from those existing in the early years of service. The once-through boiler was first developed in Europe more than 80 years ago as an alternative design for a fired boiler and subsequently was licensed around the world. Siemens, the original Benson licensee of 1924, developed a version of the Benson boiler as a heat recovery boiler, which they installed at the Cottam Development Centre, in England. The plant has been in commercial operation with EON (UK) since June 1999. IST, of Cambridge, Ontario, has developed a once-through heat recovery boiler for industrial combined heat and power schemes with the majority of installations behind large aero-derivative gas turbines such as the Rolls-Royce Trent and RB211, and the GE LM6000. They have also supplied some units to Siemens to provide cooling steam for their SGT6-6000G gas turbines operating in simplecycle mode. Steam power plants have in recent years become able to operate at even higher pressures with supercritical steam cycles. A 700 MW coal-fired power plant so equipped with a 240 bar, 580 °C high-pressure steam output would have an efficiency of about 42% deriving from the higher steam pressure. For this type of plant, only the once-through boiler is possible. As the size of combined cycles has increased with larger gas turbines with greater mass flow and exhaust temperatures above 600 °C, steam pressures have risen significantly. Under the previous generation of gas turbines, the so-called Eclass, in the output range 70–160 MW, with a two-pressure steam cycle, the high-pressure steam output would be typically about 80 bar at 520 °C. For an Fclass gas turbine of 150–260 MW, depending on system frequency, and with a three-pressure steam cycle, the high-pressure output is generally between 110 and 125 bar at 560 °C. A 50% increase in pressure requires a thicker high-pressure drum, and thickerwalled tubing and is going to take longer to heat to an operating temperature at least 40 °C higher. Certainly, with the horizontal drum-type natural-circulation boiler which depends on a temperature difference between the downcomer from and the
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riser back up to the drum, the higher the pressure, the longer it takes. This is a major problem for operators of plants with this type of boiler since it makes it impossible to undertake typical mid-load operation with with daily start and stop and complete shutdown at weekends. European combined cycles have demonstrated greater flexibility of operation in later life with vertical assisted- and natural-circulation boilers; to try to operate current horizontal natural-circulation boilers in the same manner is not so easy because frequent starting would overstrain welds at the tube joints to the drum headers and lead to fatigue failure. On the other hand a daily start-and-stop regime is not possible if it is going to take more than 2 h to start each morning with the gas turbine held at part load to protect the boiler while it reaches temperature. At a time of high energy costs and growing environmental concern, the shape of future electricity supply systems may be vastly different in the years ahead: an increased nuclear component, 10% of renewables in large wind farms of low availability, IGCC as part of a clean-coal programme, and a growing volume of gas provided by imported LNG, replacing declining locally produced resources in the North Sea and in North America. These are all factors that could increase the cost of gas-fired generation and move development of the combined cycle back to its role in the early years where in Europe, at least, it was seen as a highly flexible midload power system which has between 50 and 200 starts in a normal operating year with running time of at most 4000 h. The new factor that is forcing this change is the proliferation of wind farms offshore and onshore in parts of Europe and North America. There has to be a back-up when the wind does not blow. Already there is considerable experience with once-through boilers on combined cycles in Europe and North America with some 33 units in operation and 18 under construction at the end of 2006. It has obvious advantages for the combined cycle, particularly in the merchant plant environment. With no drum there is less thermal inertia. The boiler starts up more rapidly, which makes it useful for loadfollowing duty and frequency control applications. Futhermore it waits for the steam turbine with the gas turbine running at full load when emission levels are at their lowest. The Benson heat recovery boiler is very much the preserve of the large combined cycles. The prototype boiler has been in commercial operation for more than 7 years. Of the units in commercial operation a the end of 2005 all but two are merchant plants in the USA and Mexico. The first once-through boiler installation was actually installed in Germany in 1995 on the first production model GT26 at Badenwerke’s Rheinhafen power station in Karlsruhe. This was a repowering scheme for a 100 MW steam turbine dating from 1965. The repowering contract included refurbishment of the steam turbine, which increased its output to 120 MW and, with steam conditions of 156 bar and 540 °C at the turbine stop valve, the decision was taken to install a oncethrough heat recovery boiler. A two-pressure steam cycle was chosen with reheat and the boiler was fabricated by EVT GmbH of Stuttgart.
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This project started the debate. Although it is Cottam, completed 4 years later, which has defined the Benson heat recovery boiler for the combined cycle market, Rheinhafen had shown that the higher steam pressures in the subcritical steam plant of the 1960s were beyond the performance limits of the drum-type heat recovery boiler and would be necessary if any higher pressures were to be introduced ito provide greater efficiency. Experience of the once-through boiler for the GT26 at Rheinhafen was applied to the smaller GT24 for the American market. The British generating company National Power had bought some gas turbine and other plants in the USA and had set up American National Power, with headquarters in Houston, Texas, and with a project engineering office at Worcester, Massachusetts, some 60 km west of Boston. The company currently operates 14 of the 26 GT24 single-shaft blocks running in the USA. American National Power had entered the American market as it deregulated. To meet this market the idea of the merchant plant was being promoted. A merchant power plant is one which has no long-term power contract with a public utility but aims on the basis of high reliability to trade in the spot market. Therefore it required a power plant which could start up quickly to be able to supply peak demand when electricity costs are at their highest. A typical merchant plant can have a mixture of long-term and spot market contracts which might mean part-load operation with a large spinning reserve. American National Power saw in the GT24 a flexible gas turbine design with a high part-load efficiency, and a high mass flow at a high exhaust temperature. In effect they wrote a specification for what they wanted and ABB designed the plant to meet it. The 180 MW GT24B with an exhaust flow of 445 kg/s at 615 °C can easily support a high-pressure steam output of 160 bar at 565 °C on a two-pressure steam cycle with a once-through boiler (Fig. 5.6). In the deregulated market in the New England states there is a unified regional power system with Integrated System Operations, now owned by the National Grid Company, of the UK, in Boston, despatching the plants according to forecasts of electricity demand. With all 11 units on the sytem in operation it has been shown that they can all run up to full load in 45 min under a warm start after an overnight shutdown. The performance of these combined cycles was at first hampered by the problems with the B versions of the GT24 and GT26 which were mutually scaled designs but, even at the reduced output of early operation, the advantages of the once-through heat recovery steam generator were clear. Plants which were run in a load-following regime could restart after an overnight shutdown in less than half the time being taken by a conventional horizontal drum-type boiler. However, the GT24 block was also designed to obtain some improvement in efficiency in the steam cycle. Generally the main improvements in combinedcycle performance have been the increased output and higher operating temperature of the gas turbine. As compression ratios and temperatures increased, so it became
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5.6 Hays County, Texas, USA: three of four once-through boilers on Alstom GT24 single-shaft blocks on the site. This is a two-pressure system with a high-pressure output of 160 bar at 560 °C.
necessary to cool the air bled from the compressor for cooling the turbine vanes and blades. In the GT24 with a 32:1 pressure ratio in its final rating, the temperature leaving the compressor is above 500 °C and is too hot for effective cooling. There are two cooling air bleeds and these are passed through two once-through coolers which are connected in parallel on the steam side, between the high-pressure economiser and the superheater outlet. In the once-through steam cycle the air coolers are connected on the steam side between the output of the high-pressure booster pump and the separator vessel (Fig. 5.7). The separator is a small vessel connected in the main steam path. When the boiler is cold, it contains water while at the operating temperature the separator contains only dry steam; in the GT24 cycle it is a junction of the main steam and gas turbine cooler flows, which are connected in parallel with the high-pressure evaporator. The Alstom steam cycle is a two-pressure cycle with the once-through system at 160 bar and 565 °C, which are the highest steam conditions so far to be used in a combined cycle. The low-pressure section is a conventional drum-type naturalcirculation stage operating at 7 bar and 320 °C. Since the fuel gas must have a pressure of 43 bar to fire the gas turbine, the fuel gas heater must be supplied from the high-pressure source.The early boilers of this series were Alstom’s own design but later they sought the cooperation of Siemens with the result that the later units have a modified Benson heat recovery boiler.
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5.7 The steam cycle for the GT24 single-shaft combined cycle, which is standard to all units sold in the USA and Mexico. US installations have a selective catalytic reduction system incorporated in the heat recovery boiler.
The Cottam combined cycle in England has the prototype production example of the Siemens-designed Benson heat recovery boiler which has been running commercially since 1999. The original intention had been to change the gas turbine for a more powerful new model after about 5 years, and so the boiler was designed for a maximum pressure of 160 bar, for an output of 500 MW. The new gas turbine was not developed and so the boiler has been running at 125 bar, which is the highpressure value that has been adopted for the commercial Benson heat recovery boiler being offered with the SGT5-4000F, in a combined-cycle block rated 405 MW under the ISO condition. After operation for 6 years at Cottam there have been no problems with the boiler, which has run in a seasonal base load with long periods of two shifts and an average of 150 starts/year. Since it was concieved as an experimental unit, it was built with both high- and intermediate-pressure Benson stages, but the units now being introduced commercially have only the Benson high-pressure stage and drum-type intermediate- and low-pressure stages. At 30 bar and a relatively low flow rate there is no advantage in having a Benson intermediate-pressure stage. The Benson heat recovery boiler has been developed in response to the need for rapid starting capability and two-shift operation, which has taken on new importance for Siemens following the takeover of the Westinghouse gas turbine business in 1998. There were a number of combined cycles in the USA based on the SGT65000F and SGT6-6000G steam-cooled gas turbines which had been built as base-load units with horizontal natural-circulation boilers and were being required to work in two-shift operation. There are two approaches to the problem: Firstly, there is the engineered approach for existing power plants which involves improving control system logic to control temperature soaking of pipes and valves, provision of an auxiliary boiler to warm and seal the steam turbine, and
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Heat release
Gas path
Mass flow
5.8 The principle of the horizontal Benson boiler; from left to right the amount of steam produced in each tube progressively decreases. Circulation is maintained by the high-pressure feed pump.
changes to turbine control software to allow more rapid acceleration to full power. These measures were all tested at Cottam and are available for retrofit to existing power plants. Secondly, for a new combined cycle there is the option of the Benson boiler. The design of the Benson heat recovery boiler in Cottam has the definitive form for the high-pressure stage. It is based on an obervation in the horizontal boilers currently in use, i.e. that the parallel tubes of the evaporator for the high- and low-pressure stages arranged sequentially in the exhaust flow path have different rates of heat uptake. In this concept, mass flows automatically adjust to the heat input, i.e. all parallel tubes of the high-pressure evaporator show saturation temperature at the first pass outlet and low-temperature differences between the rows of the second pass. This thermoelastic construction of the Benson boiler is shown in Fig. 5.8; the gas flow is from left to right. Feedwater enters at the bottom and the rate of evaporation varies according to the heat take-up rate from the gas. At the top of each tube is saturated steam which is collected and passed to the final tube rows where it is mildly superheated and passes to the bottle and thence to the superheater. In a drum-type boiler the move to higher steam pressures with gas turbines at higher exhaust temperatures has brought extra low-pressure stages to increase the amount of heat recovered. At the even higher pressures of a Benson boiler the lowpressure sections contribute far less and the majority of once-through boilers in service are two-pressure systems with a once-through section at 160 bar and 560 °C and a drum-type low-pressure stage at 7 bar and 380 °C. The Benson heat recovery boiler is now a proven system which can be offered
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as an alternative to the drum-type boiler in a new installation. What is interesting is that, of the 48 gas turbines either operating in combined cycles with oncethrough boilers or under construction with once-through boilers, all to date are the large European-designed models, even if the majority are operating in North America. In Europe, recent combined-cycle orders, notably in Germany, suggest a rethinking of the future role of these plants. In the summer of 2005, Trianel Power, a group of German and Austrian municipal utilities, ordered two combined-cycle blocks for a site at Hamm-Uentrop, near Dortmund. These both have the Benson heat recovery boiler. A second contract was for a district heating plant at Herdecke. Here the power plant will run continuously in the heating season and will run in the summer months as a full combined cycle. However, in a country with 33% of its electricity supplied by nuclear plants the likelihood is that Herdecke will employ a two-shift regime outside the heating season. An order to Alstom from RWE for two single-shaft blocks to be installed at Lingen is the first use of once-through boilers behind the GT26 since the prototype 12 years ago in Karlsruhe. A further order from Centrica, in the UK, was for an 840 MW combined cycle with two GT26 gas turbines with once-through boilers and one steam turbine. It is being built at Langage, near Plymouth, and is important as the last generating station going west from London apart from a simple-cycle peaking plant 120 km further west near St Austell, and some small wind farms on Bodmin Moor. Centrica is the parent company of British Gas and has a large fleet of combined cycles which it has bought up since 2003. As a power generator its customer base is the domestic gas consumers. It therefore operates its combined cycles to supply this market with a daily start-and-stop operation and weekend shutdown. The location of the new plant is important, which may mean that initially it will run in base load. A 420 MW single-shaft unit ordered for the Sloe Industrial Estate near Vlissingen, The Netherlands, has a Benson boiler for fast-start capability because the owners, a partnership of Delta NV and EdF, have said that they will not operate it at night when the price of electricity is too low to justify it. The plant is therefore designed for a daily start-and-stop operation. These orders suggest that the role of the combined cycle is reverting to what it was at the beginning, at least in Europe. Thus it will be the flexible component of power generation and moreover be much more efficient than the steam plants which performed this duty in the past. To describe the Benson heat recovery steam generator as a horizontal boiler is misleading because, while it is true that it has a horizontal gas path, the internal structures of the heat transfer system are totally different but are arranged in such a way that the Benson section fits into the footprint of the final high-pressure economiser, evaporator and superheater sections of a horizontal drum-type natural-circulation unit.
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Siemens have presented design concepts of the Benson heat recovery steam generator for both of their large 60 Hz gas turbines, for the SFT6-5000F in a 2+2+1 arrangement in a 540 MW block, but the main development is aimed at a singleshaft block of the steam-cooled SGT6-6000G. Although this gas turbine is the same size as the SGT5-4000F, giving for the first time a single-shaft block of the same output for both frequencies, the SGT6-6000G is steam cooled and is integrated with the intermediate-pressure section of the steam cycle. Therefore there will be only a Benson high-pressure stage for the single-shaft blocks. To have only one Benson stage is not a problem; it is the structure of the high-pressure stage, with no drum and thinner-walled tubing which determines the rate at which the power plant will load up. The gas turbine cooling circuit will be linked into the reheater and will be kept warm during the shutdown period. Siemens’ own experience and the offer of the Benson licence to the world’s heat recovery boiler manufacturers has emphasised the importance of operational flexibility in the design of the combined cycle. A flexible plant of high availability means that the plant does not have to run at times when the price of electricity is too low, i.e. at night. However, in this situation is high efficiency so important. If a fastacting combined cycle can run up quickly at peak time, it has the potential to earn more for every kilowatt hour that it can sell. The benefit to the investor is far greater than half a percentage point in higher efficiency in a more complex steam cycle running continuously. The efficiency of a combined cycle depends on that of the gas turbine and the extent to which waste heat can be recovered. The case for the Benson boiler rests on the requirement for flexible operation and for higher efficiency, with a target value above 60%. The 350 MW SGT5-8000H announced at the end of September 2006 is the second gas turbine to be designed specifically for combined-cycle duty at this level of performance. Steam cycle efficiency has been increased over the years by raising the steam pressure and temperature and improvements in turbine blading. With coal-fired steam plant the move from a 500 MW turbine with subcritical 150 bar, 540 °C steam conditions to an 800 MW unit with supercritical 220 bar, 580 °C steam conditions has raised the efficiency from 35% to 42%. IGCC is a further way to increase the efficiency of coal usage for power generation. Using the largest gas turbines in the most efficient combined cycle format is expected to bring efficiency up to 50%. Again this will require a highpressure steam cycle which will require a Benson boiler to handle it. Although IGCC is considered to be a base-load system, the higher efficiency due to the higher pressure of a Benson boiler would be a worthwhile benefit. Heat recovery streams must be handled by steam at higher pressure than the fuel gas for safety reasons, so that in the steam-cooled gas turbines an intermediatepressure stage will be required to feed heat recovery from the cooling system back into the reheater circuit.
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Gas turbines which are most suited to Benson boiler applications are the F-class and larger units under development, all of which have exhaust gas temperatures in excess of 600 °C. For the time being, boiler materials limit steam performance to a maximum pressure of 160 bar and a steam temperature not exceeding 600 °C. This is expected to be sufficient to achieve the psychologically significant 60% efficiency with a natural-gas-fired combined cycle based on the next generation of gas turbines. With these steam conditions the once-through evaporator has significant advantages. Elimination of the thick-walled drum results in improved dynamic characteristics of the entire plant. The parallel start-up of the gas turbine and heat recovery steam generator thus required necessitates a thermoelastic design of the pressure parts with small wall thicknesses. The other once-through boiler in common use is a much smaller device produced by IST, in Canada. More than 100 are in service around the world mainly in industrial combined heat and power schemes behind the LM6000, a 40 MW aero-derivative gas turbine and similar sized gas turbines. A few have also been supplied to larger simple-cycle gas turbines in the USA to provide steam for cooling and for power augmentation. The origin of the IST once-through boiler is a development of Solar Gas Turbines, San Diego, California, and the US Navy under the Rankine Cycle Energy Recovery Program. In 1985, Solar Gas Turbines supplied their first two boilers behind their 3 MW Centaur gas turbine in a cogeneration plant at Okarche, Oklahoma. In 1992, the technology was acquired by the Canadian firm, Nichols Radtke, who set up IST to manufacture the once-through heat recovery boiler and moved the business to Cambridge, Ontario, 150 km west of Toronto. The IST design for a once-through boiler is extremely simple in concept. It is a vertical format, consisting of a stack of heat transfer modules which form a continuous gas duct. The tubes are similarly arranged as in vertical boilers with horizontal tubes supported in tube plates and linked by end pieces into parallel serpentine paths between headers. These modules are factory assembled under strict quality control. The boiler is easy to erect, with a minimum number of welds to be made on site to link the modules and to connect them to the feed pumps and output steam headers (Fig. 5.9). In contrast, the Benson boiler is a high-pressure system. The highest pressure on over 100 IST units sold up to the end of 2006 is 103 bar, but the majority have the highest pressure between 30 and 65 bar. It is very much a design for the smaller gas turbines used in industrial cogeneration schemes, which accounts for much of the market. In fact, the majority of installations, at least for industrial combined heat and power schemes, are behind the Rolls-Royce Trent and RB211 gas turbines, GE LM6000 aero-derivatives gas turbines and the GE Frame 6. There are a number of features that are unique to this boiler design.The heat transfer tubes are made of a nickel-based aerospace alloy which means that the gas
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5.9 Whitby, 60 km east of Toronto, Canada: first IST once-through boiler behind a Rolls-Royce Trent 50 supplying power and process steam to the Atlantic Packaging board mill.
turbine can run at its full rating through the dry boiler. In fact, this is the normal way to start it, with feedwater being added into the dry boiler as it heats. In a country such as Canada with severe winter temperatures, a power plant that is shut down overnight when the temperature is –20 °C must be kept warm or else drained of feedwater. This is not as rare an occurrence as might be thought; an industrial combined heat and power system might shut down wholly or partially at weekends and a small combined cycle might be operating in mid-load with a shut down for 8 h on weekday nights and 36 h on weekends. Several small combined cycles have been built in northern Ontario to supply communities along the Trans Canada Pipeline. The plants have been built at compressor stations where there is not only fuel available but also compressor drivers with heat recovery potential. The compressor drivers are mostly RollsRoyce RB 211 systems which are fitted with heat recovery boilers to reinforce the steam cycle of the power plant. The operation of the compressor driver is variable and depends on the gas flow in the pipeline. When the compressor is not running, the boiler is drained and the feedwater held in an insulated tank in the power plant building. The pipeline passes about 300 km north of Toronto. The fact that more than 100 units have been sold since IST was founded in 1992 suggests that this is new technology which has been relatively easy to introduce to market. Lower costs of erection and of maintenance are attractive to a large number of industrial operators.
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If the boiler is constructed so that it can run dry, it eliminates the need for a bypass stack. The gas turbines used with the IST once-through boilers have exhaust temperatures in the range 460–550 °C. Materials for the pressure parts have been chosen with dry-running capabilities in mind. Drum-type heat recovery boilers use carbon steel for tube material which loses strength at high temperatures. Using high-nickel Incoloy 800 and 825 alloys as the tube material and with welded stainless steel fins, there is much greater strength and corrosion resistance and dry running of the gas turbine at full load is possible. Incoloy tube materials also limit oxygen sensitivity and avoid the need for active chemical water treatment. The use of an expensive aerospace alloy for the tube material is more than countered by the elimination of a diverter valve and bypass stack which would otherwise add to the capital cost and maintenance burden. The physical size of the boiler is about 60% of that of the equivalent drum-type unit. Because there is neither a drum nor a blowdown system the water volume is about 12% of that of the drum-type unit. Consequently there need be only a small water treatment plant, although for an industrial cogeneration scheme the size of the plant would ultimately depend on the rate of condensate return from the process. However, for any network a small combined cycle with, say, two large areoderivative gas turbines, once-through boilers and a steam turbine would have all the above advantages but would have the rapid-start capability and be able to supply on demand at peak times when the electricity price is at its highest. It would therefore be a plant designed specifically for peaking duty on the economic base of operating up to 4000 h/year and could find such a market on medium-sized island networks. The once-through boiler is the route to a supercritical steam pressure. Indeed Benson’s original patent was for a long tube at supercritical steam pressure which would be heated over its length and produce dry steam from a valve at the far end. With supercritical steam the pressure is such that the densities of steam and water are the same and that therefore there is no discernible boundary at the evaporation point. Almost all modern large coal-fired steam plants with a typical unit size of 700– 800 MW use supercritical steam conditions and the result has been higher efficiency of about 41–43%. Combined cycles are much more efficient but are based on subcritical steam conditions, and for a gas turbine to be able to support a supercritical cycle it must be able to support conditions of about 220 bar and 580 °C and have sufficient exhaust mass flow at a temperature above 600 °C to sustain it. Discussion of supercritical steam conditions for a combined cycle started in the mid-1990s with the arrival of the high-temperature F-class machines, and in particular the Siemens SGT5-5000F and the Alstom GT26 in the 50 Hz market. In their current versions the Siemens unit is rated at 287 MW with an exhaust flow rate of 671.5 kg/s at 583 °C. The GT26 is rated at 281 MW with an exhaust flow
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rate of 632 kg/s at 615 °C. Both companies had plans to install once-through boilers with these gas turbines. Early development of supercritical steam systems was hampered by the need to use expensive high-strength high-temperature austenitic steels in the hottest regions of the boiler, steam turbine and the connecting pipework. It was only with the development of high-strength high-temperature ferritic alloys that it became feasible to offer supercritical steam cycles for large coal-fired steam plants at pressures over 200 bar, but at temperatures only marginally higher than in the contemporary subcritical steam cycle. Why should this principle be applied to a combined cycle? First, we have to look at the driving principles behind the growth in the gas turbine combined-cycle market: high efficiency and environmental friendliness through use of a generally clean sulphur-free fuel. Coupled with this is the low capital cost and short construction times. However, supercritical steam only makes economic sense with a steam turbine of at least 200 MW, and that is only possible in a combined cycle with a 2+2+1 arrangement of the currently largest available gas turbines. The developments that have pushed combined-cycle efficiency from a modest 50% in 1990 to 58% in plants commissioned today have come chiefly from raising the gas turbine mass flow rate and firing temperature, and careful management of heat losses around the system. A supercritical steam cycle builds on this trend by opening up the possibilities for improved steam turbine efficiency through higher steam pressures. Only one company has shown significant interest in the supercritical heat recovery boiler to have actually built a pilot plant to study operation at supercritical pressure and to evaluate the design for application to a fully functioning heat recovery boiler for a 280 MW gas turbine. As an independent boiler maker, CMI have supplied more than 150 boilers behind gas turbines of more than 120 MW unit size. In 1996 the company set up a development project, the object of which was to study the control of a heat recovery boiler operating at above 240 bar. To this end, a 17 MJ/s pilot plant was set up in the Seraing works near Liège in eastern Belgium. The test rig, which went into operation in November that year, was in effect a single-pressure supercritical boiler producing 14 t/h of steam at 240 bar and 525 °C. The heat source was a duct burner in front of a bank of fans which supplied 65 000 N m³/h of hot gas at 615 °C. This is equivalent to a 12 MW gas turbine with the same exhaust temperature as the Alstom GT26, which was then in its initial rating of 241 MW with an exhaust flow rate of 545 kg/s at 610 °C. The pilot plant was built indoors in the same format as a standard vertical boiler. The steam mass flow rate was 13.8 t/h at full load. The steam produced by the boiler was throttled down to 50 bar and condensed in a small air condenser formed by two cells of a typical lubrication-oil fin fan cooler. In a subcritical assistedcirculation boiler, the tube diameters would range from 32 to 38 mm, with wall thicknesses from 2.6 to 3.8 mm depending on the working pressure. In the
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supercritical test boiler, tubes in the economiser–evaporator had an outside diameter of 25 mm with a wall thickness of 2.9 mm. The superheater tubes were made from SA355 T91, with a diameter of 26.9 mm and a thickness of 4.2 mm. Given that the normal operating pressure would be above 200 bar, the supercritical steam generator would appear to be able to respond quickly with a gas turbine required to run in a base-load mode on weekdays, running down to 60% load overnight and going back to full load the next morning. At part load in any combined cycle the steam pressure drops, and in a supercritical boiler it could enter a subcritical mode of operation where there would be a discernible phase change. Provided that the flow rate is high enough, when this happens the phase boundary moves back from the outlet and, as steam bubbles form, they are forced past it into the vapour space. The economic benefit of a supercritical steam system is greatest with a steam turbine of at least 200 MW, so a combined cycle with these steam conditions would be a 2+2+1 or 3+3+1 arrangement. This would give a steam turbine of 250 MW or 375 MW respectively. However, would such a high pressure be needed given the probable move in the direction of combined-cycle application? High efficiency comes with high pressures, which militate against flexibility. Therefore a flexible plant designed to operate in mid-load duty and for frequency control would sacrifice efficiency for rapid-start capability. The current Benson boiler can heat up more quickly than horizontal drum-type boilers with the same output pressures. All the once-through boiler experience to date is from F-class and smaller combined cycles. Only when there is significant operation with the H-class gas turbines and their higher output conditions will it be possible to determine what will be the optimum steam cycle.
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6 The single-shaft block
From 1990 onwards a new generation of large gas turbines started to appear which were aimed specifically at the combined-cycle market. Rated at around 180 MW in the 60 Hz market and over 250 MW for 50 Hz systems, they have brought a significant change to the concept of the combined cycle as a standardised singleshaft block. In the background to this, deregulation of electricity supply was gathering momentum and with it appeared a new family of investors. Some of them were created out of the project development and engineering divisions of former stateowned electric utilities; others were international partnerships of different energy industries and consulting engineers. Their purpose was to develop power plants in countries with rapid growth in electricity demand and lacking the capital to achieve it themselves from their own resources. It was in Europe that the single-shaft combined cycle first appeared, in two power stations built by the then Alstom company: Connah’s Quay, near Chester in northwest England, with four units, and Eemscentrale, near Groningen in the northeast region of The Netherlands, with five units (Fig. 6.1). At that time Alstom were joint owners with GE of European Gas Turbines who had the European production line for the Frame 9FA gas turbine at their Belfort factory in eastern France. The two stations were built in the same way as conventional steam power stations in the past, with the power trains arranged on parallel axes in a large turbine hall with an underslung condenser for the steam turbine, and the other auxiliaries located in the turbine hall basement. The power train was arranged with the gas turbine firmly coupled to the steam turbine at the intake end of the gas turbine, and with the generator on the end of the line to facilitate withdrawal of the rotor. The heat recovery boiler was a vertical three-pressure reheat design. Connah’s Quay went into operation at the end of 1994 and Eemscentrale in 1995. The difference with the single-shaft block was that it had a single large generator and was therefore totally indivisible. Except during start-up, the gas turbine could not be run independently of the steam turbine, and in Europe there was no economic case for this even if it could be done. In effect the combined cycle had 117 WPNL2204
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6.1 Eemscentrale, The Netherlands: Electrabel’s power station, which was one of the first combined cycles to be based on single-shaft blocks with GE Frame 9FA gas turbines. It has been in operation since 1995.
become just another 400 MW generating set but more efficient than the equivalent steam turbogenerator set and was potentially more flexible in operation at part load. In 1997, European Gas Turbines was broken up and the Belfort gas turbine production line was incorporated into GEEPE. Alstom relinquished their GE licences and joined forces with ABB and later, in a further reorganization, Alstom took over the ABB power engineering operations completely in 2000. Before this happened, four other single-shaft stations had been built. Single units were installed at Gent Ringvaart (Fig. 6.2) and Baudour in Belgium, and at Esch sur Alzette in Luxembourg, and a further eight units were installed at Black Point in Hong Kong. GE have not built many single-shaft blocks since then, but one was the prototype installation of the Frame 9H at Baglan Bay in south Wales. This gas turbine has been specifically designed as the component of a combined cycle or IGCC system and at Baglan Bay follows the layout of the earlier single-shaft plants with Frame 9FA. The most widely accepted concept of a single-shaft block is now the European design of a free-standing self-contained power plant which was pioneered by Siemens at King’s Lynn in eastern England in 1995. With this arrangement, each power train of gas turbine generator and steam turbine is mounted in a separate building with all its auxiliary systems and a control room as a complete power plant of about 400 MW capacity. Given that the gas turbine, steam turbine and generator were all made by the
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6.2 Gent Ringvaart, Belgium: one of the few single-shaft blocks with the 250 MW GE Frame 9FA. The building is acoustically insulated since the plant is on the edge of a residential area.
same company it was easier to optimise the steam cycle by recovering heat from the power train and by preheating the fuel to about 160 °C with a steam bleed from the intermediate-pressure header. The GT24 and GT26 gas turbines developed by ABB initially had a highpressure ratio of 30:1 and so required cooling of the air bled from the compressor for blade cooling in the power turbine stages. This is provided by two once-through heat exchangers which on the steam side are connected in parallel between the final high-pressure economiser and the high-pressure superheater outlet. On the Westinghouse-designed steam-cooled gas turbine and the equivalent Mitsubishi models it is a static cooling system for the combustor transition pieces, which is connected between the cold reheat line from the steam turbine, and the reheater outlet. All these measures have helped to improve efficiency so that now between 56% and 58% is the normal value at full load, compared with 54% for the best of the previous generation of gas turbines in a multishaft arrangement. About the time that King’s Lynn went into service, natural-gas supply was being extended from Spain into northern Portugal, and Powergen, now E.ON (UK), decided to build a combined cycle at Tapada do Outeiro a few kilometres upstream on the Douro River from Oporto (Fig. 6.3). The plant, with three units, was the first in which the layout of the single-shaft power train as a free-standing unit in its own building was established. It was also the first such application of the Siemens SGT5-4000F gas turbine at its initial rating of 245 MW. The power train is the responsibility of the gas turbine supplier which enables standard components to be taken for gas turbine, generator and steam turbine. In
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6.3 Tapada do Outeiro, Portugal: the first multiblock station based on an early version of the Siemens SGT5-4000F gas turbine. It was completed between 1997 and 1999.
fact, the complete train is defined by the basic parameters of the gas turbine since this determines the amount of steam that can be generated. There is no special design issue from one plant to another apart from site-specific issues which are related more to the format of the heat recovery boiler and the type of cooling system that must be used. One block could be installed as a complete power station, as many in fact have been, or else several units could be installed at one site on parallel axes and sharing certain common services. At King’s Lynn, originally it had been planned to build two blocks about 2 years apart, but plans for the second unit were subsequently shelved. Nevertheless, this power plant has defined the basic single-shaft arrangement as offered by the two European manufacturers. In the European design for a single-shaft block the generator is mounted in the centre of the line, rigidly coupled to the gas turbine at one end, and linked at the other end to the steam turbine through a synchronous self-shifting clutch. The clutch enables the steam turbine to be disconnected at shutdown so that on restarting, say 10 h later, the heat recovery boiler can supply steam for turbine gland sealing which eliminates the need for an auxiliary boiler. The clutch is also important for maintenance. When a combined cycle shuts down, the clutch immediately disconnects the steam turbine as its speed drops below the synchronous valve. The gas turbine runs down quickly with the generator and will be cool enough to inspect after about 36 h, but the steam turbine takes much longer to cool and is slowly rotating on its turning gear behind the open clutch. In this situation it is possible to carry out a borescope inspection of the gas turbine, power turbine or combustor before the steam turbine has shut down or to
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change some auxiliary unit on the gas turbine’s skid base. These are jobs that could be undertaken during a weekend shutdown without interfering with the normal operation of the unit. This arrangement of the power train with a centrally mounted generator is an important contributor to the lower cost of these plants. In both European designs the power train axis is about 5 m off the ground which allows for an end-mounted axial, or side-mounted condenser as with a double-flow low-pressure cylinder. In the alternative arrangement with the generator on the end of the line, the steam turbine has to be specially designed to shut down with the gas turbine to which it is rigidly coupled. An auxiliary boiler is required for gland sealing and condenser evacuation at start-up, and an underslung condenser is the only possible arrangement. Therefore this type of power train has the axis much higher off the ground at about 12 m and is installed in a much stronger and more elaborate building. All the gas turbines in single-shaft duty are fitted with the static frequency converter for starting. This system was first introduced in Europe more than 30 years ago and works by operating on the stator winding of the generator as though it were a synchronous motor. In this way the generator is accelerated to the firing speed of the gas turbine and, as soon as sustained firing is obtained, the static frequency convertor system is switched off and the generator reverts to its normal function. The static frequency convertor system replaces a diesel or electric starter motor and torque converter, is entirely solid state and is wired to the generator. On a multishaft combined-cycle block with, say, two gas turbines, one static frequency convertor unit might be shared between the two units, but on the single-shaft block the starter would generally be unique to each gas turbine. These units contribute to the high start reliability achieved with the single-shaft blocks. The single-shaft block with a gas turbine of 270 MW is equivalent to a 400 MW generating set so that three units would make a 1200 MW power plant. Had it been a steam power station in earlier times, the individual turbogenerator sets would have been installed at intervals of, say, 12 months according to the utility’s rate of requirement for new capacity. With the combined-cycle option there are three single-shaft blocks of 400 MW or a multishaft arrangement with three 270 MW gas turbines and a 390 MW steam turbine. This is where the single-shaft option has an advantage. As soon as the first block is completed, it can generate at its full output and design efficiency: 400 MW at 58% efficiency. The other units follow in due course at the prescribed intervals, which in the example is 12 months. On completion, each block is a completely self-contained unit in its own building. There will be some sharing of common services such as the fuel and water treatment facilities and a common control room in its own building and, although each would output through the same substation, they might not all be connected to the same high-voltage network. For the multishaft plant, the gas turbines would be installed first and would run
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for between 1 year and 18 months in simple-cycle mode while the heat recovery boilers and steam turbine were erected. The output of each during this time would be 270 MW at 37% efficiency. Each gas turbine would exhaust through a temporary stack, which might or might not be retained in the completed plant. In any case there would be an outage of several days’ duration while the exhaust duct was modified and connected to the heat recovery boiler. Operation would be further interrupted in commissioning the steam turbine and it is only when this has been done that the plant is able to run at its full 1200 MW output. Three separate blocks would each have identical generators and generator transformers. The multishaft plant would have a 270 MW generator on each gas turbine and a 390 MW unit on the steam turbine. So in the single-shaft case there are only three generator transformers connecting to the main high-voltage busbar of a simpler substation. Also a single 400 MW generator would be marginally more efficient than a 270 MW unit directly linked to each gas turbine in the multishaft case. There is also an operational advantage with a single-shaft plant in a multiunit station. Each of three units could be allocated to different operating patterns determined by different power sales contracts. Two, for example, might be running in base-load mode on a 400 kV network, while the third unit might be of a twoshifting nature with daily start-and-stop operation and connected to the 132 kV network. In another scenario, three units start life in a running base-load mode but, after 1–2 years, there may appear a need for part-load operation at night. This condition can be met by running two units continuously and shutting one down each evening. The units that remain in operation are still running at their design output and efficiency. In the case of the multishaft unit, if one gas turbine were shut down, there would be a corresponding reduction in steam turbine output and the efficiency would be reduced. So tremendous flexibility of operation is achievable with a group of single-shaft units, which would not be possible with a large multishaft unit of the same capacity. To that should be added the simplicity of construction with fewer components and easy controllability. With only one generator per unit there are three generator transformers instead of four, as would be the case in the equivalent multishaft configuration, and a marginal improvement in efficiency of the singleshaft block. The other advantage is environmental. It is compact and has only one stack. There is no bypass stack and, since exhaust temperatures are too high to allow dry running of the boiler, there is a full-flow steam dump to the condenser from each pressure level. This combined-cycle concept was introduced as there were starting to be complaints about the large number of relatively low stacks that could appear on the earlier multishaft stations with smaller gas turbines, particularly if it included bypass stacks as a result of phased construction.
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6.4 San Lorenzo, Philippines: two units nearest the camera. Santa Rita, Philippines: six separate buildings each housing a 256 MW Siemens single-shaft unit based on the Model V84.3 gas turbine.
The single-shaft combined cycle has been introduced because of the globalisation of the electricity supply industry (Fig. 6.4). The supplier industry has coalesced through various mergers into four companies based on major electrical engineering firms which date back to the end of the nineteenth century and so can supply all the turbomachinery and much of the other electrical equipment from within their own resources. Several of the former state-owned generating companies in Europe and Asia have moved out into the wider world as investors in and constructors and operators of combined-cycle power plants (Fig. 6.5). Spanish utilities for instance have gone into South America and Central America. These companies in their home market have experience of design operation and maintenance, if not with the gas turbine, with the balance of plant. Usually the supplier industry will support the gas turbine maintenance, and frequently the contract to build the plant will be followed by an operation and maintenance contract for the first few years of operation. Where there is no such contract, the owners will use their own staff from their home base to train operators and to assist with annual maintenance. With companies owning and operating plant in several countries there is an advantage in commonality of design. The gas turbine per se is a standard product; variations in its output are a consequence of the height of the installation above sea level and the ambient temperature. Therefore, if this concept is extended to transform the whole power plant into a standard design, it can be installed anywhere in the world to perform the same task and, with time, it will become easier and cheaper to build.
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6.5 Palos de la Frontera, Spain: a Siemens standard 400 MW block with SGT5-4000F gas turbine looking towards the condenser with the gas turbine intake housing on the right.
About 40 years ago, when utilities in Europe were building steam power plants, EdF had the reputation for installing a standard generating unit for each series of power plants. First it was for a group of plants with 400 MW oil-fired steam sets; these were followed by 900 MW and later 1300 MW nuclear units. For each series of plants there was an advantage in having a common design which resulted in marginally lower costs and reduction in construction times as the number of installations increased. The standardised combined cycle extends the principle to the rest of the world at a time when the supplier of the power plant has a much greater involvement in its operation and maintenance than it would have done in the past. Partly this is due to the nature of the gas turbine itself. Before combined cycles were installed in any great numbers, experience of gas turbines in the electricity supply industry was confined to a few small aeroderivative units in peaking plants. When it came to recruiting operating staff for the new combined-cycle plants, candidates with experience of gas turbine operations were generally found within the oil and gas industry or were former military people responsible for aircraft engines, or for operation and maintenance aboard gasturbine-powered ships. It was this lack of experience with the new technology among the owners of the new power plants that led to the award of operation and maintenance contracts to the builders, because these were the people with the gas turbine experience of designing, building and commissioning combined-cycle plants. Generally this meant that the builder of the plant would assign two or three engineer managers to the site to train locally recruited operators. These teams would be put in place in the
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later stages of construction so that they could take part in commissioning the plant as a preparation to long-term operation. Contracts usually run for 5 or 10 years so as to take in at least one of the major gas turbine overhauls. The other practice which has gained in significance with the spread of the singleshaft technology is the remote monitoring of operating plants. All four of the major gas turbine companies have remote monitoring centres at their headquarters and at selected regional sites from where they can observe what is happening at each of their connected plants. For remote monitoring an internet connection is set up between individual power plants and the monitoring centre. This is particularly valuable for a company with, say, five power plants spread out between three countries around the world. The monitoring centre views the same information as on the control room screens in each power station. They can see what is being produced and all the operating parameters of the plant and the ambient conditions at site. The centre can download data and plot trends, just as would the power station staff. If then something strange is observed, they can look back at records from this and other similar plants and see whether it has happened before. They can also run the data through their plant simulator to determine what may have caused it and how it might develop so as to reach a decision on whether or not to shut down. What the monitoring centre cannot do is to control the power plants, which may be only 100 km away in the same country, or else on the other side of the world, but they can advise the operators on the results of their analysis and this could result in a decision to shut down and repair, or to continue running to the next planned maintenance outage. Remote monitoring therefore can be an important tool in maintenance planning and is beginning to show results in shorter maintenance times. The gas turbine supplier supports the maintenance of the product and, if it can see what is occurring in the plant, and if it can deduce what is happening to the gas turbine, it can better organise to prepare for the next outage, whether planned or immediate, to fix a serious problem. In the deregulated merchant plant market this is important since a plantoperating licence specifies a minimum availability. Planned annual maintenance may be estimated at, say, 32 days under the power sales agreement but, if the work can be done in 29 days, then that is another 3 days when electricity can be produced and revenue earned. Equally it is 3 days available for unplanned maintenance, the need for which might occur at any time and which would only incur penalties if it lasted longer than the 3 days allowed for it. Helping with the concept of a standard block is the switch from traditional analogue to digital control systems. If a computer model of the power train is built, there is then a means of checking out control systems in the factory and shipping them as fully assembled packages which can be dropped on to prepared foundations and cable connections made to the equipment and to the control room.
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A further development is that signals from analogue measuring devices on the gas turbine can be converted to digital format in an insulated box on the gas turbine skid base, with a single RS232 serial cable connecting it to the control room. The essential element of standardisation is in the power train itself: the gas turbine, generator, clutch and steam turbine and their integration through the steam cycle, and in particular the use of a common lubrication system for the whole of the power train. Many of the auxiliary systems are standardised and there are a number of subcontracting companies which are regular suppliers to specific gas turbine manufacturers. These companies jealously guard their independence. If one of the four majors took one of them over, they would have a captive market with that company but it would deter others from buying from what would be considered just another operating division of a competitor. The concept of a standard power station is that of a standard power train consisting of the gas turbine, generator, clutch and steam turbine and is specific to the gas turbine type. The same basic layout is employed within a simple steelframed building, the only variation being in the layout of the condenser, whether it is axial, with a single-flow low-pressure cylinder, or a double-flow layout with a side-mounted condenser. Outside the power train, the heat recovery boiler and the cooling system are the main variables, together with the electrical output voltage. The heat recovery boiler is the major element of choice. Generally it is an item to be procured by the main contractor. The current preference seems to be for a horizontal natural-circulation boiler with a three-pressure reheat steam cycle and a maximum steam pressure of up to 125 bar. The implication is that the plant will be base loaded so as to give a quick return on capital. Where a vertical boiler is supplied it would be a natural-circulation system up to about 120 bar and an assisted-circulation system for a plant operating at higher pressures. For the early GE-designed single-shaft units in Europe and Hong Kong, vertical heat recovery boilers were used. In particular, because of this the European plants have been running in different operating modes from the beginning; Eemscentrale, for instance, with five units has three running in a base-load mode and the other two in a permanent two-shift operation. Gent Ringvaart, in Belgium, where there is a heavy nuclear base load, has run for long periods when it dropped to 50% of load on weekday nights, went back up to full load during the daytime and shut down completely at weekends. The introduction of the larger gas turbines was a challenge to the manufacturers of the heat recovery boilers, with respect to both their dimensions and the operating pressures. Firstly, with much higher mass flow the cross-sectional area of the boiler was larger which meant that the heat transfer surfaces had to be reconfigured as two or three parallel sections, purely for ease of transport to the site. This was true for both horizontal and vertical designs. It meant more complex site assembly.
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Secondly, the higher steam pressures and temperatures meant thicker drums and tubes, particularly in the horizontal case where the tubes support their own weight. Inevitably, higher thermal inertia meant longer start-up times even with a warm start after an overnight shutdown. The solution was greater factory assembly under strict quality control. If the heat transfer section is produced as a series of fully assembled modules in insulated boxes with just the headers of parallel sections to be welded together on site, erection is much quicker and the cost of sending erection crews to a distant country is similarly reduced. There are many boiler factories around the world as key elements of their countries’ engineering industries and, as they have teamed up with the leading companies in Europe and North America, it means that they all have the same production equipment, and the only difference is in labour costs from one country to another. It is often relatively easy for the company in Europe or the USA that has designed the boiler to subcontract manufacture of some of the heat transfer modules to a company in the customer’s country or elsewhere. The benefit of this construction is in quality control and speed of erection. In any single-shaft arrangement the gas turbine cannot operate until the boiler is ready. With modular construction the work on site is much reduced. On a large boiler with 12 modules in three parallel stacks of four there would be fewer than 100 largediameter welds to be performed to join up the headers and to connect to the drums, the deaerator, the feedwater pumps and the turbine stop valves. The advantages of this construction for a vertical boiler are twofold. Firstly, all the module preparation is carried out in a factory in relatively clean conditions and under strict quality control. The boiler can therefore be erected much more quickly and, if there are no skilled welders available to perform the work, it is less costly to send qualified people from Europe. Secondly, on a constricted site it is possible to design the modules to fit the space available. On an open green-field site a boiler for a large gas turbine could have two module stacks each 21 m × 6 m in plan placed in a gas path of 252 m² cross-section. On a more constricted site the boiler could have three module stacks measuring 18 m × 7 m. The gas path cross-section would still be 252 m² but the boiler would be shorter and wider and this might make all the difference in being able to erect it or not in the space available. Erection is much easier with the vertical boiler because a frame has to be erected first from which the modules are hung. This can be easily achieved with a single large mobile crane. The frame is designed with various perimeter floors and stairways which provide structural stability and are used for maintenance and inspection of the finished boiler. The drums are on the top of the frame and of course no other cranage or scaffolding needs to be used to install them. The layout of the single-shaft combined cycle is best illustrated by an example: Hidroelectrica Cantabrica’s 390 MW station at Castejon in northern Spain, about 200 km west of Barcelona (Fig. 6.6). It is one of five similar units installed by
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6.6 Castejon, northern Spain: one of five similar combined-cycle blocks based on GT26 and installed by Alstom at three sites in the summer of 2002.
Alstom and its subcontractors on three Spanish sites during the summer of 2002. Castejon is the only inland site, the others being near the coast at San Roque, near Gibraltar, and San Adrian de Besos, in the port area of Barcelona. The power train is housed in a steel-framed building with a large lay-down area beside it, enabling a truck to be driven in at one end and out the other. The building was among the first items to be erected and includes a permanent crane of about 350–400 t capacity, which can be used to position equipment on its foundations during construction and later to remove and replace casings, rotors and other other heavy equipment at maintenance outages. The heat recovery boiler is located outdoors and is a vertical natural-circulation design with three pressures and reheat, A conventional deaerator and feedwater tank are mounted on the boiler frame. Castejon is a very open site, which facilitated the erection of the boiler frame and the storage of the heat transfer modules while awaiting erection. There can now be seen to be a significant performance gap between the new single-shaft blocks of the 250 MW class gas turbines and the earlier multishaft units of the 120 and 150 MW machines. It is not just in greater outputs but in a gradual refinement of the design into what is now a standard 400 MW package at 58% efficiency. With gas turbines capable of supporting a three-pressure steam cycle with the highest pressures now attaining over 130 bar, there are significant changes in the design and configuration of the heat recovery boiler and associated equipment, all with the aim of lowering costs.
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6.7 Swanbank, Australia: a 380 MW combined cycle with a GT26 and two-cylinder steam turbine with combined intermediate pressure and single-flow low-pressure with axial exhaust to the condenser.
With the advent of the larger gas turbines, a higher exhaust mass flow rate and temperature have made possible a third steam pressure with reheat. The highpressure output ranges from 115 to 135 bar. In practice the intermediate-pressure flow is relatively small and is added to the cold return flow from the high-pressure expansion to the reheater. The reheated combined flows return to the steam turbine. Development of the single-shaft concept has also concentrated on simplifying the ancillary equipment. The chief areas of change are in the deaerator and the configuration of boiler feed pumps. The deaerator is an essential component of any steam plant. Its function is to remove dissolved gases from the feedwater which might otherwise cause corrosion in tubing and connecting pipes. It works by spraying water in the top of a feedwater tank and at the same time injecting steam which heats the droplets to saturation temperature so as to release the gases which are then evacuated. The saturated droplets fall into the body of the feedwater which is protected by a blanket of steam to prevent further absorption of gas. The traditional deaerator is mounted atop the feedwater tank and this is the type used in the Alstom GT26 combined cycle where with a vertical boiler it is mounted outdoors on the side of the boiler frame (Fig. 6.7). On steam cycles in colder climates a low-pressure evaporator is installed after the main economiser in the coolest part of the boiler with the drum incorporating a deaerator. The feedwater circulates through this section where it is deaerated and from the drum is pumped at the final pressure to the main economiser.
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Deaeration in the condenser is the method used in the Siemens combined cycle and also the Alstom GT24 steam cycle with the once-through boiler. In condenser deaeration the condensate collects in the condenser hot well and extractors remove the non-condensible gases. With a condensing deaerator it is usual to add make-up water to the condenser hot well, which then serves in place of a conventional feedwater tank. Instead of pegging steam in a conventional deaerator, a lowpressure condensate preheater can be supplied from a bleed off the steam turbine which is passed back to the condenser hot well to provide spray heating. Pumps are fewer but still generally set up as two with a 100% rating instead of three with a 50% rating, as in the high-pressure systems of the past. Also in the past there would have been condensate extraction pumps sending feedwater to the deaerator, from where separate pump groups would have passed water on to the appropriate economisers. However, with a deaerating condenser it is the condensate extraction pump that establishes the low-pressure level and it is a two-stage booster pump taken off this which separates the high- and intermediate-pressure streams. Generally, if there are only one or two blocks on a site, there will be two 100%-rated pumps at each position. A third simplification is in the liquid fuel system for a plant set up for dual-fuel operation. There is still a need for water injection for NOx suppression when running on oil, so what is now available is a preparation skid mounted beside the gas turbine which prepares an oil–water emulsion in the required proportions which is fed to the liquid fuel burners. In particular, for the European gas turbine designs with a large number of small burners in an annular combustor, this offers a considerable simplification of the fuel system by eliminating the water manifold and a large number of connections to the individual burners. These are general trends with all combined cycles, but in the single-shaft case there is the question of layout. Either the generator is placed in the middle of the line with the steam turbine exhausting axially to the condenser, or else the steam turbine is rigidly coupled to the gas turbine with the generator on the end of the line. There are advocates of both systems, but the centrally mounted generator has specific advantages, not least of which is the difference in civil engineering costs. With the steam turbine on the end of the line either an axial or a side-mounted pannier-type condenser can be used with the result that the axis of the power train can be lower than with a centrally mounted steam turbine which must inevitably be mounted at a higher level to give room for an underslung condenser. With the 400 MW single-shaft block now effectively the definitive combined cycle over much of the world, the next developments are the introduction of three larger gas turbines which are designed specifically for a combined-cycle application. The steam-cooled GE Frame 9H has been running since the summer of 2002 in a combined cycle at Baglan Bay, South Wales. Three units were ordered by Tokyo Electric Power for service in 2008. GE publicity at the time has focused on 60% combined-cycle efficiency, but the Baglan Bay plant is not able to achieve that; it
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is very much a test facility for the gas turbine. While the output of the gas turbine is suitable for a 60% cycle efficiency, it requires a new steam turbine which is optimised to it. The three units in Japan in 2008 may be the first to achieve this. Baglan Bay went into operation as the gas turbine market collapsed in North America and low rates of demand for electricity have persisted in much of Europe and Japan. On the other hand, Kyoto issues have emphasised the age of much of the existing generating plant. Life extension of some nuclear stations and younger steam plant is being pursued, but there is a growing need to replace many plants in addition to meeting future load growth. It is with this in mind that Siemens announced a new larger gas turbine, the SGT5-8000H, at the end of September 2005. It is designed for combined-cycle application at over 60% efficiency. Unlike the other H-class gas turbine there is no steam cooling. It is a design which ‘borrows’ heavily from aero engine technology, the result of a long-standing co-operation with Pratt & Whitney. By concentrating on advanced materials there is a lower maintenance burden and no steam cooling to compromise flexibility. Little is known of technical details except that the ISO power rating is 340 MW at 39% efficiency and that the combined-cycle output will be 530 MW. The steam cycle will have a Benson boiler with a high-pressure output at 160 bar. The advantage of the Benson boiler is that it can run up to temperature with the gas turbine since there is not the thermal inertia of a high-pressure drum to contend with. The gas turbine does not have to wait at part load for it to catch up, as with a drum-type boiler. Consequently a combined cycle so equipped should run up to full load in half the time of a unit with drum-type boilers, which can take 2–3 h to full load with the largest gas turbines. The only other combined cycles operating with once-through boilers are the 33 GT24 single-shaft blocks in the USA and Mexico. The first unit at Agawam, Massachusetts, went into operation in 2001. The largest operator of the Alstom combined cycle is American National Power with two units on each of two sites near Boston, and another ten in Texas at Midlothian (six), and Hays County (four). The two-pressure once-through boiler for these plants has a high-pressure output of 160 bar at 565 °C with reheat to 565 °C, and a conventional drum-type natural-circulation low-pressure system of 7 bar at 320 °C. These plants have all been designed for flexible operation. The 11 units in Mexico, for example, operate mostly in base load during the summer months when there is a large air-conditioning load and for the rest of the year are running in mid-load duty. The eight units on the four New England sites are dispatched by a regional power pool and operate mainly in mid-load duty with daily or weekend shutdown. They are assigned this duty because of the rapid-start capability with the oncethrough boiler, from start to full power in an hour with full gas turbine power alone in 25 min. Depending on system demand, plants can run from morning to evening some days or start in the afternoon and run through to the next morning on others.
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6.8 Irsching, Germany: a power station showing the location of the prototype SGT5-8000H in its combined-cycle configuration which will be in full operation by 2010. (Photograph courtesy of Siemens.)
A third possibility is to run continuously to cover a nuclear refuelling outage which typically lasts about 4 weeks. The Benson boiler operating at 125 bar is already an option for the current combined cycles, based on operation for 7 years at Cottam in the UK. That station has operated both on base load with weekend shutdown, and in mid-load duty with up to 150 starts/year. Cottam was really intended as a gas turbine development centre and the Benson boiler was in fact designed for a steam pressure of 160 bar in anticipation that a larger gas turbine model would be tested there. The boiler has only run at 125 bar and is now commercially operated by E.ON (UK). The SGT5-8000H will be tested on another E.ON site at Irsching, near Ingoldstadt, Germany (Fig. 6.8). The prototype gas turbine started testing there in a simple-cycle arrangement at the end of 2007. When these the tests are completed and the design is validated, the plant will be converted to a combined cycle. The Benson heat recovery boiler was licensed to the leading boiler makers around the world at the end of 2004. Two plants in Germany ordered in the summer of 2005 are equipped with Benson boilers to guarantee fast start-up. These are utility power plants which will operate in a system with 33% base-loaded nuclear capacity and supply back-up to a growing component of wind power, currently about 14 000 MW at the end of 2005, which is intermittent in operation. In this situation a combined-cycle power station must be flexible to work in a two-shift regime or simply as a back-up for the wind farms. A third project in Norway is the only thermal power plant in a country which has used only hydro
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stations until now. This combined cycle will run in base-load mode and therefore has a drum-type boiler. Siemens largest gas turbine, the SGT5 8000H, announced in the autumn of 2005, will be offered only with a Benson boiler running at 160 bar with a threepressure steam cycle. It will be offered as a single-shaft block ISO rated at 530 MW. The prototype is being mounted on the test site alongside the existing Irsching power station and will be directly cooled by the river Isar. To date, the single-shaft combined cycle is almost entirely a European concept. Even the early units with GE gas turbines were the products of their European licensee. The only single-shaft units in the USA are those that have been supplied by European contractors, but engineers who have commissioned them have remarked on the ease and simplicity of the job with only one of everything to be set up. American preference up to now has been for multishaft systems. Several of the operating plants have been converted by putting heat recovery boilers and a steam turbine behind simple-cycle gas turbines. Others have been built as new projects and particularly with the steam-cooled gas turbines of Siemens and Mitsubishi. However, times are changing and the large problem for most combined-cycle power plants in the USA is the lack of flexibility in operation of the large drumtype natural-circulation heat recovery boilers. The other fact is that, with the industry changes that have occurred over the last 10 years, almost half of the gas turbine manufacturing industry in North America is now in foreign ownership, specifically of Siemens and Rolls-Royce. Siemens in particular is beginning to make its technology felt, having produced conceptual designs for combined cycles with both of the large Westinghouse-designed gas turbines. Of these, the single-shaft option is with the SGT6-5000G (W501G). The same arrangement is followed with a centrally mounted generator and a synchronous self-shifting clutch linking it to the steam turbine. This also has the cold-climate steam turbine design with a combined high-pressure–intermediate-pressure cylinder and a double-flow low-pressure cylinder exhausting to a side-mounted condenser. For this plant, the Benson heat recovery boiler is used because of its rapid-start capability. Here, the gas turbine can run up to full load with the heat recovery boiler following and then hold briefly while the steam turbine accelerates to synchronous speed, when the clutch automatically engages and the single shaft is established. Full load can be reached in about an hour from the start. Furthermore, when the gas turbine is waiting, it is doing so at full load when it has the lowest emissions of NOx and CO. The single-shaft option is the main combined-cycle format over much of the world for the largest gas turbines. It repeats some of the early practice of large steam turbines in that a single unit can be designed as a base-load system, or for mid-load duty with daily or weekly start-and-stop operation. The present concept
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of a 400 MW block seems to be the ideal size for much of the world and many of them appear to have been designed for base-load operation. As the gas turbine capacity that is installed to replace old steam plant and to work alongside base-loaded nuclear and modern supercritical steam plant increases, the combined cycle will increasingly be required to supply the peak load. Already there is significant experience of combined cycles that perform this duty in North America and Europe. However, converting a base-load design to mid-load duty is not easy, although systems have been developed using an auxiliary boiler to hold up the temperature of pipes and casings overnight and with adjustments to the gas turbine controls. These systems have been tested and have been applied to a few plants to enable them to perform warm starts more quickly. If there is a large requirement for mid-load duty, then lessons must be drawn from the old plants which are currently performing that duty. Flexibility of operation with high availability will have priority over absolute performance.
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7 Repowering steam plants
As interest in the combined cycle grew in the 1970s the main concern was to improve the efficiency of power generation. So there was an opinion current at the time which saw a future for the gas turbines then available for the repowering of old steam plants. This would entail demolishing the existing boiler and installing a gas turbine and heat recovery boiler in its place. Some of the first combined cycles in Europe had been built as schemes to repower a steam plant dating from the late 1940s and early 1950s, but these were never followed up to any great extent. The steam turbines were of an earlier technology with no reheat and the gas turbines at the time could only support a single-pressure steam cycle on their exhaust conditions. Although the repowered plants were more efficient and could therefore run higher up the merit order of the operating utility, the design was inevitably a compromise. A gas turbine and heat recovery boiler could be designed to match the steam conditions of the original fired boiler that they would replace, whereas a gas turbine and boiler matched to a new steam turbine designed for the purpose was already proving to be the more efficient system. By 1970, the general form of a large steam turbine for the markets of the industrial world was between 400 and 660 MW with a subcritical reheat steam cycle at 140–160 bar and 550 °C. Some larger cross-compound sets up to 1300 MW had been installed in the USA, and the first units with supercritical steam conditions were starting to appear. At that time the European and North American utility systems had been in a period of sustained growth in the previous 20 years and had built a number of large steam plants. The first large nuclear plants also were being constructed as combined-cycle developments started to make progress. These early repowering schemes took two forms: either the original boiler was demolished and replaced with a gas turbine and heat recovery boiler, or the gas turbine was used to provide combustion air to the boiler and had an exhaust heat recovery unit connected in place of the original feedwater heaters. This latter scheme is termed the fully fired combined cycle because the original boiler continues in operation. In the early years, plants of this type offered a higher 135 WPNL2204
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efficiency. Typically they added between 4 and 5 percentage points to the efficiency of an existing steam plant. In fact, it was only after the arrival of the 50 Hz F-class gas turbines with outputs in the 220–280 MW range that there has been any serious consideration of repowering the older steam plants. First, these gas turbines, rated at over 150 MW for the 60 Hz market, and 250 MW in 50 Hz systems, had exhaust temperatures at around 600 °C and could support a reheat steam cycle with similar steam conditions to the steam turbine that had potential for repowering. Repowering is essentially a compromise between the original steam conditions and what is possible from the exhaust conditions of the gas turbine. During the time that gas turbines have been developed and, with the arrival of 400 MW combined cycles with steam conditions that are compatible with the high-pressure subcritical cycles that were current in the 1970s, there is the possibility to repower some of the smaller turbines of that period. In the last 30 years, one of the great developments has been with the introduction of computer programs to optimise blade profiles and cooling techniques, and an industry has evolved to upgrade old gas and steam turbines so that it is now possible to refurbish the steam turbine with new blades scaled to the turbine design but with the profiles of the latest models to improve output and efficiency. Steam turbine refurbishment is also necessary in repowering with the larger gas turbines to provide for up to three steam inputs for the live high-pressure, reheat and lowpressure input. Typically about 10% more power is obtainable from reblading a large steam turbine. So there is some advantage to be gained by refurbishing the steam turbine as part of a repowering scheme. An even higher efficiency can result. The examples which follow are all of specific interest. Two repowering schemes are associated with industrial combined heat and power schemes: one in the UK with gas turbines and heat recovery boilers replacing a 40-year-old coal-fired boiler; the other in the USA replaced an unused nuclear reactor with 12 gas turbines and the modified steam turbines (300 MW units which were then able to receive dry superheated steam from the gas turbine heat recovery boilers instead of the wet steam conditions from a nucler reactor for which they had originally been designed). The other three North American schemes are planned capacity additions to existing sites to improve the performance and the environmental impact. Three other schemes are applications of the F-class gas turbines in the 50 Hz market in Belgium, The Netherlands and Singapore. The Netherlands scheme entails the addition of a gas turbine topping cycle to a 600 MW gas-fired steam set at Eemshaven on the northeast coast. It was the largest unit in a programme which similarly converted six power plants between 1986 and 1988, creating fully fired combined cycles at efficiencies above 45%. Peterhead in north Scotland was a little-used steam power plant that was unprepared for the British privatisation which allowed Scottish utilities to build
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7.1 Cork, Ireland: one of two 30 MW steam turbines from 1954 included in the repowering of Marina power station. It was returned to service in 1979.
customer bases in England and to export south to them, and also to invest in power plants south of the border. Repowering one of the two 600 MW steam sets enabled Scottish Hydro to honour existing long-term gas contracts and to export the output to their English customers. Finally consulting engineers have designed a hybrid repowering scheme for a 1200 MW nuclear power plant with a specially adapted combined cycle taking a part of the wet steam produced by the reactor, superheating it and expanding it through the combined cycle and back to the reactor through a low-pressure exhaust heat exchanger that replaces the feedwater heaters of the nuclear steam turbine. The earlier repowering attempts were with smaller steam turbines of 30–50 MW dating from the late 1940s and early 1950s with non-reheat steam cycles at low steam conditions, but most of these used early versions of the gas turbines which appeared on the scene in the mid-1970s. The Marina power station near Cork, Ireland, which had received one of the first production units of the Frame 9B was followed by the repowering of Dublin North Wall, which had started life as an oil-fired peaking plant with three 15 MW steam turbines (Fig. 7.1). It was repowered as a combined cycle in 1983 in the first application of the GE 123 MW Frame 9E gas turbine which resulted in a 165 MW combined cycle. Both power plants were so much more efficient than the oil- and peat-fired stations which made up the Irish system, that both repowered plants were base loaded until the completion of a large coal-fired power station on the west coast, near Galway, in 1986. Another scheme at Jertovec, Croatia, used two of the Westinghouse W251 then rated at 33 MW with a 45 MW steam turbine and was completed in 1976, but these
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schemes were the exception to the rule and the gas turbine used in Dublin and competing models of similar output were starting to find markets for new combined cycles in Europe and Asia. In the developing economies of southeast Asia, and particularly in Thailand, Malaysia, Indonesia and Singapore, growth in electricity supply was starting from a smaller capacity base, but the demand for electricity was founded on foreign industrial investment and rising living standards. Generating sets were smaller, with the base load carried on sets of 120–200 MW which had been installed in the early 1970s. A third factor to encourage thoughts of repowering is what is now the universal problem of securing suitable sites for new power stations. An existing power station is broadly acceptable to the people living around it, and therefore it is generally easy to obtain consent to redevelop the site, particularly if the result is a plant with lower environmental impact, a different fuel and lower requirements for cooling water, and offering the continuation of employment. Sometimes this has meant redeveloping the site of a power station which had been demolished some years earlier but remained an electrical site by reason of having 132 kV grid connections running into the former plant’s substation. Several combined cycles in the UK have been so built on former power station sites. However, of all the combined-cycle plants built in the UK since 1990, the only one that could be considered as a repowering scheme was Derwent Cogeneration, which was effectively the repowering of Spondon H, near Derby (Fig. 7.2). This had been the only combined heat and power station to be built by the CEGB, the former nationalised utility. It had two 60 MW back-pressure turbines that supplied power and process steam to Courtaulds factory bordering the site, which produced nylon fabrics. The original coal-fired boilers were replaced in 1995 with four GE Frame 6B gas turbines and unfired heat recovery boilers which supplied steam, to the best of the back-pressure turbines, thereby creating a combined heat and power plant with an electric output of 214 MW. The power plant is now owned and operated by a consortium of International Power (23%), Mitsui (10%), Acetate Products Ltd, who are the steam user (17.5%), and Scottish and Southern Energy with 59.5%. Relatively few repowering schemes have been udertaken since 1990 and, in the USA, it has been to rejuvenate old steam plants and to replace the boilers to improve both efficiency and the environmental impact. The arrival of the F-class gas turbines at the end of the 1980s was the event which rekindled interest in repowering, because the gas turbines could support the available steam conditions without the need for supplementary firing. It was a repowering scheme at Fort Lauderdale, Florida, which was the first application for the Westinghouse W501F gas turbine in May 1993 (Fig. 7.3). Florida Power and Light were facing load growth of 3% a year and repowering the two steam turbines at Fort Lauderdale would be a quick and relatively trouble-free capacity addition to an existing site.
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7.2 Derby, UK: the repowering scheme Derwent Cogeneration. Four 38 MW gas turbines and heat recovery boilers replaced an old coal-fired boiler powering a 40 MW back-pressure turbine.
7.3 Fort Lauderdale, Florida, USA: two 125 MW steam turbines installed in the late 1950s, which were repowered by the first four Westinghouse W501F gas turbines in commercial operation.
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The utility have had a power station on the site, a few kilometres west of Fort Lauderdale airport, for 80 years and had installed two 125 MW steam turbogenerator sets there which went into service in 1957 and 1958. These were shut down in 1991 to demolish the rest of the plant so that the four gas turbines and their heat recovery boilers could be installed to create two combined-cycle blocks each of 375 MW. The two steam turbines were tandem compound units with reheat and each rated 125 MW. The gas turbines were site rated 125 MW at the 35 °C site ambient temperature. The units were manufactured in Japan at Mitsubishi’s Takasago works since they had been jointly developed by the two companies, and Westinghouse at the time had no gas turbine production site in the USA. In any repowering scheme the heat recovery boiler must be designed to achieve the best match to the steam conditions of the original steam turbine, and this depends on the mass flow and temperature from the gas turbine exhaust. In a purpose-built combined cycle the F-class gas turbines with their high exhaust temperatures (600 °C in the case of W501F) were designed with the aim of supporting a three-pressure reheat steam cycle, but in repowering a steam turbine there is only one live steam input and the reheater and the new boiler has to be designed accordingly. Steam turbines have always had to provide their own feedwater heating with bleeds into high- and low-pressure feed heaters and a deaerator. For the repowering scheme only two of the low pressure feed heaters were retained and linked into the condensate return to the heat recovery boilers. For the repowered sets the steam conditions were 103 bar and 540 °C with reheat at 27 bar and 540 °C. In this case the intermediate-pressure steam flow from the heat recovery boilers was not linked to the returning reheater flow to the steam turbine but instead used for steam injection into the gas turbines for emission control. Although some 10 years earlier Mitsubishi had developed the first dry low-NOx combustor system for their gas turbines, it was decided to use steam injection because intermediate-pressure steam could not be fed to the steam turbine and would in any case provide some power augmentation to the gas turbines at the high summer ambient temperatures. The first combined-cycle block went back into service at the end of May 1993 and the second a month later. A much larger repowering scheme, if it can be called that, was the Midland Cogeneration Venture which was a consequence of the antinuclear philosophy which had gripped the USA since the late 1970s and had led to the cancellation of many nuclear power projects in the aftermath of the 1979 Three Mile Island accident. One of the projects in this group was at Midland, Michigan, which had been planned as a nuclear combined heat and power station supplying the neighbouring Dow Chemicals plant with power and process steam. Midland was almost certain to be condemned because both reactors were the same two-loop Babcock and Wilcox design as the unit that had been destroyed at
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Three Mile Island. The Midland nuclear plant was abandoned in 1984 with the steam turbines almost complete. Then 2 years later a scheme was published to repower the steam turbines as a gas-fired combined heat and power scheme which would generate 1390 MW and supply up to 612 t/h of process steam to Dow Chemicals, making it the largest industrial combined heat and power scheme in the world. In January 1987 the Midland Cogeneration Venture was formed to build the gas turbine plant and to repower one of the steam turbines. MCVs customers were the regional utility company, Consumers Power for electricity, and Dow Chemicals for steam. The 12 gas turbines were the ABB GT11ND6 which was just coming into service at an ISO rating of 87.1 MW. Each gas turbine had a two-pressure naturalcirculation heat recovery boiler from ABB Combustion Engineering, six of which were equipped for supplementary firing. The total gas turbine output was 1045 MW with a further 355 MW from either one of the modified steam turbines This repowering scheme provided only one output to the steam turbine. Although the steam turbines were both modified to match the output of the heat recovery boilers better, they were not converted to two input pressures as would have been the case with a brand new purpose-built steam turbine. High-pressure steam at 63 bar and 371 °C is supplied to the steam turbine which has a single bleed from the high-pressure cylinder feeding into a pipeline going to Dow Chemicals. The low-pressure steam output, at 19 bar and 135 °C, reinforced by a steam bleed from the low-pressure cylinder is used for NOx reduction in the gas turbines and for preheating the fuel gas. The Midland Cogeneration Venture is now a joint venture of El Paso Gas, CMS Power and Dow Chemicals. It is the only example of an abandoned nuclear plant that has been repowered. Generally the nuclear turbines are much larger and with lower steam conditions than are found with a modern 180 MW class gas turbine in the 60 Hz market. A third American repowering scheme was definitely planned in response to environmental concerns. PSEG’s Bergen power station, located in Ridgefield, New Jersey, on the Hackensack River about 40 km north of Newark, was originally built as a coal-fired power plant but was later converted to gas firing. The two 200 MW cross-compound units went into operation in 1959 and 1960, respectively. Then 30 years later the boilers were at the end of their life and would have to be replaced. Bechtel Corporation, in San Francisco, were engaged to produce a report on the various options for renewal. Over the years the plant had gradually moved down the merit order as more efficient plant had come into operation. By 1990 it was running intermittently on a 30% load factor and with an efficiency of 28%. If the boilers were replaced with modern units, they would not significantly improve the performance of the plant and it would be unlikely to operate many more hours per year. The alternative would be to demolish the boilers and to install gas turbines and
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heat recovery boilers to turn it into a combined cycle. Four 100 MW gas turbines would be required to convert one steam turbine and the station output would rise to 600 MW with an efficiency of 42%. The environmental impact would be greatly reduced. There would be less visual impact with the removal of the two boilers and associated stacks. The lower profile of the turbine hall would conceal the gas turbines and heat recovery boilers when viewed from certain directions. With only one steam turbine, the second unit was mothballed pending future conversion to a second combined-cycle block, the direct cooling load on the Hackensack River could be eliminated and a bank of wet mechanical-draught-cooling towers used instead. In 1991, the utility ordered four Model V84.2 gas turbines from Siemens. These were chosen for their proven low-emissions performance. Units in Delaware were consistently returning NOx values of 9 vppm against a contract guarantee of 25 vppm. For Bergen, one steam turbine was shut down and the other was repowered with the four gas turbines. The repowered plant was completed and went back into operation in 1996. Later a new 1200 MW combined cycle was built alongside it. About 250 km northeast of Bergen, in Providence, Rhode Island, the same gas turbines were used to repower three steam turbines at the Narragansett Electric Company’s Manchester Street power station (Fig. 7.4). The plant is housed in a rather elegant architect-designed three-bay building located on a congested urban site beside a busy motorway. Here the decision was taken to demolish the existing boilers and to put the new heat recovery boilers in their place with the gas turbines mounted outdoors and exhausting back into the new boilers. Included in the conversion was the refurbishment of the steam turbines and upgrading of the smaller unit to match the 46 MW output of the other two. The repowered station was brought back into operation in 1995. In 2000, Narragansett and the other New England generators were taken over by National Grid Company of the UK. In Europe and Asia, where the 50 Hz system frequency results in having scaledup gas turbines between 250 and 300 MW, the potential for repowering the smaller steam turbines with a single gas turbine is certainly possible. Units of 120– 200 MW installed in the 1970s would have a reheat steam cycle at pressure and temperature compatible with what is obtainable from an unfired three-pressure heat recovery boiler. The two gas turbine models that have been used in such schemes are the Siemens Model SGT 5 4000F at 278 MW, and the Alstom 281 MW GT26B. Both gas turbines were designed with a dry low-emissions combustion system as standard and support reheat steam cycles in combined cycles at high-pressure steam conditions up to 160 bar at 540 °C . So far only three repowering schemes have been implemented with these gas turbines, two in Europe and one in Asia. In 1984, The Netherlands utilities decided to repower six power plants. These
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7.4 Providence, Rhode Island, USA: the repowered Manchester Street plant showing the location of the gas turbines exhausting to the heat recovery boilers between the steam turbine bays.
were not the traditional repowering scheme but rather the addition of gas turbines to an existing power station to add gas turbine capacity and to replace some of the feedwater heaters with heat recovery from the gas turbine exhaust. The largest plant to be converted was Eemscentrale 2 near Groningen, a 590 MW gas-fired unit with an efficiency of 40.5%. To turn this plant into a fully fired combined cycle required the largest gas turbine available which, at the time, was the Siemens Model V94.2 at its then rating of 130 MW. Although the gas turbine supplying combustion air replaced the original forced-draught fan, the gas turbine exhaust contained only 16% oxygen and therefore a small forced-draught fan was added to raise the oxygen level to the main burners. The gas turbine heat recovery unit had two heat exchangers of which the highpressure unit was coupled in parallel with the two high-pressure feed heaters and the low-pressure unit was connected across two of the four low-pressure heaters. The exhaust gas temperature at the exit of the heat recovery unit was 112 °C. Conversion raised the total station output to 697.8 MW, of which 127.8 MW is from the gas turbine and 571 MW from the steam turbine. The efficiency was 46.3% compared with 40.5% for the original unit. Then 10 years later gas turbines of more that 250 MW output were available and the repowering of the Rheinhafen power station in Karlsruhe, Germany, was the first application for the Alstom GT26 gas turbine announced at the beginning of
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1994. The utility, Badenwerke, had in their power station a 100 MW steam turbine dating from 1965. The repowering contract included refurbishment of the steam turbine, which increased its output to 120 MW and, with steam conditions of 156 bar and 540 °C at the turbine stop valve, the decision was taken to install a once-through heat recovery boiler. A two-pressure steam cycle was chosen with reheat and the boiler was fabricated by EVT GmbH, of Stuttgart. This was the first application of a once-through boiler to a combined cycle and the decision was made solely on the basis of the existing steam pressure. A pressure of 156 bar was higher than any operating pressure so far applied to a combined cycle. In fact, the first examples of single-shaft combined cycles with F-class gas turbines were being built at the same time and would be the first to have high-pressure steam conditions above 100 bar in a reheat steam cycle. At King’s Lynn, England, which went into operation in November, an early version of the Siemens SGT54000F had a high-pressure steam output of 231 t/h at 101 bar and 520 °C; Gent Ringvaart, Belgium, which was one of the few single-shaft combined cycles with GE Frame 9FA, has a high-pressure steam output of 275 t/h at 112.5 bar and 536 °C. Rheinhafen showed that the higher steam pressures found on the turbines that were candidates for repowering required a new approach to design of the heat recovery boiler. Rheinhafen was one on its own, and it would be another 10 years before there would be a significant number of combined cycles operating at pressures above 120 bar. The Rheinhaven experience immediately benefited the GT24 single-shaft blocks in the USA and Mexico. American National Power were planning to install combined cycles in New England and Texas which would be merchant plants. The resulting single-shaft blocks have a two-pressure heat recovery boiler with a oncethrough high-pressure section operating at 160 bar and 560 °C. All GT24 combined cycles in the USA and Mexico are of this design. Two repowered plants that followed in the 50 Hz market have certain features in common: firstly, that the repowering contract included the refurbishment of the steam turbine which would give new computer-designed blading and bearings for up to 10% increase in power output and, secondly, that the heat recovery boilers would all be vertical assisted-circulation designs and operating with a highpressure output between 125 and 130 bar. Using a vertical heat recovery boiler gave two advantages. Firstly, that it was a more compact design which could be easily installed in the relatively restricted confines of an existing power station site. Secondly, even in its natural-circulation form, it had much lower thermal inertia because the heat transfer tubes were horizontally mounted across a vertical gas path and supported in vertical tube plates hung from the top of the boiler frame. With this arrangement, full power can be reached in less than 1 h from the start, and in that respect it is compatible with the original loading time of the former steam turbine plant.
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The Electrabel power plant at Vilvoorde, in the northern suburbs of Brussels, began as a coal-fired power station with three 125 MW sets, which was completed in 1965. Later it was converted to oil firing and in 1998 the utility decided to repower one of the sets. The chosen gas turbine was Siemens SGT5-4000F at its then rating of 245 MW with a two-pressure heat recovery boiler and reheat. The repowered plant went back into operation in August 2000. Belgium has a large nuclear base load meeting approximately 50% of electricity demand in the country. The repowered plant was operated in support and, like other combined cycles in Belgium, operates in a load-following mode. The plant will start up on Monday morning and run through to Saturday afternoon, with every weekday night a reduction to about 50% of full load and generally a 36 h shutdown at weekends. In Singapore, repowering the Senoko power plant was more of a challenge. Senoko on the north side of the island overlooking the Straits of Johor had been developed over 30 years with three oil-fired steam plants of which the first, with three 120 MW sets, was completed in 1970. In 1998, Singapore signed a long-term natural-gas supply agreement with Indonesia. Deregulation of electricity supply had separated the three active generating plants at Senoko, Pulau Seraya and Tuas into separate generating companies under Temasek Holdings in preparation for future privatisation. All three companies announced plans for gas-fired power plants. Pulau Seraya and Tuas built new combined cycles, but Senoko which was the largest and had the most congested site decided to repower the oldest of the steam plants. The gas turbines were to be the Alstom GT26 on account of their high part-load efficiency. The Senoko power stations were built on a narrow strip of land between a main road following the north shore of the island and the coast. The plants were built with the boilers facing the sea with a site access road and the feedwater treatment plants between them and the edge of the quay. By 1990, the gas supply network in Malaysia had reached Johor Bahru at the northern end of the causeway, and a supply was negotiated for the Senoko power station. Later four simple-cycle gas turbines were installed. These were the Siemens Model V94.2 in a later, more powerful version than the two oil-fired units at each of their peaking stations at Pasir Panjang and Jurong. In 1997, the four Senoko units were converted to a combined cycle to gain operating experience once it was known that a long-term gas supply was in prospect at the end of the decade. Power Senko, the management company, had no spare land available and decided to repower the three oldest sets as combined-cycle blocks but, because of electicity demand in Singapore, they could convert only one unit at a time. It was therefore decided to shut down one unit in March 2001 to demolish the boiler and to create space for a gas turbine, its heat recovery boiler and a pathway for steam pipes through the building to connect the steam turbine to the new heat
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recovery boiler. What was also realised was that because the gas turbine had an output in excess of 240 MW, this would mean a combined cycle of the same output as the original power plant with 360 MW from three steam sets. Once the new combined cycle was up and running, it would be safe to shut down the other two sets and to convert them. In any repowering project for steam turbines of the 120–150 MW range the steam turbines are almost always out of warranty, which makes it possible for the repowering contract to include a clause covering refurbishment of the steam turbine. The original steam turbine at Vilvoorde was a Brown Boveri design, which was refurbished by Siemens and the three turbines at Senoko were by Hitachi and were refurbished by Alstom. This is inevitable since the steam turbine has to be optimised to the gas turbine and heat recovery boiler to obtain the best performance of the repowered system. A steam turbine designed 30 years ago used much simpler design technology than today, as the technique of computer blade profiling was not available. A modern computer design would split the incoming fluid flow into the same number of parallel paths as there were blades in a single stage. So a blade would be designed to maximise the work that could be done and at the same time minimise the leakage around the edges and over the blade tips. The output of the first stage so calculated would then be the input condition for the second stage and so on to the last stage. The blade profile calculations are then passed to the machine tools which will make them and, in fact, the resulting rotor is designed to match the length and the interstage dimensions of the original unit and can be simply dropped into place. Bearings would in any case be changed and the combination of all the modifications would result in a more efficient turbine matched to the steam conditions of the new heat recovery boiler. Similar modifications can be made to both the high- and the low-pressure turbines and for the low-pressure turbine there is the additional input of the lowpressure steam from the heat recovery boiler. Although the Senoko steam turbine is a refurbished old unit, it is set up much as a new machine would be in a combined cycle designed by Alstom without utilising any previous work. The high-pressure steam goes to the turbine and returns to join with the intermediate-pressure output as the reheated supply. The low-pressure steam goes to the crossover point at the low-pressure turbine. For Senoko the low-pressure steam is superheated, but in the standard GT26 single-shaft combined-cycle block the low-pressure supply is saturated and is also used as pegging steam to the deaerator. The first conversion was ordered from Alstom in July 1999, as the first examples of the uprated GT26B went into operation in England and of the GT24B in the USA (Fig. 7.5). In the summer of 2000 it was found on units coming into operation in the UK and the USA that there was inadequate cooling of the second-row blades in the main power turbine. This meant that early production units, including the first Senoko unit, would have to run at a lower output to stay within safe turbine inlet temperature limits, pending a solution.
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7.5 Senoko, Singapore: one of three 40-year-old 120 MW steam turbines modified for a three-pressure steam cycle and refurbished by Alstom as part of the Senoko repowering contract.
Alstom evolved a two-part strategy to resolve the problems. This was to solve the cooling problem and to apply the necessary improvements to turbine blade profiles and materials. This initial package of modifications was applied to all production units, which included the first Senoko machine that was fired up for the first time in September 2002. The gas turbine was still underpowered, and other improvements to recover lost output centred on a new compressor with revised blade profiles giving a greater mass flow at a higher pressure ratio of 32:1 and hence a higher output. Existing operators were given the blade sets to install in the existing compressor at a convenient maintenance outage. By the summer of 2003, the first unit with the new compressor was already in operation in Spain at the final specification above the original GT26B rating, and all new units, including the second and third units for Senoko, were being shipped with the new compressor installed (Fig. 7.6). These arrived on site at the end of 2003. The repowered second unit went back into operation in July 2004 and was followed by the third unit in December. In October of the same year, the gas turbine of the first unit had been due for its first major repair outage, and at this time the new blading was installed in the compressor together with changes to the profile of the struts supporting the exhaust gas housing. This measure is necessary to reduce the pressure loss with the greater mass flow. Since the end of 2004, Power Senoko have run all three units on base load and are generally dispatched at between 330 and 340 MW. This includes the 10% spinning reserve which all operating units in Singapore are required to carry. Fuel
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7.6 Senoko, Singapore: two of three GT26 packages installed in the former boiler house of the repowered Senoko power station.
supplies can come from either Malaysia or Indonesia and are guaranteed to provide 100% cover at all times. One other repowering project in Europe features the largest steam turbine so far used in such a scheme: one of two 600 MW units at Scottish and Southern’s Peterhead power station some 60 km north of Aberdeen. The plant was built by the North of Scotland Hydroelectric Board and went into operation in 1980 just as the main oil and gas fields in the northern North Sea were coming into production. For the first 10 years the plant ran on oil, but it was only during the 1984–1985 UK miners’ strike that Peterhead ran on base load. The Miller gas field was discovered in the late 1980s but was found to contain sour gas which could not be fed into the public supply network but could be burned in the power station. So the North of Scotland Hydroelectric Board had a long-term gas contract on a take-or-pay arrangement and the station was the only market for Miller gas for as long as the field remained productive. The decision to repower followed the privatisation of the electricity supply industry, which was completed in Scotland in 1992, and the opening up of the wider market. Until then the North of Scotland Hydroelectric Board had been constrained to serve only the Highlands and Islands of Scotland, which included the growing industrial centre of Aberdeen but, as the privatised Scottish Hydro plc, it could supply anyone in the UK and was only limited in the capacity of the two 400 kV lines going to England. Peterhead had two 660 MW steam turbines, which had fewer than 100 000 operating hours on them. In 1998, the outright purchase of the 700 MW Keadby combined cycle in
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Lincolnshire and the takeover of Southern Electric created the present Scottish and Southern Energy plc, with a large customer base in England. It was then that the decision was taken to repower Peterhead and at the end of the year a contract was awarded to Siemens for a repowering scheme using three SGT5-4000F gas turbines. Peterhead is not a conventional repowering scheme, since the original boiler is maintained in operation, and the three gas turbines supply steam to the original turbine, which is effectively run at part load. In this mode of operation, the combined cycle is rated at 1140 MW at an efficiency of 57%, with about 360 MW from the steam turbine. In retaining the original boiler, additional topping steam can be supplied to bring the steam turbine up to its full output. Then the output rises to 1410 MW at 51% efficiency. This is known as hybrid mode and it can be used with all three, or two, or only one gas turbine. Hybrid operation with just two gas turbines has in fact been the preferred configuration during the early years of operation. The gas turbines are supplied with natural gas at up to 70 bar, which is fed to a separate terminal on the Peterhead site to supply the three Siemens gas turbines which, with a compression ratio of 16.4:1, require a minimum pressure of 30 bar to fire. Miller gas is at a much lower pressure and is only supplied to the fired boiler when in hybrid operation. The second steam set, which was not repowered, continues to burn Miller gas. For such a flexible arrangement of plant, with one, two or three gas turbines and a fired boiler running, or no fired boiler and just three gas turbines running in combined-cycle mode, it is not a simple steam cycle. The heat recovery boilers are a conventional natural-circulation drum type, with a three-pressure reheat cycle for a gas turbine burning natural gas. The design pressure is 130 bar, but generally they operate at much lower fixed pressure when operating in pure combined-cycle mode. The steam turbine though operates under sliding pressure. When in hybrid mode the steam pressure from the fired boiler is set from the output of the heat recovery boilers, which is then raised to the full 130 bar. Integration of the two steam systems is further complicated by the fact that it is a reheat cycle. The control system has first to balance the steam pressures entering the steam turbine. The cold reheat flow out must be divided between the three heat recovery boilers and the reheater of the fired boiler. The hot reheat, supplemented by the intermediate-pressure output of the heat recovery boilers, then returns to the steam turbine. The feedwater heaters for the steam turbine are retained and operate when in hybrid mode. These are heated by steam bleeds from the turbine and exhaust to the condenser. The feed heating from the heat recovery boilers is performed in the low-pressure economiser of each unit. In operation, emissions have fallen dramatically, with sulphur dioxide down by over 90%, carbon dioxide at half the former output, and NOx reduced by 85%. Scottish and Southern place great store by availability, which in their view is the
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7.7 Peterhead, UK: a 600 MW steam turbine installed in 1980 and converted with three gas turbines to a hybrid system. It is one of the largest to be repowered so far.
key to profitability. They have the most efficient generating set in Scotland and want to use it to the full. For that reason, they have kept the new part of the plant simple. They do not have fuel gas heating, which would introduce an additional complication to the balancing of the steam circuits. They do not run the gas turbines at their maximum continuous rating. Instead they prefer to run them at a slightly lower output. This, of course, reduces wear but still provides a highly efficient combined-cycle package which compares favourably with that of conventional combined-cycle blocks using the same gas turbine. The repowering scheme at Peterhead retains the original fired boiler to work in hybrid mode with any of or all the three gas turbines (Fig. 7.7). A not dissimilar arrangement has been studied for a nuclear power plant by the Anglo-American consultants Parsons Brinckerhoff. It is a hybrid system with a modified combined cycle linked to the steam cycle of a nuclear power plant. There is only one gas turbine which could be a modified single-shaft block, and the only operating modes are either together or separately. During the last few years in the USA there has been a significant improvement in the nuclear performance with the renewal of licences for operation for a further 20 years. It is this market which is being considered for this application, since it would increase the output of the site at higher efficiency. The difference in the nuclear case is that the high exhaust temperature of the modern gas turbines enables some of the nuclear-generated steam to be superheated in the heat recovery boiler to achieve further output. The fully-fired com-
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7.8 Proposed linkage of a combined cycle with a nuclear plant. 10% of nuclear steam is superheated and the condensate is returned through the low-pressure section to heat the feedwater.
bined cycle 40 years ago used a 25 MW gas turbine with a 100 MW steam turbine. The nuclear case in North America would use a 190 MW air-cooled gas turbine with a once-through heat recovery boiler and a separate low-pressure section. Effectively it borrows an equivalent volume to the steam used for feed heating, which it superheats before returning it to the reactor through a low-pressure preheater section that replaces the feedwater heaters of the nuclear steam turbine. The proposed nuclear system would would have a 1275 MW reactor supplying about 10% of its steam output to a combined cycle with an enlarged once-through heat recovery boiler (Fig. 7.8). A study for a scheme in the USA based on a Siemens SGT6-5000F and a 1275 MW pressurised-water reactor nuclear plant shows that the steam turbine capacity would be 260 MW when coupled to the nuclear steam supply half as much again as the capacity of the gas turbine which is 190 MW. Pressurised-water reactors generally have two or four heat exchangers in parallel supplying wet steam with about 0.5% entrained moisture to a large steam turbine with typically three low-pressure cylinders. Feedwater from the condenser would be preheated by steam bleeds off the turbine. The greater power density of the combined cycle and its inherently higher efficiency is the basis of the hybrid design. A standard gas-fired single-shaft combined cycle with the above gas turbine would be rated at 260 MW incorporating a 90 MW three-pressure steam turbine. For the hybrid system, about 10% of the energy from the nuclear plant is sent to the combined cycle for which the heat recovery boiler is a once-through single-pressure system with an additional lowpressure feed heater. In the optimised system the volume of steam used for
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feedwater heating from the nuclear steam turbine is equivalent to the volume sent for superheating to the combined cycle. Wet steam from the nuclear plant is superheated to 560 °C and sent to the steam turbine of the combined cycle which is a single-pressure design with no reheat. Condensate is returned as feedwater to the heat recovery boiler where a separate low-pressure heat exchanger takes over from the conventional feed heaters on the nuclear set. The heated water returns to the nuclear heat exchangers at about 230 °C. Heat used to evaporate the high-pressure steam is not required from the gas turbine, because that has all been carried out by the reactor. The combined cycle produces dry steam at 560 °C, which is the normal high-pressure steam temperature for an F-class gas turbine. The steam flow is greater but at a much lower pressure. Typically a pressure of 60 bar as compared with a pressure of 120 bar for a normal combined cycle; hence a single pressure with no reheat is required. The hybrid system gains in output by about 8% of the combined output of separate plant capacity with the same fuel consumption and emissions, but for the whole plant the 1275 MW reactor output has been boosted to a net 1642 MW with the output of the combined cycle and the extra output on the steam turbine resulting from the external feed heating system.The combined-cycle efficiency is about 63% and that of the whole plant 37%, which is better than all but a few supercritical coal-fired plants. This is a notional efficiency calculated on the basis of fuel energy to the gas turbine and electricity from its generator. High efficiency can only be achieved in the hybrid mode. Operating separately from the reactor, as would most probably happen during the nuclear refuelling and maintenance outage, the combined cycle can only generate as much steam as the gas turbine exhaust permits. For an SGT65000F in a normal combined-cycle arrangement the steam turbine would be rated at about 90 MW. So, when separated from the reactor, the combined cycle would be running with the steam turbine on a 30% part load, but the site would continue to earn revenue during the nuclear outage. There is still much to be decided before a commercial system can be built. The combined cycle must be able to run independently if the nuclear plant is down, and vice versa. The normal operating system would be first to start up the combined cycle and then to change to nuclear wet steam and similarly to transfer the nuclear feedwater heating to the low-pressure sections of the heat recovery boiler. When the combined cycle shuts down, feed heating returns to the nuclear set. Similarly, if the combined cycle trips, the nuclear plant will stay in operation and feedwater heating automatically goes back to the nuclear steam turbine. There should be no conflict of interest in maintenance. The nuclear maintenance outage is timed to the refuelling outage and occurs at intervals of between 12 and 16 months depending on the design of the fuel and its rate of burn-up. Gas turbines normally have an annual inspection or maintenance which varies over a 4 year cycle. A large F-class gas turbine would see a major maintenance outage every 4 years.
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Given that the nuclear plant runs in pure base load, the gas turbine linked to it would also run in base load. The first application could be applied to an existing station in the USA being licensed for a life extension, or a brand new station such as the 1600 MW European pressurised-water reactor. The other advantage is that the combined cycle is built on an existing site and could output to the existing substation and continue to operate after the nuclear set has been shut down and decommissioned. Repowering is, for all this, very much a niche market for gas turbines. The examples above illustrate this with the emphasis on extending the life of existing power plants, particularly in urban areas. Derwent Cogeneration was an example of replacing a time-expired coal-fired boiler for a combined heat and power scheme which had been supplying process steam for 40 years. Midland Cogeneration with a gas energy source was used to replace a nuclear power plant which had been cancelled when almost complete. All the other plants are of similar age which have been in time moved to the bottom of the merit order as more efficient power plants came on to their systems. The Senoko project in Singapore must be viewed against that country’s deregulation policies which separated the three generating companies into operating divisions of Temasek Holdings pending privatisation. While the other generators were able to build new combined cycles, Senoko had no room for this and instead elected to repower the oldest of three oil-fired stations.
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8 Combined heat and power
As gas turbine development gathered pace in the 1970s, one response to the 1973 oil crisis was a growing chorus of opinion asking for the wider application of combined heat and power schemes. Given that the efficiency of the average coalfired power station from coal to electricity was at best about 35%, critics could easily point to the fact that, for every kilowatt hour of electricity produced, two were wasted into the environment up the stack and into the cooling water. Many cities in northern Europe were held up as examples of what could be done with district heating, notably Stockholm, Västerås and Malmö in Sweden, and Helsinki in Finland, where coverage of the city centre and the surrounding housing areas was over 90%. In Europe in particular, the UK, France and Italy had monolithic state-owned utility systems whose function was to generate electricity efficiently, which was at the lowest possible cost and securely supplied to every consumer in the land. Outside Europe, similar arrangements existed with state-controlled utility systems in many countries. In the UK, for instance, any private power plant would have to be built and operated to the same exacting standards as if it were in the public power system. In Japan there were a number of industrial power plants, but they were not allowed to operate in parallel with the grid. They could start up while the site was taking power from the grid, but as soon as they got up to full power, they had to break the connection and operate independently until they shut down. In France, because of the large nuclear component of power supply, no combined heat and power scheme could compete on electricity costs for 9 months of the year but, as electricity demand increased in the winter months and EdF increased its power tariffs, then electricity from a gas-fired combined heat and power scheme became competitive. For the industries with such schemes, running the gas turbine reduced their electricity costs in the winter months and took the equivalent demand off the public system. Outside this period the company would run the fired boiler to produce steam, and electricity would be bought from the public system. Resistance to combined heat and power was widespread. To bleed off steam to 154 WPNL2204
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supply, say, a paper mill meant that there was less steam available to generate electricity and the price that the utility could obtain for the steam was less than it could earn for the electricity. Furthermore, steam demand did not always follow electricity demand. Yet by 1990 there had been installed a large number of small combined heat and power schemes for specific industries in which the efficiency expressed in terms of useful energy out against fuel energy in was calculated at around 80%. By 1973, the efficiency of the best available gas turbines was about 25%, this meant that they exhausted a large volume of hot gas at about 400 °C which could be used to generate steam. However, the industries that built their own schemes used small gas turbines with supplementary firing as necessary so that all the steam and power demand could be met by the power plant and none would be available for export to the grid. Indeed many electric utilities offered deterrent payments for purchased power which would have made such a scheme uneconomic. For a gas-turbine-based combined heat and power scheme, to an extent, heat and power demands can be balanced by using supplementary firing in the heat recovery boiler to vary the steam output. Not only that, but some boilers were fitted with forced-draught fans which enable them to be operated independently of the gas turbine during its maintenance outages. If the gas turbine were sized to meet just the power demand of the industry, then there would be nothing to sell, and a back-up connection to the grid would cover maintenance of the gas turbine. District heating, as in many European cities, is a power plant supplying heat to a pressurised-hot-water mains system which distributes heat to public buildings and private dwellings around the city centre. The other is a similar but smaller system feeding a specific site such as a university campus or other large estate of public buildings, laboratories and workshops. Such schemes are seasonal in operation and are working in full combined mode for no more than 7 months of the year. The first district heating schemes were based on back-pressure steam turbines. Some early schemes in North America and Europe used steam as the heating medium and were limited in the distance that they could transmit heat. Consequently district heating has never become popular in the USA but in Europe, particularly after the Second World War, district heating was extended with pressurised hot water as the medium, which meant that hot water was sent out at between 110 and 130 °C and returned at between 50 and 70 °C. There are still a large number of back-pressure turbines in district heating schemes in eastern Europe and the CIS. Many of these are now being or have been replaced by combined-cycle plants with condensing–extraction turbines. Some of the first installations were in East Germany and Hungary. With this arrangement, all the steam can be applied to the district heating condensers during the winter months, and then in the summer, when there is less demand for heat, the turbine’s condensing tail becomes operative and the plant functions as a combined cycle. This makes greater use of the power plant since in the summer months, when it
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operates as a combined cycle, it would be the most efficient power plant on the system. A number of large combined cycles have been installed for district heating in South Korea, in which a synchronous self-shifting clutch has been installed between the intermediate- and low-pressure cylinders. During the heating season the clutch is open and the low-pressure cylinder is at standstill. The turbine is effectively operating as a back-pressure turbine with the high- and intermediatepressure cylinders. Then in summer the clutch is closed, the district heating condensers are shut off and the unit operates as a combined cycle with an efficiency of about 56%. The opportunities for combined heat and power over much of the world did not appear until after deregulation of electricity supply in the early 1990s; this effectively separated generation from transmission and distribution which allowed independent power producers into the market. This was only possible because the enabling legislation also defined the terms of power sales contracts. More than 10 years earlier, in 1979, the PURPA law was introduced in the USA by the Carter administration. Under this measure, anyone could build a combined heat and power plant and would be guaranteed market price for their electricity sales back to the grid. To qualify, a PURPA plant had to have a dedicated steam host, which was generally a large industry such as a paper mill or a chemical plant. The fact that the USA was a country of over 200 million people with a largely uniform lifestyle meant that many industries were on a much larger scale with production plants in different regions of the country each serving a market larger than that of many other countries in total for the same product. Thus, if one factory in, say, Texas installed a combined heat and power scheme, an enlightened management could install similar schemes in their other factories. The larger American schemes would be combined-cycle plants with one or more GE Frame 7EA or Westinghouse 501D or ABB GT11N gas turbines, with most of the large installations in California, Texas and the northeastern states. A number of schemes used large aero-derivative gas turbines such as the GE LM2500 rated at 25 MW and the 33 MW LM3000 which was later replaced by the 42 MW LM6000. Many of the smaller schemes were simply a gas turbine and heat recovery boiler supplying steam to an existing turbine on the site. PURPA led to the application of low-emissions combustors across the gas turbine industry, but it also saw the introduction of an innovative steam turbine design which would later be applied to combined-cycle merchant plants. To improve the efficiency of small industrial steam turbines, ABB found that, by splitting a single-cylinder turbine into high- and low-pressure sections and by changing the rotor diameters and speeds to optimise the efficiency of each section, it would result in a more efficient turbine, even allowing for the gearbox that reduced the high-pressure turbine to synchronous speed. Known as VAX, among the first schemes in the USA to use this turbine was Richmond Cogeneration, a 240 MW combined cycle with two GT11N gas turbines and a 90 MW VAX turbine completed in 1991 (Fig. 8.1). Then 4 years later Air
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8.1 Richmond Cogeneration, USA: a 240 MW combined cycle with two GT11N gas turbines and a VAX-type two-speed steam turbine, which supplies steam to a board mill 30 km south of Richmond, Virginia.
Products installed a single-shaft combined cycle for a combined heat and power scheme in Orlando, Florida. This was a single-shaft block with a GT11N and a 50 MW VAX steam turbine which went into operation in 1995. The company were already looking at the combined-cycle market for the VAX turbine and in June 1999 installed a 160 MW single-shaft combined cycle at Dighton, Massachusetts. This plant had the more powerful GT11N2 and a 50 MW steam turbine. In this scheme the clutch is mounted between the generator and the gearbox on the low-pressure side with the high-pressure cylinder on a parallel shaft running at 8900 rev/min. Dighton, in fact, and the Orlando unit before it can be considered to be the test plants preparing for the GT24 single-shaft units to follow. Privatisation in the UK was the event that led to the opening of the market for industrial power plants around the world as other countries followed the British example. The new generating companies quickly established project engineering divisions to develop combined heat and power schemes. A typical plant could be on a plot of land outside, say, a paper mill. The mill had an old boiler plant which it wanted to replace and was intending to install a new paper machine. The generating company would design a power plant which would export steam over the fence to the paper mill but feed the power into its network and then sell it back to the industry. Several such schemes were built, some of them combined cycles incorporating new or existing steam turbines. Buying electricity from the grid rather than direct from the power plant provides additional security, since power plant maintenance
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8.2 Southdown Cogeneration, New Zealand: a 120 MW combined cycle with two LM6000 gas turbines, which supplies steam to a neighbouring paper mill and power to the city of Auckland.
is covered by the power company who can continue to supply from another source. It depends on the importance of having a continuous electricity supply to the process. One of the largest schemes in the world is at Wilton on Tees in northeast England with eight 133 MW gas turbines in two groups of four supplying a common steam range feeding two 400 MW steam turbines supplying process steam to the ICI Wilton chemical works. The fuel supply for this plant was obtained by stopping flaring on a number of North Sea oil platforms and directing the gas into a collector main which fed into the British Gas system. However, schemes such as Wilton in the UK, and Midland in the USA, which both have about 1800 MW electric output, are the exception. Most combined heat and power schemes are specific to a particular industry, such as a paper mill (Fig. 8.2) or a chemical plant, and are generally of a size that will guarantee steam supply and cut electricity import from the grid. If all the electric load is covered by the power plant, there may be times depending on process demand where there may be a few megawatts available for export. Maintenance of the power plant would be covered by a back-up power supply from the public grid. As other countries outside Europe deregulated electricity supply, they also created opportunities for combined heat and power schemes. However, as a general observation, combined heat and power has only succeeded where legislation
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has allowed it to happen. Even then the future of combined heat and power can be influenced by fuel prices and public policy. The New Electricity Trading Arrangement introduced in the UK in April 2001, for a while, effectively killed combined heat and power there. The immediate effect of this measure was a sharp reduction in the price of electricity. It almost reduced British Energy, the nuclear operator, to bankruptcy and, for the existing combined heat and power operators, the higher costs of producing power and steam from their own plant, even with the then current gas prices, made it cheaper to buy power from the grid and run the existing back-up package boilers to produce steam. A further opportunity for combined heat and power is in the growing trade in LNG. In the receiving country the gas has to be evaporated. If a combined heat and power unit is built beside the gas terminal, the heat output of the plant can be used to evaporate the gas and the electric output can be used to drive the various pumps and the compressors that raise the gas pressure for transmission, which in the UK is 70 bar. The National Grid has a gas terminal on the Isle of Grain about 70 km east of London at the confluence of the Medway and the Thames which is the site of a new LNG import terminal. In the spring of 2007 they obtained consent for a combined heat and power plant to evaporate the liquefied gas. The power plant will consist of three single-shaft blocks of Alstom GT 26B with a low-pressure extraction from each steam turbine which will supply hot water to evaporate the liquid gas. It was mainly in the countries without monolithic state-owned electric utilities that the main market lay for combined heat and power applications in Europe; this was mostly The Netherlands, Germany, Denmark, Sweden and Finland. However, as a general view, widespread application of combined heat and power required legislation by an enlightened government. In the Middle East and notably the United Arab Emirates, combined heat and power is the basis of electricity supply expansion. In 1977 the Ruler of Dubai decided to follow Bahrain and to build an aluminium smelter together with a gas turbine power station to supply the electricity required. The power plant consisted of 12 gas turbines: eight Frame 5P and four early model Frame 9B, each of which had a heat recovery boiler supplying steam to a multistage flash distillation unit. It went into operation in 1979 with initially three potlines which have since been extended to six. In more than 25 years since the refinery was built, the population has grown rapidly with the influx of Asian workers and Western and Japanese businessmen to build and operate the new infrastructure. The population needed water before electricity. The power plant no longer supplies Dubai City, but they do supply bottled water to restaurants and a regular procession of tanker trucks takes water to the smaller emirates further north. Public water supply for the city now comes from Dubai Electric’s Jebel Ali power plants.
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8.3 Al Taweelah, Abu Dhabi: along the Gulf Coast, power plants which are designed with great flexibility so that the public water supply is virtually independent of the availability of the gas turbines.
The Jebel Ali power plants were built as combined cycles in a configuration that guarantees that demand for water is virtually independent of power demand. Similar plants have been built at Al Taweelah, Abu Dhabi (Fig. 8.3), and on a new site in Dubai at Al Shuweihat where the first 1500 MW of ultimately the 5000 MW planned for the site came into operation at the end of 2004. These dual-purpose plants are designed so that water supply is independent of the availability of the gas turbines. Three 280 MW gas turbines with fired heat recovery boilers supply steam to two turbines each in turn supplying two multistage flash distillation units. The fired boilers each have a forced-draught fan which allows them to operate if the associated gas turbine fails for any reason. Similarly, if the steam turbine is down, the outputs of the heat recovery boilers can be throttled down and connected to the headers feeding the distillation units. Operating in this way, water supply can be guaranteed all year round and therefore it is electricity demand which is the determining factor as to when the gas turbines will run. In the United Arab Emirates there is a low demand for electricity in the winter months and, as soon as the hot humid weather creeps up the Gulf coast towards Kuwait, the air-conditioning load builds up and electricity demand is almost trebled. Since these plants were built, the landscape has changed remarkably as a result. Modern sewage works have been built to keep pace with water demand and the clean water effluent is used for irrigation. As a result, there is in Dubai a championship golf course, one of three in the United Arab Emirates, and extensive tree planting conceals the smelter and the Jebel Ali industrial zone from the main Abu Dhabi road.
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Elsewhere, supplementary firing can even out differences in process steam and electricity demand. All along the Gulf Coast the demand for water is met through combined heat and power schemes from the sea. Growth in public demand for water is what determines when and where a new power station will be built. Another country with a special requirement for combined heat and power is India. The grid system is inherently unstable because of the long distances between the power plants and the major load centres. Large variations in frequency occur from day to day and, for an industrial plant with electrically driven pumps and compressors and processes controlled by timers, an unstable frequency can seriously affect production. A number of industries decided that the only way to resolve this problem was to build their own power plant and to run it in island mode, independently of the grid. To be successful a plant had to be flexible in being able to operate power and steam supply separately. Such a plant would have two or three small gas turbines which would carry spinning reserve to cover shutdown of one gas turbine for maintenance. There would be a separate fired boiler to back up steam supply from the heat recovery boilers. The steam turbine would supply the process pressures which would be covered by throttling down from the high-pressure output, and there would be some supplementary firing to cover variations in steam demand. Elsewhere, deregulation effectively made industrial power plants available around the world by opening up the market to private power generators. Prior to this, although industrial schemes had been built in many countries, their scope of operation was limited by the pricing policies of the public electric utilities. In some countries, deregulation of electricity supply has followed a somewhat different path, e.g. in Thailand where the Government as owner of the original public utility maintains ownership of the grid and continued to control the planning of generation according to power demand. The Small Power Producers Act allowed for industry to develop its own power plants. If it was planned to build a gas-fired combined cycle, then it qualified for a long-term power sales contract to the Electricity Generating Authority under which they would supply, say, 60 MW per generating unit. This made it attractive to build up a large steam load on an industrial estate which could all be supplied from unfired heat recovery boilers, on several gas turbines suitably sized to ensure that they would obtain the EGAT contract and would be able to supply them independently of steam demand (Fig. 8.4). The reunification of Germany brought about the renewal of district heating plants in some of the major cities of the former GDR. These were coal-fired plants with back-pressure turbines, some of them predating the Second World War. Dresden was the first city to adopt a combined cycle with two of the Siemens 65 MW SGT-1000F gas turbines and a single condensing–extraction steam turbine. This was followed by new district heating schemes for Chemnitz, Leipzig and Halle.
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8.4 AMATA EGCO, Thailand: a 180 MW combined cycle which supplies steam to an industrial estate at Bang Pakong and has a long-term power sales agreement with EGAT for each generator.
The SGT-1000F, at its current rating of 65 MW, is the smallest of three scaled F-class gas turbine models introduced in 1995 and has been sold to a number of combined heat and power schemes around the world, all in the form of a combined cycle with extraction from the steam turbine. The other small F-class machine is the GE Frame 6FA model derived from the 250 MW Frame 9FA. This, too, has found application in large industrial combined heat and power schemes and small combined-cycle plants. Both machines incorporate the technology of the large F-class machines, particularly in the design of turbine and compressor blading and improved turbine cooling. Both have cold-end drive to the generator, and dry low-emissions combustors. Because both turbines are scaled down from larger 3000 rev/min designs, under the rules of similarity they cannot run at a synchronous speed and must therefore drive the generator through a gearbox. Both gas turbines can therefore be applied to schemes in the 50 and 60 Hz markets. The rated speed for the SGT-1000F is 5400 rev/min, and for the Frame 6FA it is 5230 rev/min. Several of the larger gas turbines of the E-class have also found niche markets in district heating and industrial combined heat and power schemes. The main contenders here for the 50 Hz market are the Alstom GT13E2 and the GE Frame 9E, both of which run at the 3000 rev/min synchronous speed. Both gas turbines have been successful in winning orders for large combined heat and power schemes at French oil refineries.
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8.5 SembCorp Cogeneration, Singapore: a 650 MW combined cycle of flexible design which sends all electricity to the national power pool and supplies process steam to a large industrial estate.
A few schemes have been built with the F-class machines either serving large industries such as oil refineries or chemical plants, or else a cluster of smaller industries concentrated on an industrial estate. SembCorp Cogeneration in Singapore is an example of a large combined heat and power scheme serving a whole industrial estate (Fig. 8.5). The project is located at Sakra on a 2 hA site within a 3000 hA land reclamation which has created a centre for the petrochemical industry on the southwest corner of Singapore. SUT Sakra owns a large above-ground pipe network which supplies process steam at three pressures from its own boiler plant, together with high-grade industrial water, chilled water, sea water for cooling and demineralized water to the petrochemical and chemical plants in the area. With the reorganization of electricity supply and the decision to import gas from Indonesia the combined heat and power scheme was seen as a logical extension of their system. In the deregulated Singapore market, power generators cannot engage in other utility services. Therefore SUT Sakra created SembCorp Cogeneration as a separate company to own and operate the power plant. The shareholders are SembCorp Utilities with 60%, Tractebel with 30% and Economic Development Board Investments with 10%. All the electricity produced must be sold into the Singapore power pool so that it is dispatched on merit order of its electricity offer price and availability. Therefore the combined cycle has been designed for high flexibilty in operation so
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that its availability as an electricity generator is not compromised by the demands of process steam supply. SUT Sakra’s boiler plant remains on standby to cover maintenance of the gas turbines and steam turbine. With supplementary firing to 780 °C, nearly 200 °C above the natural exhaust temperature of the gas turbine, process steam demand can be followed independently of electricity demand. SembCorp Cogeneration was the last project to be engineered by Alstom before their break with GE and the takeover of the ABB Power Engineering business. GE Power Systems supplied the two Type 9FA gas turbines for this scheme and, under a long-term agreement, are providing all the parts, inspection and repair services for the three turbine generators, and the major maintenance services on the balance of plant. The heat recovery boilers are a vertical assisted-circulation design with two pressures and reheat. This is best suited to the large process steam loads and also gives a boiler of lower thermal inertia which will be faster than a three-pressure system to start up in electricity-only mode of operation.These boilers have a smaller footprint, which is important for a congested site such as on Jurong Island. Each boiler has its own deaerator and feedwater tank mounted on the side of the frame. In pure electricity mode, the plant has one of the highest pressures so far achieved in a drum type boiler at 145 bar and 550 °C. Reheater outlet is at 41 bar and 518 °C. With maximum process steam delivery, the high-pressure output reduces to 104 bar and 566 °C and the reheater to 24.6 bar and 566 °C. Under this condition, supplementary firing is at its maximum of 780 °C. Steam outputs are carried on a pipe bridge which links with the SUT network at the plant boundary. There is a continuous supply of demineralised water coming back from SUT to top up the condensate return to the steam cycle. Some industrial power plants are set up to burn waste gases from the process. Quite often these gases are used for supplementary firing while the gas turbines themselves burn natural gas. Industries with by-product gas available are oil refineries and large chemical plants. However, in parts of Australia, coal mines are an unusual source of gas turbine fuel. About 20 years ago, ABB supplied a 15 MW gas turbine to a coal mine in New South Wales. Methane extracted from the workings was compressed and supplied to the gas turbine which had a heat recovery boiler to provide hot water for pithead baths. Some similar schemes were installed in other countries where there are working coal mines with high methane content. Queensland has extensive coal deposits, some of which are very deep and uneconomic to mine conventionally but which contain large quantities of methane. By recovering this gas and putting it into the natural gas pipeline system, gas turbine power plants and industrial schemes can burn this coal seam gas. Bulmer Island combined heat and power scheme at the BP refinery near Brisbane (Fig. 8.6) was the first plant to take fuel from this new coal-seam methane source. It entered commercial operation in November 2004.
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8.6 Brisbane, Australia: the BP Bulmer Island refinery which received the first two examples of the SGT-400 for a combined heat and power scheme burning coal-seam methane.
In fact, Australia is the only country in which the exploitation of coal-seam methane is a firm issue of energy policy.
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9 Gas turbines and coal
The first gas turbines were developed in the UK and Germany in the years leading up to the Second World War: two countries which depended on coal for much of their energy supply. After the war the British technology was made available to other countries and, as development got under way again, inevitably the question arose as to whether a gas turbine could be produced that would burn coal. Wind and water apart, coal is the oldest energy source known to man. It was the fuel which launched the Industrial Revolution and the products resulting from its gasification are the bedrock of organic chemistry. It powered the first railways and was the fuel for the first thermal power stations, but for much of its history in power generation it has been burned extremely inefficiently. It was not until the mid1950s that efficiency in power generation reached over 30%, and even today the limit of efficiency for a modern 700 MW coal-fired steam power plant working on a supercritcal steam cycle is about 43%. Various applications of gas turbines to transport were studied, and the most successful has been in shipping. Gas-turbine-powered warships serve with many of the world’s navies and in the high-speed catamarans used on longer ferry routes, but these are all oil fired. In the USA, a serious attempt was made to develop a gas-turbine-powered locomotive based on a coal-fired gas turbine. The power unit was the Rolls-Royce Dart, a turboprop engine used in the Vickers Viscount airliner, many examples of which were then in service with North American domestic airlines. The gas turbine was directly fired and enough was known about the effect of particulates on gas turbine components but, although a prototype locomotive was built and tested by Union Pacific Railroad, it was in fact overtaken by events. As steam was replaced by diesel–electric traction on the railroads, so the line-side coaling facilities were removed. In any event a diesel–electric locomotive could run from New York to Los Angeles and back without the need for en-route engine changes to service a gas turbine. In the 20 years after 1973, a serious effort was made to develop gas turbine applications with coal. What resulted were practical solutions which have occupied niche markets and which have been overtaken by the decline of the European 166 WPNL2204
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9.1 Coolwater, near Barstow, California, USA: the first IGCC plant to be built. Completed in 1984, it had a Texaco gasifier and a 110 MW combined cycle with a single GE Frame 7EA gas turbine.
coal industries and the growth of natural gas in the energy markets around the world. Most of these projects have been technology demonstrations funded by national governments and the European Union and proof of technology has been more important than absolute performance. With concerns over global warming and the abundance of coal in many parts of the world, these gas turbine applications are being looked at again, and in particular the IGCC which was pioneered in Germany in the early 1970s. The first complete IGCC demonstration plant in the USA was Coolwater built in the early 1980s (Fig. 9.1). There are many who see this as the direction for the country to go. Domestic sources of natural gas and imports from Canada have declined and are being augmented by increasing volumes of LNG from Trinidad, Nigeria and the Far East. An energy system based on American technology and an abundant American fuel resource makes eminent good sense in the first decades of the twenty-first century. There are three concepts of coal-fired gas turbines. The oldest of these is the closed-cycle gas turbine of which several were built in Germany in coal-fired district heating schemes. In the closed-cycle gas turbine there is an external combustor to heat air circulating in a closed loop. Energy would be added in the combustor and removed as mechanical energy on the shaft and as thermal energy in the compressor intercooler. The closed-cycle gas turbine was really developed for a nuclear power application. In 1977, a 15 MW prototype of a high-temperature gas-cooled reactor was installed at the Nuclear Research Centre in Jülich a few kilometres north of Aachen. The concept of the reactor was similar to a fluidised bed with the core
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consisting of thousands of graphite balls, each about the size of a tennis ball and impregnated with uranium carbide. For this reason it was popularly known as the pebble-bed reactor. The balls are kept in motion by blowing helium through the bed and the energy would be removed in a closed-cycle gas turbine integrated with the reactor. The reactor temperature was 950 °C which was compatible with turbine inlet temperatures of the gas turbines available at that time. Development went as far as building a closed-cycle gas turbine with helium as the working fluid, but with a coal-fired combustor and installing it in the district heating plant in Oberhausen in 1975. Further development of the reactor came into conflict with the violent antinuclear protest in Germany, and development of the closed-cycle gas turbine was therefore stopped. Now, 30 years later, the pebble-bed reactor is under development in South Africa and China, with a closed-cycle gas turbine under development in Japan by Mitsubishi, as the output device. The use of coal as a fuel for a modified gas turbine with a pressurised fluidised bed in place of its normal can–annular combustor system was pioneered in Europe. The pressurised fluidised-bed combustion (PFBC) gas turbine was developed over a 20 year period with funding from the International Energy Agency (IEA) and the UK, German and US Governments. Development started in the UK and moved to Sweden in 1980. The plants have all been built as combined-cycles and the steam cycle is shared between the fluidised bed and the gas turbine heat recovery boiler (Table 9.1). The first commercial application of a PFBC coal-fired gas turbine was to the Vartan district heating plant in Stockholm, and among the five other units that have been built are included a new district heating station at Cottbus, Germany, burning locally mined lignite, and a 390 MW combined-cycle station on the Japanese island of Kyushu burning Australian bituminous coal. The IGCC links a coal gasification process which fuels a combined cycle and this in turn receives steam from the process. A few examples have been built in the USA and Europe, but as development projects with government funding from Department of Energy in the USA, and from the European Union for the few projects that have been built there. Given the environmental issues which have gripped the world with global warming now at the fore, any new coal-fired power system must be more efficient and have significantly lower emissions than the systems that we have today, so that means a target efficiency of at least 45% and removal of all entrained chemicals such as sulphur and mercury in the combustion process. Development of a new coal-based energy system is still in its early stages. To be attractive to the power generators it must be cheaper than the existing generating systems in terms both of capital cost and of operating cost, which means having a system which is as reliable and easy to maintain, in both the combined-cycle and the gasifier systems. It is unlikely that the present state of technology will provide any significant
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Table 9.1 Gas turbine PFBC schemes Owner
Site
Country
Gas turbines
Application
Stockholms Energi
Vartan
Sweden
2 × GT35P
District heating
Endesa
Escatron
Spain
1 × GT35P
Power generation
American Electric Power Tidd
USA
1 × GT35P
Stadtwerk Cottbus
Cottbus
Germany 1 × GT35P
EPDC
Wakamatsu Japan
1 × GT35P
Kyushu Electric
Karita
1 × GT140P Power generation
Japan
Power generation District heating Power generation
advantage over a conventional coal-fired plant with a supercritical steam pressure. However, the syngas is predominantly a mixture of hydrogen and carbon monoxide, and its attraction is that, by passing the syngas at a high pressure through a shift reaction with steam, the carbon monoxide is converted to hydrogen and carbon dioxide which can be separated. The gas turbine is effectively fuelled with hydrogen and the carbon dioxide is collected to be piped to an oil field for enhanced oil recovery, instead of going up the stack. However, like flue gas desulphurization before it, carbon dioxide sequestration adds to the cost of the plant without improving the performance. Coal has fallen out of favour in Europe for a variety of reasons. The high cost of production and geological difficulties have closed mines, and elaborate pollution controls to ensure clean burning have increased the generating cost and reduced the efficiency. There were about 850 mines in the UK at nationalisation in 1947 and, 60 years later, fewer than ten are still working. Only in Germany where there are massive lignite deposits close to the surface over much of the country has there been any significant construction of coal-fired steam plant in recent years, and that mainly to rebuild the former East German power system, and to preserve employment in the opencast mines there after reunification. The large coal markets today are in China, India and the USA. Of these the USA has a large inventory of old coal-fired power plant and it is only there that significant effort is being made to develop clean coal technology for the future, with the IGCC as the preferred choice. The challenge is to engineer an IGCC power plant with an output of, say, 800–900 MW that will be efficient and competitive against gas-fired power based on imported LNG. Of the coal applications the PFBC coal-fired gas turbine has for some years had commercial installations operating in two district heating plants in Europe and in a 390 MW combined cycle in southern Japan. The remaining projects have been technology demonstrators in association with the development of filter systems for the hot gas returning to the power turbine. In 1968, the British Coal Utilisation Research Association at Leatherhead, about
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60 km southwest of London, was investigating fluidised-bed combustion and set up the first pressurised fluidised-bed experiments. This programme included a study of the effects of the flue gases on gas turbine components. In 1974, the then Manager of ASEA Stal’s London operations, Henrik Harboe, published a paper entitled ‘The importance of coal’ in which he proposed the use of a pressurised fluidised bed as the combustor for a modified version of one of his company’s gas turbines. Cyclones would capture and recycle unburned coal dust carried off in the flue gas so that clean gas returned to the gas turbine. In a fluidised bed, inert material such as sand is kept in circulation by a current of air rising through it. As coal is injected into the bed, it circulates with the sand as it burns and, by lacing the bed with limestone, any sulphur in the coal reacts with it to form a solid calcium sulphate which is removed in the ash. The combustion temperature is less than 850 °C which is below that at which atmospheric nitrogen starts to oxidise. The hot air rising off the bed contains dust which is collected in cyclones and returned to the bottom of the bed. It is a clean coal combustion system that produces an inert ash which can be used as an aggregate by the construction industry. Also the coal, although it has to be ground down to be injected into the bed, is not the fine powder produced by the pulverising mills of a conventional fired boiler. In the 1970s, concern about acid rain due to the sulphur oxides released in the flue gases of power station boilers led to the development of FGD systems which were installed between the boiler and the stack and were being introduced first on new power stations in the USA and Germany. The problem with these systems was that, by creating a back pressure on the boiler, they reduce the output and efficiency of the plant and created, as a reaction product, calcium sulphate (gypsum), which has to be disposed of. German plants found a ready market for it with builders in eastern Europe to make plaster boards for ceilings and partition walls, and other operators have found similar markets elsewhere. American Electric Power, a large coal-fired utility in the eastern USA, became interested in PFBC because it offered a way of burning cleanly some difficult eastern coals with high sulphur and ash contents. The utility joined the project in 1990 and hosted one of the first three projects of the coal-fired gas turbine at their Tidd power station on the Ohio River west of Cincinnati. The basis of the coal-fired gas turbine was the GT35 gas turbine which had started life in the 1950s as a development programme for an aero engine for the Swedish Air Force. The project was cancelled when the Swedish Air Force opted for the Rolls-Royce Avon, but the developers, Stal Laval Turbin AB (now incorporated in Siemens Industrial Power Division), decided to adapt the engine for industrial application. The GT35 is still in production as the Siemens SGT-500 and many units have been sold around the world for power plants,
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offshore platforms, district heating and industrial combined heat and power schemes. Only a few PFBC gas turbine plants have been built, and not all as a new concept of coal power but rather to gain experience with a coal-fired gas turbine by repowering an old steam turbine. The original GT35P was developed in Sweden by ABB who created a company, ABB Carbon, to market it. With their takeover of the ABB power engineering business in 2000, Alstom acquired the intellectual property rights for the PFBC with the Industrial Gas Turbine Division in Finspong remaining responsible for the gas turbines. Following the sale of the Finspong and Lincoln industrial gas turbine businesses to Siemens at the end of 2003 the situation is that PFBC technology rests with Alstom, but Siemens will supply gas turbines for future projects and continue to support maintenance of the gas turbines at the existing power plants. All the PFBC plants have been designed as combined cycles, mostly by repowering old steam turbines. Of the three new plants, two supply district heating in Stockholm and Cottbus, Germany, and Karita is a 390 MW combined-cycle generating plant owned and operated by Kyushu Electric in southern Japan. The unit for American Electric Power was a research tool backed by US Department of energy funding of US$67 million, to study the clean combustion of various American bituminous coals with high sulphur and ash contents. The power station was 42 years old when the PFBC unit was commissioned, and over the next 4 years the properties of the system were thoroughly investigated and various filter systems were tested. It was closed in 1995. Since then, American Electric Power has emerged as one of the first companies planning to install an IGCC system. The first PFBC gas turbines in service were at an extension of the Vartan district heating station in Stockholm. It was built as a combined cycle with two gas turbines and a back-pressure turbine supplying district heating condensers. When Stockholms Energi ordered the plant in the spring of 1987 it was at the culmination of testing for 4000 h the process test facility in Malmö, a heavily instrumented pressurised fluidised bed which was installed to determine the operating characteristics and to perform combustion tests on a number of coals, but mostly with Polish coals alone, and mixed with biomass fuels such as wood chips and palm nut shells. The fuel at Vartan is Polish coal. The third of the initial PFBC plants was at Escatron, Spain, owned by the utility ENDESA; the plant came into operation in 1991 and is a combined cycle of 63 MW, of which the gas turbine contributes 17 MW; the plant burns locally mined coal with 5% sulphur and 27% ash. The GT35P has little in common with the standard gas turbine. In place of the combustion chamber there is a fast-acting shut-off valve mounted on top of the gas turbine casing and leading into a coaxial pressure duct connecting to the fluidisedbed combustor. The gas turbine compressor is divided into high- and low-pressure sections
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which are separated and mounted at opposite ends of the machine. The highpressure shaft is connected to the generator and drives it through a gearbox at 1500 rev/min. The low-pressure section is a free turbine stage on a separate shaft driving the low-pressure compressor. There is an intercooler between the compressor sections which is included to ensure that the temperature entering the PFBC is no higher than 300 °C. The PFBC is a large cylindrical pressure vessel which is held at 12.3 bar together with the two cyclones which recycle dust coming off the top of the bed to the bottom. The type of coal being burned defines the need for limestone sorbent for sulphur entrapment. Depending on the type of coal and its sulphur content the sorbent can be fed in dry or as a paste. At the bottom of the pressure vessel is a lock hopper which allows ash to be removed to hold the top of the bed at a constant level. All the PFBC plants have been supplied as combined cycles, but only three as completely new power plants. Of these, Kyushu Electric’s Karita power plant on the Japanese island of Kyushu is the largest and is interesting for the fact that a detailed economic evaluation at the time showed that the PFBC plant would have lower operating costs burning Australian coal than an equivalent sized combined cycle burning gasified LNG also imported from Australia. Karita is the only example of the larger GT140P gas turbine, which is rated at 75 MW and integrated with the steam cycle of a 290 MW supercritical turbogenerator, for a total plant capacity of 360 MW. GT140P was derived from the GT200, a large aero-derivative engine jointly developed in the 1970s by Pratt & Whitney and by ASEA Stal. Only one was ever built and was installed as a simple-cycle peaking unit at Linköping for Statens Vattenfall. The pressurised fluidised bed which here is held at 16 bar is the only heat source and is not only the combustor for the gas turbine but also contains a once-through heat exchanger which is the evaporator and superheater of the 241 bar steam supply to the main turbine. The plant went into commercial operation in 1999. The GT140P followed the same general layout as the smaller GT35P. The eightstage low-pressure and 12-stage high-pressure compressor sections were derived from the GT200 compressor, but the power turbine stages were scaled up from the GT35. The operating temperatures are the same for both engines. The intercooler and the gas turbine heat recovery boiler are the feedwater heater and economiser for the main steam cycle which has the evaporator and superheater in the fluidised bed. Of the bituminous coals burned at Karita, the average heating value is 26 MJ/ kg with less than 1% sulphur, up to 29% ash and a maximum 7% of water. The efficiency at Karita is 44%, which is about the same as the best currently obtainable with a conventional coal-fired steam plant on the same supercritical steam cycle, but of twice the size, complete with NOx catalyst, FGD system and electrostatic precipitators. In effect, this could be considered the definitive steam power plant for the 60 Hz networks. The last PFBC station to be built was the new district heating plant for
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Stadtwerke Cottbus in eastern Germany. This has a single GT35P burning locally mined lignite. This brown coal has a heating value of 19 MJ/kg and contains less than 0.8% sulphur but 5.5% ash and 18% water. The situation at the end of 2007 was that the PFBC technology is looking for a market, at a time when interest in Europe and much of the rest of the world is still focused on gas-fired combined cycles. PFBC is a proven clean coal technology which can handle a large range of coals from high-grade bituminous to lignite with high ash and moisture content. However, all the plants except Karita, Japan, have been subsidised by governments; most of these were built as demonstration units and were much smaller. Karita is interesting because it is the only one of the plants which is of a comparable size with the alternative pulverised coal-fired plants in the market place. Alone of the six, the efficiency is higher than that of the equivalent pulverised coal plant and at US$1500/kW the cost is at the bottom end of the range currently predicted for pulverised coal-fired and IGCC plants. It is a low-temperature system and so does not require a NOx catalyst, and the sorbent system replaces the FGD system which in a conventional coal-fired steam plant lowers the efficiency by putting a back pressure on the boiler exhaust. One other fluidised-bed idea can be described as a modern version of the fully fired combined cycles built in the 1970s. This is in Thailand 150 km south of Bangkok at Mab Ta Phut where it is one of three plants operated by Glow Energy Ltd, the Thai operation of Suez Tractabel, which supply power and process steam to industrial estates in the area, from three combined heat and power plants and send part of their electrical output on long-term contracts to EGAT under the Small Power Producers Act (Fig. 9.2 and Fig. 9.3). The power plant consists of two blocks which are termed hybrid plants each consisting of an atmospheric fluidised bed and two GE Frame 6B gas turbines with heat recovery boilers integrated into the steam cycle of a 170 MW steam turbine. It went into commercial operation in March 2000. The hybrid plant is a way of providing greater flexibility between electricity and process steam output. All process steam is generated in the fluidised bed and outputs to the two steam mains at 19 and 52 bar serving the Mab Ta Phut estates. Glow Energy has two contracts with EGAT to supply 150 MW from each of the hybrid units: 30 MW from each gas turbine and 90 MW from the steam turbine. There is also a gas-fired combined cycle on the site which provides back-up power and steam to safeguard the EGAT contracts during maintenance of the hybrid units. Why was a hybrid coal- and gas-fired plant used instead of another and larger gas-fired combined cycle? A combined cycle with heavy supplementary firing could probably have performed this duty but, under the small-power producer rules, EGAT could only take up to 90 MW from each section of the plant and the remaining electricity demand has to be matched to the demand for process steam. Compared with a conventional coal-fired plant the hybrid unit is inherently
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9.2 Mab Ta Phut, Thailand: the schematic diagram of the hybrid cogeneration plant of Glow Energy Ltd, which is a highly flexible system with a power supply largely independent of steam demand.
9.3 Mab Ta Phut, Thailand: the third power plant of Glow Energy Ltd, which consists of two fluidised-bed boilers, each with two GE Frame 6 gas turbines integrated into the feedwater heating system.
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simpler. Without the gas turbines, the same capacity would be obtained with a 210 MW steam turbine with a reheater and various extractions to process, and with an array of maybe two low-pressure feed heaters and two high-pressure feed heaters and a deaerator, all supplied from the energy of the coal. However, there would not be the flexibility in balancing steam and power loads. The hybrid system removes the reheater function from the fluidised-bed boiler and puts it in the hottest region of the gas turbine heat recovery unit. All the energy of the coal is available to generate more steam, which is reheated by the gas turbine exhaust energy. Thus the hybrid system is inherently flexible in that it can control the rate of combustion of coal to meet process steam demand while at the same time maintaining electricity supply to EGAT and the other customers. In fact, the steam turbine set is rated 170 MW, which is enough to meet the EGAT load of 150 MW with both gas turbines down for maintenance. The inert material of the fluidised bed is sand laced with finely ground limestone to absorb the sulphur in the coal. The combustion temperature is 800 °C. The gas turbines, however, have steam injection for NOx control. A cyclone system gathers dust and unburned carbon particles carried off in the flue gas stream and returns them to the bottom of the bed. Any dust which is not returned through the cyclones is picked up in a chain of bag filters, from which it is collected, together with bottom ash from the bed, and taken to a storage site where it is sold as a construction aggregate. The fluidised bed consists of once-through evaporator and superheater sections of the steam cycle which are at a much higher pressure than has so far been obtained in the largest combined cycles to date. Live steam output is 120.6 kg/s at 180 bar and 568 °C with reheat at 530 °C as determined by the exhaust conditions of the gas turbines. As a combined cycle with no process steam load the output is 230 MW at an efficiency of 43%. With the full steam load of 100 t/h to process the electrical output is 209 MW and the net cogeneration efficiency is 53%. Of the total energy output, 55% can be attributed to coal and 45% to gas. The hybrid power plant is unique. It has been in operation since 2000 and has met and exceeded all performance guarantees. With the particular arrangements for power sales from independent cogeneration operators in Thailand it is particularly valuable in being able to meet steam demand without compromising its sales contracts to EGAT. The coal-fired gas turbine with the PFBC is a proven concept in commercial operation. The hybrid steam plant with gas turbines is a viable system for cogeneration, offering flexibility in balancing steam demand with fixed power loads in a way that a steam turbine alone cannot. A cogeneration unit with gas turbine alone, or in a combined-cycle format, would only be able to run heavy supplementary firing to achieve similar flexibility of heat output. The other gas turbine link to coal is not direct but with a coal-derived fuel. IGCC is not just a power plant, but a cluster of chemical processes with a combined cycle in the middle. The basic elements are an air separation plant which produces
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oxygen for the gasifier, the pressurised reactor vessel of the gasifier, and syngas clean-up, including sulphur and mercury recovery systems. The challenge is to develop a power plant which both is more efficient and in time can be linked with a carbon sequestration process that will recover carbon dioxide. IGCC potentially has the largest auxiliary load of any of the other generating systems, and maximising recovery of heat from the process is the route to higher efficiency. The air separation unit is independently supplied with air, although future gas turbines may be designed to supply this air, about 15% of the mass flow, from its compressor and the air separation plant sends the separated nitrogen back to the gas turbine combustor for flame dilution to suppress emissions. The steam turbine is larger than for a normal combined cycle because there is the cooling system of the gasifier itself as well as the syngas cooler placed between the gasifier output and the syngas cleaning system which removes sulphur and mercury. The gas is a mixture of carbon monoxide and hydrogen. Coal gasification is a long-established process in the coal-producing countries of Europe and North America. Coal gas dates from the nineteenth century as a public energy supply in the major cities, initially for street lighting and later extended to cooking and space heating. The processes that created it are the building blocks of the chemical industry and of the coal gasifiers that have emerged 100 years later. IGCC as commonly understood refers to coal and some of the earliest examples were built in Europe and the USA. These were essentially prototype systems to test the technology and used relatively small gas turbines, although one of the latest, at Puertollano, Spain, has an F-class gas turbine, the V94.3, rated at 245 MW, with 45% efficiency under ISO conditions. All the IGCC schemes are of a commercial size, but coal-based schemes are fewer and in the USA were built as technology demonstrators. In Europe, the coal schemes are full-size power plants: SUV Vresova, Czech Republic, with the GE frame 9E in a 2+2+1 arrangement; Buggenum, The Netherlands, with the Shell gasifier and one Siemens V94.2 in a single-shaft arrangement; Puertollano, Spain, with a 1+1 multishaft block of a Siemens V94.3. This last project has been using a mixed feedstock of locally mined coal and petroleum coke and claims, at 45%, the highest efficiency of the currently operating units. In the USA, IGCC has been studied since the time of the first major oil crisis in 1973. Thus, 34 years later, several projects have been built to demonstrate the technology, but the main factor is cost. IGCC is not specifically a coal gasifier; in fact, the majority of schemes have been built at oil refineries gasifying the heavy, almost solid residues of the refining processes. The other facet of IGCC is that it is potentially more than just a producer of electricity and process steam. With the many high-sulphur coals which have been extensively tested in the existing plants, an essential part of the gas clean-up process is the production of elemental sulphur, which has a high commercial value and can be sold to the chemical industry.
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Then there is the fuel flexibility of the gasifier which can be designed for firing coal, but also residual oil, biomass, pelleted refuse or combinations of those fuels. With the growing emphasis on recycling, the amount of domestic refuse is significantly reduced once the glass, metals, plastics, clean paper and board have been taken out for recycling. What is left is more organic in nature and can be formed into pellets that can be blended with coal and burned or gasified, thereby saving on transport to landfill. Table 9.2 shows the IGCC plants that have been built, of which a number, particularly in Europe, are at oil refineries. The market for oil changes over time and processes must change to respond to need. One of the largest process changes in the last 20 years has been the switch to production of high-performance unleaded gasoline, and particularly in Europe the production of increasing volumes of clean diesel fuel for pasenger cars. These processes result in different end products: the near-solid residual oils, asphalt and petroleum coke which are the feedstock for the industry’s gasifiers. An IGCC scheme at an oil refinery gasifies these process residues as fuel for a combined heat and power scheme which will supply power and process steam to the refinery. The majority of oil gasifiers are in Europe and are commercially operated by the refineries. They are among the largest units so far with two units of 500 MW in Italy and one of 400 MW in Japan. In all there are currently more than 25 gas turbines in operation in IGCC schemes around the world with 1.5 million h of combined operation between them. In the USA, the emphasis has been much more on coal gasification to produce fuel for a combined-cycle power plant. Although there have been coal gasifiers in the chemical industry for many years, none of these has been integrated with combined cycles. The American IGCC schemes based on coal have been built as demonstrators to learn about the operation of the gasifier in the integrated system and the performance of the combined cycle with the gasifier product gases. The properties of IGCC are first that the synthetic fuel gas produces less carbon dioxide than even a natural-gas-fired combined cycle if carbon capture is considered. The performance of the pilot plants has suggested that the efficiency of the power plant without carbon capture will be between 40% and 45% (lower heating value) depending on the extent to which the syngas coolers are linked to the highpressure feedwater path of the heat recovery boiler. In the 13 years following the completion of the IGCC scheme at Buggenum, The Netherlands, in July 1994, 12 others were built, of which five were in the USA, four in Italy, all at oil refineries, and one each in The Netherlands, Spain, Germany and Singapore. The Spanish scheme is at Puertollano some 220 km south of Madrid. Completed in March 1998, it has since been gasifying a mixture of locally mined coal and petroleum coke. Of the five American schemes, Wabash River (Fig. 9.4) and Polk County use coal feedstock. The Dow Louisiana Gasification Technology Inc. (LGTI) Project with a Dow (ConocoPhillips) E-gas gasifier and Siemens W501D5 gas turbines
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Table 9.2 IGCC schemes at end of 2006 Site
Owner
Country
Gasifier
Feedstock
Kellerman Lünen Coolwater Buggenum Wabash River El Dorado Polk County Puertollano Pinon Pine Shell Pernis Falconara Priolo Sarlux Schwarze Pumpe Delaware City Jurong Negishi SUV Sulcis Sanazzaro Plaquemine Sanghi Clark County Iwaki
STEAG S Cal Edison Nuon Power PSI Energy Frontier Refining Tampa Electric ELCOGAS Sierra Pacific Shell API Energy ISAB Energy Saras SpA SVZ Sustec Motiva Enterprises Exxon Chemicals Nippon Oil Vresova AT Sulcis AGIP Petroli Dow Chemicals IBIL Energy Global Energy Clean Coal Power
Germany USA The Netherlands USA USA USA Spain USA The Netherlands Italy Italy Italy Germany USA Singapore Japan Czech Republic Italy Italy USA India USA Japan
Lurgi Texaco Shell Destec Texaco AFB Prenflo AFB Shell Texaco Texaco Texaco Lurgi–GSP Texaco Texaco Texaco HTW Shell Texaco Destec GTI UGas BG Lurgi Mitsubishi
Coal Coal Coal–biomass Coal1 Petroleum coke Coal Coal1 Coal Residual oil Residual oil Asphalt Residual oil Lignite2 Petroleum coke Cracked tar Asphalt Coal Petroleum coke Residual oil Coal Coal Coal3 Coal4
1
Mixture of coal and petroleum coke. Two gasifiers for the process plant incorporating a combined cycle. 3 Coal and pelletised refuse. 4 Air-blown gasifier. 2
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9.4 Wabash River, Indiana, USA: the 250 MW IGCC demonstrator that went into operation in 1997 and in separate campaigns has used various high-sulphur coals and petroleum coke feedstocks.
used subbituminous coal over its 8 year operating period; Wabash River with a Destec (ConocoPhillips) E-gas gasifier uses the high-sulphur Illinois 6 and petroleum coke; Polk County, with a Texaco gasifier uses a mixture of Kentucky 11 and Pittsburg 8 bituminous coals and petroleum coke. The other schemes, El Dorado and Delaware, use petroleum coke and waste oils, being associated with oil refineries. Around the world the coal-based IGCC schemes have converted different American and foreign coals with various concentrations of sulphur, ash and moisture. The coal is converted by oxidation at a high temperature and high pressure which produces a gas which is a mixture of carbon monoxide and hydrogen, together with hydrogen sulphide and carbon dioxide. The molten slag can be cooled and sold as an inert construction aggregate. The gas-cleaning process yields elemental sulphur which can be sold to the chemical industry. The gas turbine burns a low-Btu gas with the flame dilution performed by nitrogen and steam. The nitrogen, in the case of an oxygen-blown gasifier, is returned from the air separation unit. Gas turbines used in the American schemes have so far been the GE Frame 7FA at Wabash River and Polk County, and the Frame 6B at El Dorado and Delaware City; Dow’s LGTI IGCC scheme at Plaquemine, Louisiana, used the Siemens W501D5.
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When the first GE gasifier was installed at Coolwater, 150 km northeast of Los Angeles, in 1984 the cost was put at US$2500/kW installed, but this was a prototype plant with the gas turbine of the day. It was the first example of the Texaco oxygen-blown gasifier and supplied a combined cycle consisting of a GE Frame 7EA with a 40 MW steam turbine on a separate shaft. The five American plants range from US$1672/kW to over US$2000/kWh but, in the 10 years since these plants were installed, costs have risen for both IGCC and conventional coal-fired steam plant, and the Green dimension of clean coal has come to dominate. Today IGCC projects under investigation for start-up in about 2012 are of the order of 600–800 MW. The combined-cycle format would be a 2+2+1 arrangement of initially F-class gas turbines, with one gasifier train associated with each gas turbine. The reason that IGCC has not progressed more rapidly is that there has been a considerable lack of enthusiasm until now among the coal-burning power utilities. It is a power plant with a chemical process tied on to it. There are several gasifier designs each with different operating characteristics and maintenance requirements. What are the running costs of the gasifier and what is its availability compared with that of a typical combined cycle? The other issue is the environmental pressures against coal in much of the developed world. Nearly half of the total installed coal-fired capacity is between 30 and 40 years old and much of it runs on subcritical steam cycles at efficiencies of around 30%. However, it is natural-gas-fired combined cycle that will initially replace much of this old coal-fired capacity. There is still much development needed before the first commercial IGCC plant will come into operation. Meanwhile, what has changed is that the gasifier technology is being acquired by the power engineering companies. The aim is that the commercial IGCC power plant comes from one supplier with a specific gasifier as an add-on system optimised to a combined cycle. In 2004, GE acquired the Texaco gasification technology from Chevron Texaco and entered an agreement with Bechtel with the aim of producing a standard integrated system linked to a combined cycle based on their Frame 7FB gas turbine. It was the same gasifier type as had been used in the first IGCC scheme at Coolwater, California, 20 years earlier and is the most widely used gasifier system in the few schemes that have been built with six units, all at oil refineries. Four are in Italy and one, the largest, is in Japan which is linked to a 400 MW single-shaft combined-cycle block based on the Mitsubushi M701F. In 2005, a deal was struck between GE, Bechtel and American Electric Power to perform front-end engineering design for a planned 630 MW IGCC plant on a site in Meigs County, Ohio. Since then, American Electric Power have placed a second contract for a similar plant to be installed in West Virginia. Later Duke Energy has also placed a front-end design contract for a 600 MW plant to be installed at Evansport, Indiana. These initial design contracts were completed at the end of
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2006 and first contracts could be awarded in 2007–2008 for initial operation some time after 2010. Also at the end of 2005, GE announced a licensing deal with the China Petrochemical International Company SINOPEC to apply a gasifer to a chemical plant in Shandong Province. This was not an IGCC scheme but simply a gasifier for process application. Development of clean coal technology has received funding from the US government as announced in the 2006 State of the Union message. The aim is to assist the development of the technology and in particular of carbon dioxide sequestration. IGCC produces a gas of which the principal components are hydrogen and carbon monoxide. For this reason the system must be dual fuel with either oil or natural gas for starting. Ultimately with carbon dioxide sequestration technology in place, the syngas will be almost all hydrogen. The commercial plant must therefore be designed to operate on syngas or hydrogen or natural gas. The steam turbine would be larger than normal for a natural-gas-fired plant because of the large high-pressure steam input available from the syngas coolers. It might only be a two-pressure boiler since on natural-gas firing it would run at part load to achieve the same steam conditions on the gas turbine exhaust energy. The gasifier link to the combined cycle is to the high-pressure steam path, and there are various ways in which it can be done. The most basic system is through the quench system of a slurry-fed gasifier which cools the ash leaving the vessel. Some gasifiers, notably GE Texaco, have a water-cooled reaction vessel which can be cooled by high-pressure feedwater. Another heat source is the free-standing convective syngas cooler which has to reduce the temperature from about 750 °C leaving the gasifier to about 50 °C going into the acid gas removal systems. Gas cleaning removes acid gases (sulphur oxides) in a process that reduces them to elemental sulphur which can be sold to the chemical industry. Mercury can be removed by passing the gas over an activated carbon bed which can remove over 90% of any mercury present. Mercury removal is a statutory requirement of any IGCC plant installed in the USA. The cold clean syngas can then be preheated on its way to the gas turbine using the same arrangement as with a natural-gas-fired combined cycle to raise its temperature to about 160 °C. Removal of carbon dioxide from the syngas is possible and comparable applications in the chemical industries are running. An engineered system installed in a commercial power plant is not yet available. The basis of it is a catalytic shift reaction with water which converts carbon monoxide to carbon dioxide and hydrogen. So the syngas of the future will be largely hydrogen, the combustion product of which is water. GE and Bechtel are designing what in effect will be a standard design for an IGCC plant based on two oxygen-blown gasifiers supplying fuel to a combined cycle with two Frame 7FB gas turbines and a steam turbine. The normal S207FB
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combined-cycle design has an output of 562.5 MW and an efficiency of 57.6%. As an IGCC system, because the synthetic fuel is a low-energy gas, with nitrogen for flame dilution, the mass flow is much higher so that each gas turbine produces about 40 MW more to achieve an output of 630 MW but at an efficiency of 39%. The GE design is limited to bituminous coal applications only. Siemens is also developing a 600 MWe class IGCC plant based on its SGT65000F gas turbines for the North American market application for lower-rank coals and lignite. Mitsubishi is developing a 450 MWe IGCC plant using its M501G gas turbine and an air-blown gasifier. The low efficiency is calculated on the same basis as the net efficiency of any combined cycle: from fuel to saleable electricity. The heavy auxiliary loads of the gasifier and the gas-cleaning system are responsible for the large auxiliary load which gives the low net efficiency, but it would seem to be clear from this that the initial design uses the quench mode of the gasifier with no cooling steam going to the combined cycle and only perhaps preheating of the fuel gas. Despite the low efficiency there are advantages, nonetheless. It is a clean fuel which enters the gas turbine with no sulphur and no mercury. GE quote emissions of 39% less NOx, 75% less sulphur oxides and 45% less particulates compared with the steam plant with its low-NOx burners, and FGD and electrostatic precipitators. For the USA, at least, IGCC represents the use of an indigenous fuel in a more environmentally friendly manner and guarantees continued employment in the mining industry. In fact, the first commercial plants will be built in the traditional northern mining states. At the end of 2006, IGCC was still uncompetitive against the alternative of supercritical pulverised coal when carbon dioxide capture is not considered. The net efficiency is marginally lower, but there are many variables still to be evaluated before a standard repeatable format can be established. The oxygen-blown entrained flow gasifier is a high-temperature process which receives the coal in the form of a slurry or dry feed. The GE gasifier is a single-stage slurry gasifier with a water-walled vessel and is a radiant cooler that can be linked back to the steam cycle of the power plant. The Shell, Prenflo and Mitsubishi air-blown gasifiers are dry-feed systems. The E-gas gasifier is a two-stage slurry gasifier. The raw syngas leaves the gasifier at about 730 °C and has to be cooled to about 40 °C for the acid gas removal process which cleans the gas of sulphur. One way is to use a convective cooler which also removes heat to the steam cycle, but systems used for some of the demonstration plants have had corrosion problems because they lie upstream of the acid gas removal unit and can also be contaminated with particulate matter which can lead to blockage of the cooling paths. Of course, the more heat that can be removed to the steam cycle, the higher will be the net efficiency of generation. On the other hand, so too will be the capital cost per kilowatt. In the USA, which is likely to be the largest market in the foreseeable future, the most probable gas turbines to be used in the initial projects are the F-class machines
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9.5 Schematic diagram of a possible IGCC scheme with an optimised link from the gasifier cooling system to the steam side of the combined cycle. It is an F-class gas turbine with a two-pressure steam cycle.
which in their ISO power ratings on syngas are 232 MW for both the GE Frame 7FB and the Siemens SGT6-5000F and would probably be used in a three-shaft combined-cycle arrangement with one gasifier train serving each gas turbine. However, GE have already carried out preliminary studies for their Frame 9H gas turbine which show that it could be possible to achieve 50% efficiency on a coal scheme. Certainly a more efficient combined cycle would contribute to this as also would a larger steam turbine linked into the syngas coolers, but there is much development ahead, not least in the gas clean-up system, before this can be realised. Also in a fully optimised system the use of a steam-cooled gas turbine adds further questions to the linkage of the steam cycle to the syngas cooler (Fig. 9.5). A possible way to do this would be if the syngas coolers were two-stage heat exchangers, which would keep the water cycle intact and separate from the actual syngas stream. Then there would be no problem of leakage between the syngas cooler and the steam cycle with its cooling streams going to the gas turbine. Siemens also has significant experience of IGCC operation with coal, and with a number of different oxygen-blown gasifiers. The company’s first IGCC project was Kellerman Lünen, a 183 MW power plant for the German generator STEAG, which was completed in 1972. This was based on a 74 MW gas turbine fired with syngas produced by a Lurgi gasifier with a heating value of 123 Btu/ft³, and a composition of 12% hydrogen, 22% carbon monoxide with 55.6% nitrogen; the plant efficiency was 35.1%, about the same as the best of the conventional pulverised-coal plants at that time with a subcritical reheat steam cycle. Then, 20 years later, Siemens also provided two W501D5 gas turbines for the Dow LGTI
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9.6 Puertollano, Spain: a Prenflow gasifier and combined cycle with an SGT5-4000F gas turbine which has operated since 1998, gasifying a 50– 50 mixture of coal and petroleum coke.
IGCC Project in Plaquemine, Louisiana, that operated as an IGCC plant between 1987 and 1995. Other European projects include the only two coal-fuelled IGCC plants in Europe. The first of these was at Buggenum, The Netherlands, using the Shell gasifier, which went into operation in 1994. Based on the 150 MW Model V94.2 gas turbine, it had a net efficiency of 43.1% and the gas had a heating value of 113 Btu/s ft³. The second, completed in 1997 at Puertollano, Spain, used the Krupp Thyssen Prenflow gasifier to power a 360 MW combined cycle with a V94.3 gas turbine (Fig. 9.6). There was also an oil refinery scheme similar to Buggenum at Palermo, Italy, but using a Texaco gasifier. The 1997 takeover of the Westinghouse non-nuclear power engineering business brought them into contact with the American IGCC schemes. The company has worked with Fluor and ConocoPhillips to supply two IGCC plants of 600 MW nominal output to sites in Illinois and Minnesota. The Minnesota project, Mesaba, is at Iron Range and received consent from the State Government in 2003. The steel industry in the region has declined with low world prices and more than 10 000 jobs have been lost in the last decade. The project owner and developer is Excelsior Energy, and Siemens in partnership with Fluor and ConocoPhillips are the technology providers. Two E-gas gasifiers are planned, each linked to an SGT6-5000F gas turbine in a 603 MW combined cycle in a 2+2+1 arrangement, but protests are mounting over the cost of the project and the cost of electricity that will result even without the addition of carbon sequestration, despite US$36 ×106 having been offered in a US Department of Energy grant. In May 2006, Siemens Power Generation bought the Sustec GSP gasification
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process, renamed the Siemens SFG gasifier, from the Swiss Sustec Group. It is an oxygen-blown gasifier which, for converting coal, is lined with water-walled cooling screens but has no refractory linings. The gasifier lining has lasted over 10 years in a unit at the SVZ Schwarze Pumpe plant. Siemens are aiming for gasifier availability over 90%. The company claims that the cooling-screen design gives operational flexibility with quick start-up and shutdown and that it can gasify coals with high ash-melting temperatures without affecting availability. The Siemens SFG gasifier is one of several which were installed at Schwarze Pumpe, Germany, to gasify lignite and industrial wastes for the production of town gas in Cottbus and the surrounding area. Today, about 25% of the feedstock used at the facility is lignite and the rest is various industrial and domestic wastes. After reunification, natural gas was brought in to replace town gas and, in 1994, a 70 MW combined cycle with a Frame 6B gas turbine and a 26 MW condensing extraction steam turbine supplied by Hitachi was coupled to the gasifiers. Then, in 1999, a British Gas Lurgi gasifier was installed to replace the old units. Having acquired the GSP technology, Siemens announced that they would build a prototype at Spreetal, Germany. However, the focus will not be on IGCC but on downstream syngas conversion to produce clean sulphur-free automotive fuels. Siemens has also taken an order from a Chinese customer to provide multiple gasifiers for a coal-to-chemicals project in China with start-up expected in 2009. The other country which is making a concerted effort to develop the IGCC concept is Japan. As a net importer of coal, an IGCC is important as a higherefficiency power generation system compared with a conventional steam plant which has a supercritical steam cycle and is fitted with FGD and all the other environmental measures. The one operating IGCC plant in Japan is at the Yokohama oil refinery; this uses asphalt as the feedstock for a Texaco gasifier which is integrated with a combined heat and power system supplying electricity to the Tokyo Electric Power Company and process steam to the refinery. The gas turbine is the 280 MW Mitsubishi M701F. The national development programme is focused on the air-blown gasifier which is being developed specifically for power generation. It does not require an air separation plant and therefore has a lower auxiliary load and consequently a higher net efficiency from coal to electricity. The air-blown gasifier is a two-stage pressurised entrained-flow design with a dry-coal feed system. Since it is supplied with pulverised coal there is a low moisture latent heat loss compared with wetcoal feeders based on coal slurry; by using the same water-cooling wall structure in the gasifier as the boiler, it is possible to realise a highly reliable gasifier. Mitsubishi has built a 250 MW IGCC demonstration plant at Iwaki, about 160 km north of Tokyo. The plant owners are Clean Coal Power Ltd, who are a consortium of nine Japanese utilities which are supplying 70% of the funding with the Ministry of Economy, Trade and Industry supplying the other 30%. This plant consists of a 1700 t/day gasifier with the smaller M701DA gas turbine and was scheduled to start operational testing for 3 years in early 2007.
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Mitsubishi has sold several examples of the 701DA to the Asian steel industry where they are burning blast furnace gas. The air-blown gasifier also produces a low-energy gas with an average calorific value of 1157 kcal/m³. In fact, there is little modification of the gas turbine required, apart from the need for the compressor casing to be able to send about 17% of the air supply to the gasifier and the fitting of the low-energy gas burners. The gasifier is a two-stage system consisting of a combustor and a reducing stage mounted above it. The combustor burns part of the coal to produce char and gases which carry it up to the reduction stage where more coal is added in a reducing atmosphere to produce syngas and more char; this is collected in cyclones and recycled through the bed. The reaction is endothermic which reduces the final gas temperature. With a smaller auxiliary load the air-blown gasifier should be more efficient in the larger commercial version based on the M701F gas turbine in a three-shaft combined-cycle arrangement at an efficiency of 45%, and 48% with the steamcooled M501G. However, the aim is to develop the gas turbine to tbe able to send 100% of the air required to the gasifier and to receive back 100% of the available inert gases for flame dilution. The initial IGCC plants in commercial operation will have oxygen-blown gasifiers, probably with an independent air separation unit sending nitrogen back for flame dilution. One of the leading power plant design programmes suggests that there are significant variations in output and efficiency depending on the cooling arrangements of the gasifier, the heat content of the fuel and its composition, and the amount of air sent to or nitrogen received from the air separation unit. The two gasifiers being studied for the American market are the GE Texaco and the ConocoPhillips E-gas. Both are two-stage gasifiers which are fed with a pulverised coal–water slurry. In the first stage, coal slurry is fed to the lower section with oxygen to maintain a temperature above the ash fusion point; this converts the coal to syngas which enters the second upper stage, where more slurry is added. Char carried off with the syngas is trapped in a cyclone and recirculated to the bottom of the vessel. The GE gasifier has a water-walled vessel which can be cooled by the highpressure feedwater from the combined cycle. The syngas leaves at about 730 °C and is further cooled to about 100 °C for the gas-cleaning systems. The E-gas gasifier has quench cooling and the gas leaves at about 1000 °C. The gas enters a large fire-tube-type heat exchanger which is linked into the high-pressure boiler, and where the temperature is reduced to about 370 °C. From both gasifiers the ash is a fine granular substance which can be used as a building aggregate. The expectation is that these early IGCC plants will have an efficiency marginally higher than that of a conventional pulverised-coal supercritical steam plant, but it really depends on how much heat is recovered from the syngas coolers into the high-pressure section of the steam cycle. The Texaco gasifier, for instance, can
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be supplied with just quench cooling and some fuel gas preheating, which will give the lowest efficiency. Alternatively the radiant cooler of the gasifier vessel jacket can be added to raise the efficiency further, and finally a convective cooler can also be added. All the cooling options could increase the net efficiency to around 45% from coal to electricity sent out. If it means building a more complex system to achieve a higher efficiency, will the additional capital cost give a sufficient rate of return given the price of electricity that results, and can the reliability be sufficient that it does not compromise availability of the power plant? With the current F-class air-cooled gas turbines, independent air separation units, a high-pressure steam cycle and a high-quality bituminous coal, the efficiency could be between 46% and 53% gross on the generator terminals and between 40% and 45% net depending on the extent of heat recovery from the gasifier vessel and the syngas coolers and the amount of nitrogen returned from the air separation unit. Gas turbines supplying air to the separation unit are being considered and are a future development, but it would create a family of gas turbines designed specifically for IGCC applications and burning low-energy gases. It does not in itself significantly raise the efficiency of the system and a far better way would be to apply higher-powered gas turbines to lower costs. The large cooling load represented by the gasifier and the coolers which drop the gas temperature by about 700 °C between the gasifier exit and the acid gas removal unit is a valuable source of energy which should not be wasted. The large volume of high-pressure water required for cooling duty suggests that a vertical twopressure heat recovery boiler with a large high-pressure flow and with assisted circulation would not only avoid too large a volume of water but also reduce the cost of the boiler. It may be more than 15 years since the first IGCC plants were installed, but the development of the system has not been fast. Nevertheless some of the current plants offer only 39% higher heating value efficiency because they are not using cooling systems on the gas treatment side. If these are included, while they may increase the auxiliary load, they will add to the high-pressure steam and therefore the steam turbine output. In Europe, the natural-gas-fired combined cycle with a single-shaft block of an F-class gas turbine would have a gas turbine of about 280 MW and a steam turbine of about 130 MW, which would have a net output of about 395 MW at 58% lower heating value efficiency. The same combined cycle in an IGCC scheme would have a higher gas turbine output because of the additional mass flow of the syngas and the flame-diluting nitrogen returned with it, and a larger steam turbine because of the additional cooling load of the syngas in the clean-up process. The total output would be 500 MW with 320 MW from the gas turbine and 180 MW from the steam turbine, with about 60 MW of the total output accounting for the large auxiliary load. However, the net efficiency could be up to 46% which, given that the fuel is coal, is a small gain in efficiency from fuel to electricity.
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There is no standard gasifier although the gas turbine companies have adopted specific designs for particular markets. There are six types that have been used in the current IGCC projects and two more under development. The GE Texaco and ConocoPhillips (Destec) are slurry fed whereas the Shell, British Gas Lurgi, Siemens SPG, Mitsubishi and Prenflo are dry-fed with water used only to cool the slag in the bottom of the reactor. The AFB gasifier uses the principle of the fluidised-bed boiler at a high temperature and is a dry system with cyclones recirculating particulate matter entrained in the syngas. The Siemens SFG gasifier is also a dry-fed system with a water-wall screen in the reactor vessel. All the above are oxygen blown except the Mitsubishi and AFB designs. Dry coal feed is simpler, with less auxiliary load and so results in a higher efficiency. The Prenflo gasifier at Puertollano, Spain, has run for 7 years with a net efficiency from coal to electricity of 45%. Given that the whole purpose of the combined cycle is to generate electricity at a higher efficiency, to switch to a coal-based scheme and not to produce a worthwhile gain in efficiency is a pointless exercise. Who would order an IGCC with a net efficiency of 45% when they can obtain the same from the proven technology of pulverised coal with a supercritical steam cycle? There are still many issues to be resolved before it can be said that there is a competitive IGCC plant in a standard configuration with a significant cost advantage over the traditional coal-fired plants. Not least is the reliability of the heat exchangers which have unclean gas passing through them and are prone to corrosion and blockage. The challenge then is to achieve reliability of the total gasifier system up to the same level as the combined cycle. If the major overhaul of a large F-class gas turbine takes place every 4 years, the gasifier and its auxiliaries must be able to run the same length of time between major overhauls. The first American design utility projects are intended for installation in the northeastern states: Ohio, Indiana, Pennsylvania and West Virginia. These are the traditional mining areas with high-quality bituminous coals of heating values between 22 000 and 35 000 kJ/kg. The sulphur content is in the main less than 1%, but the notorious Illinois 6 has more than 4%. There are also several projects planned for the western states that will use lowerrank coals and lignite. A plant in Texas would use a locally mined lignite with heating values of 8000–15 000 kJ/kg but low sulphur, high ash and high moisture contents. Studies show that a lignite-fuelled IGCC plant would have a higher output but a lower efficiency, all other factors being equal. An export market for IGCC will take account of the coal sources available to the customer and the plant will be designed accordingly. The improvement in the efficiency and reliability of the system will drive development forwards. One of the important issues is the reliability of heat transfer. There are water-wall linings for some gasifier types, but the syngas coolers have a very clean fluid on one side with the high-pressure feedwater, and a very dirty gas on the other side. It requires stainless steel tubing to protect against corrosion, but any solids in the gas may
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accumulate and block tubes or otherwise reduce cooling efficiency. The other issue being considered by the gas turbine manufacturers is that of taking an air supply to the air separation unit from the gas turbine compressor. Already this is being considered for the air-blown gasifiers. About 15% of the total mass flow is taken from the compressor delivery and must be further compressed to reach the operating pressure of the gasifier. As with the oxygen-blown gasifier the nitrogen is returned but as a component of the syngas. The mass flow entering the power turbine is about the same as that leaving the compressor and therefore the whole nitrogen volume can be used for flame dilution to reduce emissions. Taking air from the gas turbine compressor is a challenge because of the compressor surge margins that must be controlled. The argument for it is that there is a much smaller auxiliary load than is the case with an independent air separation unit and, as the gasifier reactions are exothermic, a dry coal feed can be used; there is a large potential for heat recovery to the steam cycle with a water-walled reactor vessel. Mitsubishi who are developing the air-blown gasifier expect that a full-size unit with a combined cycle based on their M501F gas turbine would have an efficiency of 45%. The more powerful H-class gas turbines which are just coming into production could result in a significant gain in efficiency that would strengthen the IGCC advantage, but absolute performance is not as urgent as absolute reliability and low emissions in a standard product. At present, the technology rests with the large and small F-class gas turbines which have demonstrated lower emissions at comparable efficiencies to supercritical pulverised-coal plants. However, most of the operating coal-fired plants in the world do not have supercritical steam conditions and are generating at below 35% efficiency. So even the most basic IGCC concept would seem to have an advantage, with significantly lower emissions. Probably there will be no significant improvement in efficiency until larger, more powerful air-cooled gas turbines that could support higherpressure steam turbines are developed. It may be that 50% net coal to electricity may then be possible. However, what will the cost be? Meanwhile, if the protests by power regulators in Minnesota are typical of what we can expect elsewhere, IGCC may be doomed as nuclear power was 20 years ago. Many nuclear projects were cancelled because regulators saw Green protests inflating costs by challenging the effectiveness of technical fixes that they had insisted be applied. Is carbon sequestration another Green-inspired technical fix which will be the end of clean coal with inflated legal costs before serious commercial application has even started?
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10 What does the future hold?
The combined cycle in the first decade of the twenty-first century has reached a plateau in its development from which further progress may be assessed in terms of what it is going to cost to obtain a worthwhile gain in output, and with minimal effect on the environment. It is a complex environment in which we all live, and the underlying issue is that society cannot function without electricity. The question is: how can it be generated and how can the environment be protected? The energy system that supplies us today is the result of political decisions taken more than 30 years ago and which are still with us. The reaction to the 1973 oil crisis was for many countries to take oil out of power generation and also created an environmental awareness which has been in the background of combined-cycle development. Looking back at the development of the gas turbine, we see that it took 25 years from the production of the first mechanical drive gas turbines at the end of the 1940s to the arrival of the first 100 MW gas turbines designed to run at the common synchronous speeds. It was another 15 years before the first F-class gas turbines appeared and a further 13 years before the first H-class went into service in south Wales. The intervening years were marked by the progressive upgrading of the existing models and the development of low-emissions combustion systems across the industry. The classifications relate to temperature since this is one of the two properties which determine the performance of the gas turbine and thus of the combined cycle. Turbine inlet temperatures were 1000 °C by 1990 and are now almost at 1400 °C with the current H-class units. Gas turbine efficiency has increased to almost 40% and exhaust temperatures have reached 640 °C with some of the largest units. It is these developments that have resulted in the higher steam conditions which in over 40 years have raised the efficiency of power generation from little more than 35% in the 1960s to almost 60% at the end of 2007. In particular, since 1990, the combined cycle has become the system of choice for new generating capacity around the world. Yet it is more the result of the low cost, low environmental 190 WPNL2204
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impact and rapid construction than of absolute efficiency. Furthermore, it is still the case that most of the available coal-fired capacity in the world consists of generating sets installed between 30 and 40 years ago and still operating with subcritical steam cycles at efficiencies of less than 35%. The benefits of improved efficiency from combined-cycle generation are more visible in small countries with large programmes, such as Belgium and the Irish Republic, with individual utilities with units at the top of their merit order. All the applications of combined cycles, whether by repowering, combined heat and power or IGCC, result in higher efficiency although not necessarily higher than that of the best combined cycles. Nevertheless, as repowering has shown, higher efficiency with the lower emissions of gas firing has restored many of these old plants to base load. Although the efficiency of all the F-class gas turbines is above 35%, in most markets there is no economic case for running them in simplecycle mode for peaking duty. IGCC potentially offers similar gains in efficiency over current coal-fired generating systems but is still in the early stages of development and commercial applications. Developers and potential customers still have reservations about IGCC and see it as a new technology that must be proven in stages. In fact, the basic coal gasification processes date back to the nineteenth century when they supplied coal gas for street lighting, space heating and cooking over much of the then developed world. Development of a commercial IGCC system is rather the optimisation of the combination of two proven technologies to achieve an economic, environmentally friendly and more efficient generating system with coal, that is capable of being built at a competitive cost compared with the alternative: a pulverised-coal-fired power station operating on a supercritical steam cycle. The efficiency target must be at least 45% lower heating value before it can begin to offer any improvement over the conventional steam plant, and the cost of construction around US$2000/kW installed. However, there are two fundamental questions that must guide future development of the combined cycle, since this will have a bearing on the future of IGCC. Firstly, what will be the generating plant mix in the future power system and what will be the role of the combined cycle within it? Secondly, what are the development priorities for the combined cycle: how important is 60% efficiency and can it be taken higher? To develop a more efficient combined cycle means having a more efficient gas turbine. That means new materials to support higher temperatures in larger frame sizes, and the cost of a significant advance beyond 60% combined-cycle efficiency may push it a long way into the future. However, since the combined cycle itself was developed to improve the efficiency of power generation, systems built around the combined cycle have also realised higher efficiency. Repowering, although a compromise of gas turbine and steam turbine performance, has achieved worthwhile gains in efficiency where it has been applied. At Bergen, New Jersey, for instance, repowering raised efficiency from 28% to 42%
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while at Peterhead, Scotland, in pure combined-cycle mode, it went from 40% to 57%. Much depends on the size and condition of the steam turbine and the extent to which it can be refurbished to improve its performance. Blade profiling on a computer is one of the technologies that have been widely applied to give performance improvements to both gas and steam turbines. Combined heat and power is inevitably more efficient but limited in its scope to specific industrial sites. District heating has social implications which would encourage the maintenance of existing schemes rather than any widespread development of new systems. The application of combined heat and power from a combined cycle can be anything from 70–85% depending on the amount of the heat load and the conditions under which it is supplied. Some plants in Finland and Sweden also supply surplus power and heat to the local district heating network. However, despite these advantages, the future plant mix will not change very much for several years, if only because of the time taken to license and build the alternative generating systems. More wind farms will be built and more combined cycles. IGCC is only in the initial stages of commercial development and exploitation in the USA, but we are unlikely to see any unit in operation until 2012, at the earliest, and then using the current F-class gas turbines. Perhaps that is being optimistic, because IGCC still holds too many unknowns which these early projects are aiming to clarify. What is the best gasifier to use, how reliable can it be, what will be the maintenance requirements of the gasifier and its auxiliaries and how will this fit in with the gas turbine maintenance cycle? The other question is the gain in efficiency that is available with the new technology. If the simplest concepts are applied to prove the technology with little gain in efficiency, what will be the effect on the market? An 800 MW supercritical coal-fired plant has an efficiency of about 43%. Who is going to be willing to risk the new technology of IGCC if it cannot improve on this? Much of the current development work by the major gas turbine companies is in the integration of specific gasifier types with their current combined-cycle concepts so that they can offer a completely integrated system as a turnkey contractor and subsequently be responsible for the operation and maintenance of the complete system. Is clean coal really the answer? At the present state of development it could be 10 years before any significant impact of the new technology can be felt. Plans have been filed, front-end designs have been performed, sites have been nominated and in some cases consents have been given. However, these are for the basic IGCC scheme and first indications are that they will not offer any gain in performance over conventional coal-fired plant which can be up to 5% higher in efficiency and therefore would have significantly lower emissions. The largest contribution to emissions reduction in energy would be to take coal out of mainstream power generation altogether, just as oil was in much of Europe 30 years ago. There would still be a market for coal as a chemical feedstock as undoubtedly it must become as oil supplies diminish. Carbon sequestration means engineering a process which will remove 90% of
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the carbon dioxide emission. Studies have shown that such a scheme at 2005 prices would add about US$60 /kW installed to the cost of a 600 MW IGCC power plant. Look back nearly 40 years to 1970, when in Texas new technology was applied to a 120 MW power station, near San Antonio. The new technology was a combined cycle which resulted in the most efficient power plant in the USA at the time. The contract was awarded on the basis of a US$3.60/kW lower price than the alternative of a conventional 120 MW coal-fired steam plant. The combined cycle was the then current American concept of a gas turbine and heat recovery boiler replacing the normal feedwater heaters of the steam plant. It burned less fuel and therefore had lower emissions for a higher output of electricity, but significantly it was cheaper to build and therefore would not add significantly to the price of electricity to the consumer. IGCC today is an entirely different issue. A recent UK study suggests that nuclear power based on the current advanced reactor designs would be £1200/kW, with the cheapest renewable option at £1070/kW for an onshore wind farm and £1375/kW for offshore wind. Other renewables are more than double the cost per kilowatt installed, and clean coal as IGCC without carbon sequestration is £1250/ kW installed. If carbon sequestration costs are added to IGCC, this would raise it to about £1280/kW. In 1970, a combined cycle was sold to an American utility on the strength of a US$3.60/kW reduction in costs which, for a 120 MW power plant, was a US$432 000 saving on capital costs. Now, 40 years later, IGCC is being offered with a US$60/kW increase for an engineered carbon sequestration system to reduce emissions by 90%. For 1200 MW of IGCC in two plants the added cost for carbon sequestration would be US$72 million, which would ultimately be passed on to the electricity consumer. Given that a 1200 MW nuclear power plant would have no emissions at all and generates more fuel as it operates we have to ask why there is this enthusiasm for so-called clean coal. Up to 1980, the purpose of building a power plant was to generate electricity. The plant was designed to do that efficiently and reliably at the lowest practical cost. The environmental consequences were of less concern, but this all changed with the experience of acid rain, which led to the introduction of FGD, which is now standard equipment on all new coal-fired power stations. The problem with FGD is that it adds to the cost but reduces the efficiency of the plant. Utilities have accepted this, but will they so readily accept carbon sequestration as an engineered addition for environmental aims which does not add to the output of the plant except to the auxiliary load which cannot be sold and will inflate the price of electricity to the consumer? We still face the political fear of nuclear energy which is entirely built around events in Japan more than 60 years ago. Yet despite this, and being in a seismically active region of the world, Japan has built up a large nuclear power park of its own.
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Not only that, but other countries in the region are also developing nuclear power, not least China and South Korea and keeping the industry active. The antinuclear posturing of the Green movement which almost brought nuclear construction to a halt in Europe and North America appealed to significant public opinion during the Cold War. Later, as Russia and eastern Europe opened up with the end of communist government, the concept of global warming was gathering momentum and culminated in the Kyoto conference of 1997. Global warming is now generally assumed to be evident, but whether because of human activity or natural activity is hard to tell. In Europe and the USA the particularly hot summer of 2006 invited comparisons with 1976 which saw similar weather conditions long before global warming became a public issue. A year later in the UK, successive torrential rainstorms during June and July have seen daytime temperatures below 20 °C for much of the period. There have been subtle changes in global climate throughout recorded history and this may be another at a time for the world when there is an articulate protest movement that can frighten people who do not understand the subject but, however climate change arises, it will change the pattern of demand for energy. Another major volcanic eruption to rival Tambora in 1815 or Krakatau in 1883 would produce a significant short-term climate change through the spread of fine ash through the upper atmosphere until it was washed out in rainfall. In fact, in Europe, 1816 was known as the year without a summer owing to reduced sunlight and a 3 °C drop in temperature following the Tambora eruption in Indonesia. The population of the world has trebled since the end of the Second World War. Two countries, China and India, account for a third of the global population and are developing rapidly with rising demand for energy, fresh water and raw materials. In the developed world of Europe, North America and Japan, future population trends are downwards. Birth rates are below the replacement level in some countries and give rise to economic questions about the size of the workforce that must support a retired population with greater spending power and longer life. The world population in the year 2000 was 6.1 billion and could reach 7.5 billion by 2020. In the same period the demand for electricity is expected to grow from 15 500 TW h to 27 000 TW h, but most of this is expected to occur in the newly developing industrial countries who are expected to account for 45% of demand in 2020 compared with 29% in 2000. However it is caused, global warming is not happening as fast as some would have us believe, but it has focused attention on other energy systems and the improvement in efficiency with lower emissions. The response of the power plant producers to the changing times is quite interesting. There are an increasing number of contracts being placed for the renovation and upgrading of existing steam turbines and hydro plants. Many of the steam turbines are with nuclear power plants, particularly in the USA. All this points to a need to keep these plants running and to increase their output because, alone of all the thermal power systems, nuclear plants emit no greenhouse gases.
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Similarly, the major gas turbine manufacturers have developed global service and maintenance operations in order to upgrade their older gas turbine models. Units designed 30 years ago were of a much simpler technology and operated at lower temperatures. Fitting computer profiled blading, together with dry lowemissions combustors where there was none before, and the replacement of analogue controls with digital systems, are all worthwhile modifications to make, at present fuel prices, for the performance gains that they bring to power plants. For the operator the crucial question is: what is the contribution of the fuel cost to the overall generating cost? If more electricity can be produced from the same quantity of fuel, how does the additional income stand against the additional capital and maintenance costs of a more complex power plant? This is what will decide how quickly new technology will be taken up by the market. The F-class gas turbines, despite initial technical problems, are now bedding down in service and achieving the same reliability and, significantly, despite their higher operating temperatures, similar levels of emissions as the previous generation of machines. The efficiency of typically 58% in the 50 Hz market is a significant improvement over what was possible even in 1990. The introduction of the single-shaft block with a standard power train has given benefits to customers, particularly the international divisions of deregulated European utilities who could have a number of identical blocks distributed between several sites in three or four different countries. A common spare parts inventory can be held and maintenance across the fleet is much simplified. It would therefore seem that the future development of the gas-fired combined cycle will be not so much towards absolute power as toward greater flexibility, and higher efficiency will be a bonus. The more urgent questions are: how and when should existing capacity that has been running for 40 years or more be replaced, and what will provide for system growth? There are now several factors at play in the market which will shape these decisions. The first must be the high prices of oil and gas which are unlikely to diminish significantly because of the high demand in certain developing markets, and the increasing development costs of more remote sources of these fuels. Expansion of the trade in LNG may see a marginal reduction in price through economies of scale in the production processes, but it will still be higher than in the recent past and susceptible to broader political and market forces. This may also encourage research into other energy systems than gas-fired combined cycle, particularly in those countries in the developed industrial world which will otherwise be more dependent on fuel imports than in the past. The price of fuel and its availability will have an important bearing on the deployment of these new systems and there are subtle changes beginning to appear in the understanding of what is needed to guarantee energy supply. No fuelimporting country wants to be solely dependent on a single fuel source, and yet the environmental politics of energy planning, which have closed off the nuclear and coal options in much of Europe, are leading to just that situation.
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There is a groundswell of opinion which is beginning to realise how much society depends on a reliable source of electricity, available whenever it is needed, and, if we do not at least replace the older nuclear stations, which are now approaching the end of their service life, with new ones, then greenhouse gas emissions are going to increase substantially and climate change may accelerate. In Canada, the province of Ontario published an electric power development plan in June 2006, the central plank of which is the addition of at least two new nuclear plants and the closure of all the coal-fired power stations in the province on grounds of emissions and public health. Two of originally six stations have been shut down and the redevelopment of one site in Toronto with a 500 MW combined cycle has already started. The Ontario Government has further stated that a gasfired combined cycle will only be used for mid-load duty and system back-up, e.g. for wind farms when the wind does not blow, and during maintenance and refuelling outages at the nuclear plants. The Canadian statement is the first to single out coal as an undesirable energy source on grounds both of pollution and deteriorating public health which stems from it. While other countries may achieve the same result with gas-fired combined cycle and nuclear plants they still will consider new environmentally friendly coal-fired capacity. The UK Government’s energy review in July 2006 has put emphasis on replacing existing nuclear power plants, the argument being that there would be significant power shortages if no new plants were constructed because all but one of the nuclear plants and also the large coal-fired plants built at around the same time should logically be replaced by 2020. The case for nuclear plants is that they are free of carbon emissions, with low fuel costs, and without them the country would quickly move from 80% self-sufficiency to 80% dependency on foreign energy supplies. Demolition of old stations will initially reduce the reserve plant margin and some combined cycles will be built to replace some of the lost capacity while new nuclear or coal-fired plants are built. So there is a future role for combined cycles but not as a base-load power plant alone. A future scenario might work as follows. Plans for new capacity lead to the ordering of a 1200 MW nuclear plant and a 400 MW combined-cycle block with a currently available F-class gas turbine. All consents have been obtained and the sites are ready. So, if construction starts at the same time, the combined cycle will be completed in 30 months and the nuclear plant in 60 months. The combined cycle will initially run base load until the nuclear plant is completed. It may have to carry spinning reserve under the terms of the grid connection, but it will run over 7000 h/year during this initial period. While the nuclear plant is being completed, a 30 MW wind farm and a second combined cycle of higher power and efficiency than the first and using an H-class gas turbine come into commercial operation. The wind farm will run intermittently, but the nuclear unit will be base loaded as also could be the new combined cycle.
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With the nuclear plant in service, the F-class combined cycle goes into a midload regime with perhaps daily start-and-stop operation and a 36 h shutdown at weekends. There could be times when it may run continuously for a few days, but a typical summary of operation could be about 4500 h/year with between 150 and 200 starts. The H-class combined cycle might be running base load during the winter months, and continuously but with weekend shutdowns for the rest of the year, say 6000 h and 40 starts/year. The growing component of renewables, mainly in wind farms consisting of a large number of small generators spread over a large area, will also create a role for the combined cycle as a back-up system. The largest individual units in service are about 3.0 MW and, although larger units are under development, public opinion may insist that they be installed offshore. Wind farms are intermittent with some of or all the units operating at any given time. In predominantly thermal networks with a large contribution of wind energy, the combined cycle will have a strategic role in stabilising the network in response to changes in the weather and in electricity demand. To design a combined cycle for rapid starting is the great challenge to the gas turbine industry. A 400 MW combined cycle may not start to operate to replace a 30 MW wind farm, which could be easily carried by spinning reserve on the operating plants but, if 1000 MW of wind capacity in 900 generators sited over a whole country were simultaneously idle on a hot summer day when the airconditioning load was at its peak, that would be equivalent to the failure of a large nuclear set, and that is when the combined cycles would make the most valuable contribution. The availability of renewable energy is variable and only one of the factors that can affect the amount of generation available to meet demand. Wind farm projects have also been heavily subsidised. A combined cycle is inherently a flexible system and, while it can reach full output more rapidly than any of the other thermal systems, it has an important role to play. It therefore must be designed for mid-load duty for much of its life with high start reliability and high availability. Because the combined cycle overturns the economics of power production with its low construction costs and high efficiency, people have tended to ignore this in recent years and built new plants optimised for base-load duty. The decisions were taken at a time when gas was relatively cheap, but that is not the situation today and, while other less flexible power systems are coming back into favour, the combined cycle has a place in the general scheme for which it must be designed. The industry is beginning to recognise this. The decision at the end of the 1990s to design a combined cycle for the USA as a merchant plant was recognition of the changing circumstances of the independent power market. A combined cycle with rapid-start capability combined with high availability can respond to changes in demand and maximise its earnings by being available to generate at peak times. The speed with which a combined cycle can reach full load depends on the heat recovery boiler. If the gas turbine has to wait at part load for the boiler to heat up,
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then that is an extended period of operation at low efficiency and higher emissions. If it takes 2 h to reach full load and then is only required to run for, say, 4 hours over the evening peak, this is not a very sensible arrangement. Yet, in this situation, how important is efficiency? If high power and efficiency are important for the IGCC combined-cycle running base load, should the same be said for the mid-loaded natural-gas-fired plant? The most efficient power plants have a high-pressure steam cycle powered by a gas turbine with a high exhaust mass flow at a temperature above 600 °C. There can be either a drum type or a once-through boiler, but the operating pressure has an important bearing on the rate at which it can heat up to generate the required steam conditions. As has already been shown, the vertical boiler acts more rapidly than the horizontal designs, and some plants in Mexico and Canada have been pointedly ordered with vertical boilers because of a requirement for load-following duty. The Benson heat recovery boiler, although configured as a horizontal design, achieves much the same effect by not having a high-pressure drum and has a lower water volume. The other advantage of the Benson boiler is that it can operate at higher pressure, but that depends on the exhaust energy of the gas turbine sent to it. The oncethrough design has advantages only at a high pressure and it is notable that, with one exception, all the operating plants at the end of 2006 had a two-pressure steam cycle: a Benson-type high-pressure section and a conventional drum-type lowpressure section. The speed with which a combined cycle can be loaded depends on the speed with which the steam turbine can be loaded, and the thermal inertia of the boiler. If in future more combined cycles are ordered specifically for mid-load duty, then we may see the return of the vertical drum-type boiler and more of the larger combined-cycle blocks with Benson boilers, and efficiency of 57–59%. So, what does this all mean for gas turbine development? Limitations on the gas turbine are metallurgical: how much higher than 1400 °C can the turbine inlet stages sustain effective cooling, or will frequent cycling lead to premature metal fatigue? The introduction of steam cooling in 1995 was an answer to the problem of attaining low emissions with higher firing temperatures in order to achieve higher power output. The first steam-cooled gas turbines were introduced in the USA and Japan in 1995 when gas prices were much lower than today. These were gas turbines with the can–annular combustor design in which steam cooling was applied to the transition pieces carrying the hot gas from the individual cans to the turbine inlet. This diverted cooling air to combustion to dilute the flame to reduce NOx emission. The next step was to apply steam cooling to rotating components. This was the first of the H-class of which there is only one unit in commercial operation and another four under construction. The gas turbine is the 330 MW GE Frame 9H which went into operation in 2003 as the unit of a 500 MW combined cycle at Baglan Bay in the UK. It is the only gas turbine to have incorporated steam cooling of rotating components.
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The only other H-class gas turbine under development is the 340 MW Siemens SGT5-8000H, which was announced in September 2005. The prototype started testing at a site in southern Germany in late 2007 and, like the American machine, it is designed specifically for combined-cycle application and will form the basis of a 520 MW single-shaft combined-cycle block with a target efficiency of more than 60%. There the similarity ends. The American machine is steam cooled, the Siemens gas turbine is air cooled and this, together with the use of a Benson boiler for the steam cycle, indicates that the primary design objective of the European gas turbine is flexibility in operation. The starting dates of development of the two machines are separated by 10 years, and much has happened since then. First economic recession slowed the Asian market in 1997 and, although it has since recovered, the rates of growth in electricity demand are now below 10% and not the previous heady rates above 15%. The European market dropped back in the wake of the Kyoto conference with only a few countries of southern Europe and Turkey remaining active. Expectations of boom years ahead in the USA at the turn of the century were abruptly abandoned with the Enron bankruptcy in 2002. As a result, the market for base-loaded combined cycles in the mid-1990s has given way to one requiring fewer plants, but with greater flexibility of operation and this leaves a question over steam cooling. For those gas turbines which have it, the steam cooling of stationary and in one case rotating components ties them firmly to the steam cycle. The cooling steam flow is linked to the intermediate-pressure–reheater sections of the steam cycle, and heat recovery from the fabric of the gas turbine complements that from the exhaust energy. However, since the gas turbine can only operate with a fully functional cooling system at the normal operating range of the combined cycle, any leakage from the gas turbine would cause the plant to shut down and might cause serious damage to the gas turbine as a result of overheating. With a naturally air-cooled gas turbine in a single-shaft block no auxiliary boiler is required because the faster start-up rate of the gas turbine ensures that there is enough high-quality steam to perform the initial gland sealing before the steam turbine starts to roll. In any case, while this is happening, the steam turbine would be isolated on its turning gear behind an open clutch and would not be generating power until it reached synchronous speed. It is worth noting that aero engines have always had to rely on air cooling, but then the air temperature at normal cruising altitudes is about –50 °C. Early turbojet engines such as the Rolls-Royce Avon had a can–annular combustor arrangement, but the large turbofan engines which succeeded them had a full annular combustor system, which is readily adaptable to dry low-emissions burners for industrial applications. The American heavy-frame industrial gas turbines used the similarly configured can–annular combustor arrangement. It is strange that they did not, even with the F-class machines, move to a full annular combustor. Certainly 60 Hz versions of
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the large European-designed F-class gas turbines have annular combustors with smaller versions of proven dry low-emissions burners and achieve the same low emissions. Time may show that steam cooling was an aberration resulting from aspects of design and materials available at the time of its introduction. With steam cooling limited in its application, could the elimination of the can–annular combustion system and its replacement with a full annular combustor be far behind? It would certainly reduce the maintenance burden since refurbishment of the transition pieces is an almost annual job with the American-designed gas turbines. The impact of the H-class gas turbines with at least 2% better combined-cycle efficiency and 20% higher output will not be felt for some years, until several have come into operation in a few countries, and certainly not before about 2015. So what is the importance of 60% efficiency? It is true that less fuel is used to produce the same output, but it will have been achieved by more powerful gas turbines operating at higher temperatures, and powering more efficient steam cycles at higher steam pressures and temperatures. However, in a flexible power plant operating in load-following duty, it is high availability and rapid-start capability that are more important, and high steam pressures work against this. The point is that, if the gas-fired combined cycle operated for only a few hours per day, the quick start-up and shutdown would in any case maximise the efficiency of the operation by reducing the fuel burn during start-up. The ultimate question for a merchant plant operator is how much he will earn for his power and at what time of day. If the 58% efficient combined cycle can earn more by running in two spells of 4 h/day and continue day after day in this manner, it must have a heat recovery boiler with a low thermal inertia which will enable it to heat up quickly with the build-up of gas turbine exhaust heat. The electricity supply system of the future will be significantly different. Governments see the need to reduce emissions, and power generation is a compact industry with a finite number of stations that are easy to regulate. However, governments must also create the regulatory environment which will enable plants to be sited and built to replace older and less efficient power plants quickly. Herein lies the problem. At the end of the day it is governments that decide when and where power plants will be built. If they have a large Green element supporting them, that will force energy policy in a direction which may be contrary to the national interest, as can be seen to have happened in Germany. This raises the question as to what will be the true price of electricity if the choice of generating plants is based on political prejudice supported by subsidy. Those who license the construction of power plants have it in their power to refuse on the grounds of cost of construction and production. However, even if they do not refuse, will their electorate be content to see subsidies paid to private developers for power generation and, even if they are, will they be content to pay significantly more for electricity? What is beginning to appear is a reappraisal of existing technologies whose costs
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are known and can offer significant performance gains. Combined heat and power will be an important contributor to energy efficiency and the reduction in energy costs for industry. The growing contribution of renewables is creating a requirement for fast-acting back-up capacity. The installation of more nuclear plants and coal-fired plants, with or without carbon sequestration, for base-load application will force the combined cycle back into the system support role of the early plants in Europe. The combined cycle of the future must be more powerful and more flexible in operation. It must be easier to control and not be designed primarily for base-load duty. The gas turbines must also be designed to work in this environment, with high power and low emissions, and must not compromise the working of the combined cycle. The combined cycle began as a means of improving the efficiency of power generation. This it has demonstrated, but now it faces a greater challenge, namely to be the reliable guarantor of security of supply in a larger and more diverse power system.
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Index
acid rain 22, 170 aero-engines 58, 60, 63 air condensers 54 Al Taweelah power station (Abu Dhabi) 160 AMATA EGCO power station (Thailand) 161–2 Angleur power station (Belgium) 18–19, 41–2 ASEA Brown Boveri (ABB) 68, 71 Ateliers de Construction Electrique de Charleroi (ACEC) 18 Baglan Bay power station (Swansea, UK) 35, 36, 81–2 Bang Pakong power station (Thailand) 48, 49 Benson boilers 101–2, 105–6, 108–12 biomass power generation 4 Blackstone power station (USA) 77 boilers see steam generators Brayton cycle 9 Brown Boveri 14, 41, 61 Brugg Hedersbrug power station (Belgium) 92 Bulmer Island power station (Brisbane, Australia) 164–5 Castejon power station (Spain) 127–8 Chernobyl accident 25 clean coal 4 coal gasification 4 coal-fired PFBC gas turbines 169–76 combined-cycle programmes 2, 7 Australia 129–30 Austria 14 Belgium 14–15, 18, 92, 95–6, 118–19 Canada 112–13 flexibility of 39
Germany 15–16, 132–3 India 25 Indonesia 28–9 Italy 25 Japan 24, 33–4 Mexico 18 Netherlands 14, 117–18 Philippines 27, 34–5, 123 Saudi Arabia 27–8 Spain 123–4, 127–8, 184 Switzerland 17 Taiwan 24 Thailand 24–5 Turkey 25 UK 9–11, 26–7, 30–1, 35, 36, 37, 38, 119, 120 USA 11–13, 106–7, 167 combined heat and power 1, 154–65 Abu Dhabi 160 Australia 164–5 New Zealand 158 Singapore 163 Thailand 161–2, 173–4 USA 156–7 Comanche Peak power station (Oklahoma, USA) 17–18 Connah’s Quay power station (Chester, UK) 37 Coolwater power station (California, USA) 167 Cottam power station (Trent Valley, England) 9–11, 31 deregulation of power generation 5–6, 33 development, history of 9–40 district heating 155–6 Drogenbos power station (Brussels, Belgium) 45–6, 63–4
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Index
early schemes 41–56 Austria 41, 43–5 Belgium 41–2, 45–6 Ireland 47 Thailand 48, 49 Turkey 49, 50 UK 51, 52–3 USA 47 East Palatka power station (Florida, USA) 47 Eemscentrale power station (Groningen, Netherlands) 117–18 ethylene glycol 54 European Union (EU) ban on natural gas power generation 30 flue-gas desulphurisation (FGD) 22 future propects 193 Fort Lauderdale power station (Florida, USA) 138–40 future perspectives 190–201 gas turbines 1, 166–89 Belgium 63–4, 72, 73 development 57–86 exhaust heat 9 New Zealand 58–9, 60 PFBC schemes 169 Portugal 72, 73, 119–20 USA 77, 82–3 gas, natural 4 GEC Alstom 68–9 General Electric (GE) 12–13, 18, 28, 32–3 Gent Ringvaart power station (Belgium) 118–19 global warming 3 Hamitabad power station (Turkey) 49, 50 Hays County power station (Texas, USA) 106–7 heat balance diagram 94 high-voltage direct current (HVDC) transmission 2 historical perspective 1–8 development 9–40 horizontal heat recovery boiler 95 hydrogen sulphide 70 IGCC schemes 167–89
future prospects 191–3 Ilijan power station (Philippines) 34–5 Irsching power station (Ingoldstadt, Germany) 132–3 King’s Lynn power station (East Anglia, UK) 37, 38, 119, 120 Korneuburg power station (Austria) 41, 43–5 Lake Nasworthy power station (Texas, USA) 12–13 Limay Bataan power station (Philippines) 27 liqufied natural gas (LNG) 4, 6, 23 Mab Ta Phut power station (Thailand) 173–4 Manchester Street power station (Rhode Island, USA) 142–3 Marina power station (Cork, Ireland) 47, 137–8 naphtha 69–70 natural gas 63 natural gas see gas, natural New Electricity Trading Arrangement (UK, 2001) 159 nitrogen oxides (NOx) emission 22–3, 30–1, 65–7 nuclear power 2 oil crisis of the 1970s 2–3, 17 price fluctuations 7 once-through boilers 87, 104–5 combined cycles 88 online washing 55 Organization of Petroleum Exporting Countries (OPEC) 17 Palos de la Frontera power station (Spain) 123–4 Peterborough power station (Cambridgeshire, UK) 52–3 Peterhead power station (Scotland, UK) 149–51 Pratt & Whitney 13 pressurised fluidised-bed combustion (PFBC) 168–9
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gas turbines 169 Public Utilities Regulatory Powers Act (PURPA) 21–2, 40, 156 Puertollano power station (Spain) 184 Rankine cycle 9 Richmond Cogeneration power station (Virginia, USA) 156–7 Rolls-Royce 13, 28–9 Roosecote power station (Barrow-inFurness, UK) 26, 51 Samarinda power station (Borneo, Indonesia) 28–9 San Lorenzo power station (Philippines) 123 SembCorp Cogeneration power station (Singapore) 163 Senoko power station (Singapore) 145–8 sequential combustion 71–2 Seraing power station (Belgium) 72, 73 Siemens 10, 18, 31, 36, 37 low-emission burner 65–6 rotor development 84 water brake 75–6 single-shaft blocks 117–34 sour gas 70 Southdown Cogeneration power station (Auckland, New Zealand) 158
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Spondon power station (Derby, UK) 138– 9 start-up performance 103–4 steam cooling 35, 81 steam cycle 107–8 steam generators 87–116 Mexico 90–1 steam plants, repowering 135–53 Ireland 137–8 Singapore 145–8 UK 138–9, 149–51 USA 138–40, 142–3 sulphur emissions 22 Swanbank power station (Australia) 129– 30 Tapada do Outeiro power station (Portugal) 72, 73, 119–20 UK privatisation of power generation 26, 30 vertical natural-circulation boilers 53, 99– 101 Vilvoorde power station (Belgium) 95–6 Whiranaki power station (New Zealand) 58–9 Whitby power station (Canada) 112–13
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