Combined-cycle gas turbines: The technology of choice for new power plants
Combined-cycle efficiencies of up to 60 percent are now possible when advanced gas turbine technology is utilized
Douglas J. Smith
Many of the world`s electric utilities and independent power producers are turning to gas turbine combined-cycle power technology for new capacity. The major reasons for the predominance of this technology are high efficiency, moderate capital cost, low environmental impact, favorable natural gas prices and short construction schedules. Recent advances in gas turbine technology allow for a combined-cycle efficiency of almost 60 percent.
Another benefit of combined-cycle technology is it can be constructed in phases. The first phase would be the installation of a gas turbine for simple-cycle operation. Then, as additional capacity is needed, a steam turbine with a heat recovery steam generator is added.
According to David Gray, Black & Veatch, Kansas City, Mo., USA, unlike steam turbines that are inclined to be custom engineered and manufactured for specific plant applications, gas turbines tend to be an assembly line product. Gas turbines are available in discrete sizes with fixed ratings being specified at standard conditions of 15 C, 1.013 bar and a relative humidity of 60 percent. Table 1 shows some of the manufacturers of gas turbines and different models produced while Table 2 shows the combined-cycle performance for some of the larger gas turbines.
Today, manufacturers offer aeroderivative and heavy duty gas turbines. In simple-cycle operation, aeroderivative machines are generally limited to 40 MW or less, while the heavy duty gas turbines can be supplied in sizes up to 240 MW, 50 Hz. However, advanced heavy duty gas turbines with high firing temperatures, 1,290 C to 2,350 C, when operated in a 50 Hz combined-cycle configuration can generate 360 MW at an efficiency of 58.5 percent.
EPRI`s advanced gas turbine program
The Electric Power Research Institute (EPRI), Palo Alto, Calif., USA, is collaborating with electric and gas utilities, the Gas Research Institute of Chicago, Ill., USA, and major aircraft engine manufacturers in an advanced gas turbine research and development program. Participating in the project are the following research teams:
– Rolls Royce Inc. and Bechtel,
– United Technologies` Turbo Power and Marine Division and Fluor Daniel,
– General Electric Power Generation and
– Stewart and Stevenson and Bechtel.
According to EPRI, the goal is to accelerate the commercial availability of high-efficient aeroderivative gas turbines for electric power generation applications by the turn of the century. For this reason, the new high thrust aircraft engines, which have been developed at a cost in excess of (US)$1 billion each, were selected. Not only do these engines incorporate advanced cooling technologies and materials, their larger size makes them more promising candidates for electric generation than previous aeroderivatives.
Although utilizing the advanced technologies of today`s high thrust aircraft engines could significantly improve gas turbines over the next 10 years, dry low NOx combustors present a challenge for aeroderivative engines. Dry low NOx combustors must be able to achieve emissions of NOx almost 90 percent less than current aircraft engines.
EPRI says high efficiency aeroderivative gas turbine cycles are obtained by:
– compressor intercooling,
– reheat gas turbine systems and
– high efficiency bottoming cycles.
Compressor intercooling improves gas turbine cycle performance by reducing the work of the compressor, increasing the mass flow and reducing the high pressure compressor exit temperature. As a consequence, the cooling air temperature for the high pressure turbine blades is correspondingly reduced.
Similarly, colder turbine blade and vane cooling air allows the gas turbine to reach higher firing temperatures without raising the temperature of the bulk metal. Colder combustor cooling air also allows the combustor to be cooled with less air, thus leaving more air for the combustion process.
Raising the high pressure turbine rotor inlet temperature is the most effective means of improving cycle efficiency. Adding intercooling to the current high thrust aircraft engines would raise the gas turbine rotor inlet temperatures by approximately 121 C to 149 C. According to EPRI, rotor inlet temperatures could be increased to around 1,426 C if the next generation of engine materials and cooling technology were to be incorporated into to the gas turbines (Figure 1).
Unfortunately, as gas turbine flame temperatures increase the production of NOx increases. Results from Phase I of the EPRI advanced gas turbine research program indicates that continuing gas turbine improvements could be limited because of the problem associated with increased NOx production at elevated temperatures.
Intercooled gas turbine cycles
Because intercooled cycles have lower development costs, and can achieve a significant increase in performance, EPRI`s manufacturer led research teams have selected intercooled cycles for more detailed study. After reviewing the different levels of technology proposed by the gas turbine manufacturers it was decided that the research would focus on utilizing technology currently used on advanced military gas turbines. Utilizing advanced military gas turbine technology would be less expensive than developing an intercooled aeroderivative engine.
In addition, using existing advanced technology would meet EPRI`s advanced gas turbine research program`s goal of accelerating aeroderivative technology development. The end result would be an increase in simple- and combined-cycle efficiencies of 1 percent to 2 percent. Intercooled aeroderivative and industrial gas turbine plant costs and performance at ISO conditions are shown in Tables 3 and 4.
Intercooled aeroderivative gas turbines are attractive for intermediate/peaking cycle applications because of their simple-cycle efficiency of approximately 45 percent to 46 percent. The cost of electricity from simple-cycle intercooled gas turbines closely follows that of an intercooled combined-cycle over the entire load range.
Electric utilities throughout the world face different criteria when choosing what type of gas turbine they should purchase. Before making any decisions, electric utilities must take into consideration their competitive and regulatory situation including the utility`s size and rate of growth, fuel prices and availability of parts and services. National Power Plc, one of Britain`s privatized electric utilities, is looking at intercooled aeroderivatives for future capacity additions.
In the opinion of National Power, the operating flexibility of simple-cycle aeroderivatives are ideally suited to the UK`s half hourly bidding scheme for capacity procurement. Across the English Channel, Electricite de France is looking at simple-cycle intercooled aeroderivatives for meeting its future peak and low intermediate load requirements.
Other gas turbine applications
Electric utilities are using gas turbines for many unique applications including steam turbine repowering, feedwater heating and hot windbox repowering. These applications were discussed in a paper by Ralph Hollenbacher of Energy Options and Dr. Arthur Cohn of EPRI at the POWER-GEN Americas conference held in Orlando, Fla., USA, in December 1994.
According to Hollenbacher and Cohn, TransAlta Utilities, a Canadian utility, is investigating steam turbine repowering applications. In this application, the boiler in an existing electric power plant is replaced by one or more gas turbines and heat recovery steam generators (HRSGs). The end result is increased power plant capacity and efficiency at a lower installed cost.
Hollenbacher and Cohn say that steam turbine repowering offers the highest potential efficiency of any power plant repowering application. For this reason, electric utilities with access to natural gas, that have a properly sized steam turbine in good condition, are good candidates for steam turbine repowering. However, to achieve maximum efficiency the throttle steam temperature must be maintained at the original design temperature. Likewise, the gas turbine`s exhaust temperature should be 24 C higher than the throttle steam temperature.
Elkraft Power Company Ltd., the Danish electric utility that supplies the eastern part of the country, has investigated the use of exhaust heat from intercooled aeroderivative gas turbines to heat boiler feedwater. This is being looked at as an innovative solution to a Danish government mandate that electric utilities reduce emissions of CO2 and SO2.
Because Denmark has no hydroelectric electric capacity, has limited potential for high-cost renewable energy plants, and utilizes coal for 90 percent of the country`s electric generation, burning natural gas must be part of the solution for reducing CO2 and SO2 emissions. However, since natural gas costs almost twice that of imported coal, Danish electric utilities must burn natural gas efficiently for them to remain competitive with neighboring Scandinavian electric utilities.
Elkraft, in order to achieve the mandated emission controls, studied several hybrid systems to determine the most flexible and cost effective power plant for burning natural gas. The study looked at combining gas turbines with a supercritical coal plant. Results of Elkraft`s design studies indicated that using gas turbines for feedwater heating met all of the economic and efficiency criteria. Not only was the feedwater heating design less expensive, it also had the flexibility to allow the gas turbine and the coal-fired plant to operate independently.
The Danish utility is looking at utilizing an intercooled aeroderivative gas turbine with a new 400-MW supercritical coal-fired power plant currently in the planning stage. Table 5 illustrates the efficiency improvements achievable by using a hybrid plant design together with an intercooled aeroderivative gas turbine. The higher natural gas conversion efficiency coupled with the higher power plant efficiency of the hybrid cycle provides the utility with the desired CO2 and SO2 emissions reductions.
A popular European option is hot windbox repowering where a gas turbine`s exhaust is used to preheat the boiler combustion air. With this option, the existing steam boiler is assumed to be in good condition. Utilizing this technology increases the overall cycle efficiency of the plant while allowing the boiler to burn low grade fuels. Another advantage, according to EPRI`s Cohn, is that the costs for repowering are very reasonable.
Britain`s National Power has carried out a preliminary investigation into hot windbox repowering. Initial findings of their investigation indicate that the lower exhaust temperatures of intercooled aeroderivative gas turbines are advantageous because less modifications are required to the existing boiler inlet air plenum. As a result, the capital cost of the retrofit is substantially reduced.
World`s largest combined-cycle power plant
What is reported to be the world`s largest combined-cycle gas turbine power plant, Teeside Power in the north of England, has been in commercial operation since the middle of 1993. Teeside Power plant is the direct result of the British government`s privatization program which started in 1989 with passage of the Electricity Act. Not only has the plant replaced an old coal-fired power plant, it has also helped the United Kingdom meet emission targets set by the European Union`s “Large Plant Directive of 1989.”
The plant is owned by Teeside Power Ltd. (TPL), a joint venture company. Enron Europe Ltd., a wholly owned subsidiary of Enron Corp. in the USA, holds 50 percent of the shares. The remaining shares are owned by Midlands Electricity, Northern Electric, Swalec (formerly South Wales Electricity) and South Western Electricity, all of the United Kingdom. ICI Chemicals & Polymers (ICI C&P) of Britain has a small equity interest.
The shareholders have 15 year power purchase agreements with TPL to purchase all of the plant`s 1,725 MW of capacity. Process steam from the plant is used by ICI C&P`s nearby Wilton plant. Enron is responsible for the operation of the plant and management of the joint venture company.
Feasibility studies began in 1989 when Enron and ICI C&P were looking at the possibilities of utilizing combined-heat and power plants for ICI sites in the United Kingdom. At the same time, discussions began with the regional electricity companies as potential power purchasers and with fuel suppliers.
By the middle 1990 a site had been chosen and arrangement had been made for the sale of steam and electricity to ICI, and in September 1990 natural gas fuel purchase agreements were signed. Power purchase agreements for the remainder of the plant`s capacity were also signed.
A turnkey (US)$341.6 million construction contract was awarded to Enron Power Construction Ltd. and construction started in November 1990. Agreements were also reached with the National Grid Co. for connection to the grid and with Enron Power Operations Ltd. to operate the plant and manage TPL. By the end of 1990 the majority of the permits and consents had also been obtained.
Once all of the contracts had been finalized, Teeside Power was able to go ahead with financing of the project. A total of (US)$493.7 million was raised in the first non-recourse project financing in the UK energy sector.
The Teeside power plant comprises eight 146.7 MW ISO rated MHI 701-DA gas turbine generators and heat recovery steam generators, and two 283-MW steam turbine generators. Westinghouse Electric Corp. and Mitsubishi Heavy Industries were jointly responsible for supplying the gas turbines and the HRSGs. However, the steam turbines and their hydrogen-cooled generators were purchased from Westinghouse. The gas turbine`s air-cooled generators were provided by Brush Electric Machines Ltd.
Teeside has a triple fuel system. Natural gas is the primary fuel while liquid naphtha is the main backup fuel. Gaseous propane is used for emergency startup and as a secondary backup fuel. Initially, the plant is being fired with natural gas supplied by British Gas. However, a new 250-mile gas pipeline from the Central Basin of the North Sea will bring gas to the Teeside plant. Eventually this gas pipeline will supply all of the plant`s natural gas needs.
When natural gas is unavailable the gas turbines will operate on naphtha. Should this be needed, the gas turbines will first be started, one or two at a time, on propane and at about 20 MW transferred to operation on naphtha. However, should the gas turbines be in operation when natural gas is curtailed, they would be automatically transferred to naphtha once the distributed control system (DCS) has confirmed that the pumps on the naphtha skid are operating. During the changeover the DCS would back off the load by about 10 MW.
Should the natural gas supply be restored while the gas turbines are operating on naphtha, the gas turbines, one or two at a time, would be returned to burning natural gas. The naphtha fuel is supplied at ambient temperature by ICI.
In addition to supplying process steam to ICI C&P, the HRSGs supply steam for the steam turbines and for gas turbine NOx control. The steam can also be used for increasing the output of the gas turbines. For NOx control the steam is injected through the fuel nozzles and into the combustor baskets.
Simple-cycle versus combined-cycle
John Joyce, deputy director of marketing, Power Generation Group (KWU), Siemens, Germany, says that gas turbines, when combined with steam turbines to form unfired, fully fired and parallel powered combined cycles, are more efficient than simple-cycle gas turbines or reheat steam boiler/turbine units. According to Joyce, over the past decade unfired combined cycles have proven to be by far the most economical means of generating electricity from fossil fuels.
Unfired combined-cycle power plants were the first thermal power plants to achieve net efficiencies in excess of 50 percent, Joyce said. The 1,350-MW Ambarli combined-cycle power plant near Istanbul, Turkey, is reported to have an efficiency of more than 52 percent. Ambarli has three 450-MW combined-cycle units. Each of the 450-MW blocks has two 150-MW Seimens V94 gas turbines and a 173-MW condensing steam turbine.
In fully fired combined-cycle power plants the exhaust from the gas turbines is used for combustion air in the conventional steam boilers. A big advantage of fully fired combined-cycle units is that in addition to firing natural gas they can also burn a variety of solid and gaseous/liquid fossil fuels. The solid fuels, generally coal or lignite, are fired in the boiler furnace while the gas or distillate fuels are used in the gas turbines.
Parallel powered combined cycles, on the other hand, are hybrids of the fully fired and unfired types of combined-cycle power plants. Parallel powered combined-cycle plants employ a gas turbine with an HRSG. However, unlike conventional gas turbine HRSG combined-cycle power plants where the steam from the HRSG is the only steam source for the steam turbine, parallel powered combined-cycle plants utilize steam from a conventional steam boiler and an HRSG.
The HRSG can be designed to supply supplementary main steam, reheat steam or low pressure steam. In addition, the HRSG steam is sometimes used to preheat all or part of the condensate or feedwater.
According to Joyce, the great advantage of parallel powered combined-cycle plants is its versatility with regard to design, fueling and operation. In operation, plant management has the flexibility to use either the gas turbine or the steam turbine to generate the most electric power. Because only the flue gas from the coal-fired boiler might need to be cleaned, parallel powered combined-cycle power plants can be more efficient even when coal accounts for 65 percent to 85 percent, Joyce said.
Parallel repowering of a plant entails supplying the plant`s existing steam turbine with additional steam from a gas turbine exhaust-fired HRSG. The end result is a more efficient parallel repowered combined-cycle plant with the flexibility to operate the steam and gas turbines independently or as a combined cycle.
Joyce said that the high pressure section of a steam turbine is the most severe limitation to increasing the steam supply to an existing steam turbine. As a consequence, parallel repowering is best accomplished by providing a supplementary source of hot reheat and/or low pressure steam.
Because of the greater stress from increasing the steam flow, the blading of some stages of the steam turbine may have to be upgraded. The efficiency of parallel repowering is maximized by fully utilizing the sensible heat in the gas turbine`s exhaust for producing superheated steam and for heating as much of the condensate and feedwater as possible.
Boosting, another form of repowering, is where the new HRSG is designed solely to heat the condensate or the feedwater. It is possible to heat the full condensate and feedwater of a power plant by utilizing a gas turbine with about one-third the rating of a plant`s existing steam turbines. Known as full boosting, this type of repowering option does away with the need for steam extraction used for heating a plant`s condensate and feedwater.
Unfortunately, in some instances closing the extraction valves on the steam turbines can cause overloading in the low pressure section of the turbine. It can also lead to overloading of the generator. Where this is a problem it is more common to adopt a smaller gas turbine and design the HRSG to preheat only a portion of the condensate or feedwater, Joyce said. Figure 4 shows how full boosting can increase a plant`s output from 160 MW to 245 MW and plant efficiency from 39 percent to 42 percent. However, at part load there is a sharp drop in the plant`s heat rate.
According to Joyce, while neither fully fired nor parallel powered combined cycles possess the same high efficiency potential as unfired combined cycles, they do allow more efficient electric power generation from a mix of relatively inexpensive coal and natural gas or distillate than is attainable with just coal. Likewise, by increasing the use of natural gas or oil over that of coal reduces the emissions of CO2.
In terms of efficiency, Joyce said that fully fired combined cycles are inherently superior to parallel powered combined cycles. As a result, fully fired combined cycles are particularly suitable when power plant emissions can be met by primary measures such as using low-sulfur fuels and low NOx combustion technology.