Gas turbines work on a constant-volume cycle, so power output depends on air mass flow. Warm air is less dense than cold air, so power output is reduced. Also, warm air needs more energy to compress it than cold air, removing more work from the compressor, increasing internal losses as it does so. The work required by the compressor can be 66% of the total turbine power. Therefore, gas turbine efficiency can be improved by cooling the inlet air. This is especially effective in hot, dry climates.
A significant benefit of turbine air inlet cooling is that it can reduce (or eliminate) fuel efficiency reduction by evaporative cooling the inlet air to the wet bulb temperature. However, note that over-cooling past the wet bulb temperature by chilling will increase power but with little or no net efficiency improvement. An increase in inlet air temperature from 15°C to 38°C increases the heat rate, which causes a decrease in fuel efficiency of about 4%. Turbine air inlet cooling can minimize this loss. In a gas turbine installation, the inlet air can typically be cooled from 15°C at 50% relative humidity (RH) to around 11°C by evaporative cooling, representing a fuel efficiency improvement of around 0.5% and a power increase of up to 3%.
Gas turbine air inlet cooling can be achieved in a number of ways, including the use of mechanical and absorption chillers (with or without thermal energy storage), or the evaporative type (wetted media, fogging and wet compression/overspray).
Water droplets can be sprayed into the intake air resulting, in effect, in compressor intercooling, reduced compression work and the required efficiency increase. This method also benefits CHP plant because the greater mass flow increases the specific heat of the exhaust gas. The vaporization of liquid natural gas (LNG) provides a chilling effect ideal if this is the plant fuel. True intercooling provides bigger efficiency gains, but providing intercooling is hardly a plant operation adjustment!
AxEnergy’s (www.axenergy.com) ‘UpStream’ gas turbine inlet air cooling system provides a power increase by adiabatic cooling of around 0.7% for each degree celsius of cooling, depending on ambient conditions and turbine type. Installed in a Rolls Royce Trent gas turbine at the Whitby cogeneration plant in Ontario, Canada, this achieved a maximum power gain of 7%.
Inlet air warming
In combined cycle, the highest plant efficiency does not require the highest gas turbine efficiency or pressure ratio. A balance has to be struck between the gas turbine firing (combustion) temperature and pressure ratio to maximize the steam cycle output. In such circumstances, inlet air warming using scavenged heat can improve CCGT efficiency on very cold days. Also, inlet air warming is often used for protection against the gas turbine’s mechanical limits.
A Centrax installation for Spanish company Arcilla Blanca SA, showing the air filter enclosure. This 1 x CX501-KB7 genset produces 5.2 MWe plus recovered heat for drying clay product
Inlet air warming can also be used to advantage with gas turbine plant operating in very cold locations (40oC or lower), either to reduce de-icing requirements, which can reduce efficiency although very cold air is usually dry or to maintain a high exhaust temperature for efficient combined cycle or CHP plant operation.
Steam or water can be injected into gas turbines to increase output power, improve part load flexibility and significantly reduce exhaust emissions. Saturated or superheated steam can be injected, usually into the combustion chamber, but this will significantly increase pressures, possibly above the compressor’s aerodynamic/mechanical design limits. Therefore, there are likely to be restrictions on the steam/fuel ratio, so steam injection is not available for all gas turbines.
A Centrax installation for the BRAL Algeria oil and gas complex showing the air filter enclosures. The hostile desert conditions mean that the Donaldson air filters and enclosures work hard protecting the two gas turbines
Water injection into the combustor is more usual. This actually reduces efficiency, but the increasing mass flow rate through the turbine increases power output by up to 10%.
Energy conservation technology for steam-operated machinery has brought about seasonal thermal/electric load variations. The flexible heat and power gas turbine can adjust efficiently to such varying needs, using both thermal and electric energy. Kawasaki’s GPC PLUS series gas turbines are suitable for such operation. To increase electricity output, saturated steam from a heat recovery steam generator is injected into the gas turbine. Operation using flexible heat and power is possible by changing the quantity of steam injection. To reduce NOx emissions, the turbine can operate in either water or steam injection modes and can be switched between the two. Steam injected in this way substantially expands the flexible heat and power range. And according to Kawasaki, using superheated injected steam means still more efficient electricity generation can be achieved.
Filtering inlet air
The hot and difficult operating conditions inside gas turbines mean that dirt from the intake air (and, more rarely, the fuel supply) can damage the blades. This occurs through particulates adhering to the blades (fouling), corroding them or eroding them each quite different mechanisms. These unwanted effects reduce blade efficiency, degrade performance and increase maintenance requirements. Turbine blades have very precise aerodynamic characteristics; any damage can reduce mass flow and effective pressure ratio. Both reduce fuel efficiency.
Inlet air filtration (as well as fuel filtration) is essential and will prevent most particulate matter from entering the turbine, but such systems result in a pressure drop. This, in itself, is an efficiency loss. If the pressure drop is reduced by a remarkably small amount (as little as 20 mm static pressure), hundreds of thousands of Euros per year can be saved in fuel costs for large plant. So good filter design should minimize pressure drop by balancing filtration efficiency against minimal pressure drop.
A camera from an ETR-Unidata’s air filter monitoring system. Such systems can measure sub-ambient particulate levels across full filter duct coverage
Modern gas turbine intake filters largely achieve this (typically using microfibre synthetic melt blown surface laminates), offering a minimum efficiency rating value (MERV) efficiency rating of up to 15, yielding a filtration efficiency of 99.999 % on 0.5 micron sized particles and larger. Note that the higher the MERV, the greater is the pressure drop across the surface of the filter. Where particulate contamination is especially heavy, pulse cleaned air filtration systems may be preferred, because the long-term pressure drop is lower.
Siemens Industrial Turbomachinery is trying to persuade its plant operator customers to specify top quality air filters to reduce maintenance requirements rather than increase fuel efficiency. However, Siemens points out that, even if there were a significant pressure drop, the resulting fall in fuel efficiency would result in extra heat lost to exhaust exactly what might be required for cogeneration plant increased overall efficiency.
Schematic showing how ETR-Unidata’s Epsilon air filter monitoring system provides full filter duct coverage
Replacing gas turbine air intake filter cartridges can be costly, so relatively inexpensive pre-filters that trap larger particles are often fitted to extend primary filter life. However, pre-filters will also suffer a pressure drop if dirt builds up too much, so they should be capable of being cleaned or changed while the gas turbine is running. Pre-filters may often run without washing for years.
Pneumafil’s (www.pneumafil.com) Ultrascrub air intake technology is claimed to significantly improve turbine performance while reducing maintenance costs. It combines very high efficiency filters with a scrubber-cooler to remove the 0.20.4 micron particulates (also chlorides, sulphates and sodium). The need for intermittent off-line washes is virtually eliminated, turbine component corrosion and erosion, and NOx emission are all much reduced. Ultrascrub has been field-tested on a 100 MW Dow Chemical installation in Texas, where calculated annual savings were over E600,500 compared with conventional technology. Higher total system efficiency is claimed to be one of the benefits.
Gas turbine air intake filter banks, up to six storeys high in large plant, contain thousands of filter elements which must be checked regularly or when programmed maintenance occurs. Both are time-consuming tasks. A better way of maximizing air filter efficiency is to monitor them electronically. Modern filter monitoring systems provide exactly the quantitative measurement and cross-sectional mapping of air filter performance required.
For example, ETR-Unidata’s (www.etr-unidata.com) Epsilon system measures sub-ambient particulate levels across full duct coverage. Based on laser scanning, and thought to be unique, it provides spatial information/resolution on individual filters starting to fail. The Epsilon also provides particulate distribution mapping, enabling identification of individual filters that may be failing. Use of such equipment can improve gas turbine plant efficiency as well as reducing downtime.
Parasitic energy losses
Parasitic energy losses result from all gas turbine moving parts, such as bearings and seals. Bearing frictional losses waste energy, generate heat and reduce life, including that of lubricants. A significant proportion of the total fluid film bearing losses in high-speed turbomachinery is consumed simply by feeding oil to the bearings. At bearing surface speeds below around 3000 m/min, parasitic losses are typically less than 10% those of the oil-film frictional losses. For higher speeds, the losses increase rapidly with surface speed and can reach 25%50% of total bearing loss. Such losses can be minimized speak to the bearing manufacturer or gas turbine OEM. This is very much a job for the experts, but may be well worth attending to in terms of improving gas turbine fuel efficiency.
Significant fractions of the total power output can be absorbed by auxiliary equipment required to run the plant. Principal electrical loads such as the turbine enclosure ventilation fan motors and liquid fuel pump motors all consume power. Careful equipment selection, operation and maintenance all help to reduce losses. A significant load is the fuel gas compressor for gas-fired turbines. These reduce plant net output. If no high or medium pressure gas pipeline is available, this can be a disadvantage for engines with a high cycle pressure ratio.
The fuel used in a gas turbine can also indirectly affect fuel efficiency in the long term. For example, many liquid fuels need pre-treatment to remove harmful vanadium and sodium compounds. Vanadium pentoxide and sodium sulphate are the main ash components formed at higher temperatures. This ash adheres to blades and causes corrosion. The preferred fuels in this respect are natural gas, properly prepared syngas, and distillate oils.
For cogeneration plant, some of the gas turbine’s exhaust energy is recovered for drying, process heat or process steam production, etc. So depending on the precise nature of the CHP plant, the gas turbine can be optimized for maximum thermal efficiency, or lower thermal efficiency with more useful heat in the exhaust.
Higher air intake or combustion temperatures raise the exhaust temperature, while a higher pressure ratio is likely to reduce the exhaust temperature this needs to be taken into account by cogeneration plant operators. For them, greater energy in the exhaust could be more important than ultimate gas turbine fuel efficiency. The ability of a gas turbine to provide good simple cycle and cogeneration efficiency depends on a high pressure ratio and exhaust temperature, so even relatively low efficiency simple-cycle gas turbines may be highly efficient when used in cogeneration plant. Such plant can achieve overall thermal efficiencies of more than 80%; nearly 90% if low-grade heat can be properly used.
If still greater amounts of exhaust heat are required, supplementary firing may be the answer. This is possible because gas turbine exhaust gas contains up to 15% of oxygen, which can be used to burn more fuel to further raise the gas temperature before passing to (for example) boiler flues in combined cycle plant. Supplementary firing can raise exhaust temperatures from about 500°C to around 800°C. This may double steam output, though at the cost of extra maintenance.
Flexibility versus efficiency
High gas turbine thermal efficiency does not always make for best plant efficiency. As explained, a lower gas turbine thermal efficiency will provide more heat in the exhaust for combined cycle or CHP plant. However, even leaving aside the argument that power plant has to make money for shareholders, best thermal efficiency is not always the most important goal. For example, greater operational flexibility is often needed today.
A GE industrial gas turbine core a high core thermal efficiency does not necessarily translate into high plant thermal efficiency, especially for combined cycle or CHP plant
Rolls Royce’s John Charlton says that Rolls-Royce is working towards producing more efficient flexible gas turbine-powered plant to take account of the effects of energy supply deregulation, environmental legislation and the connection to power grids of non-continuous renewables plant such as wind turbines. So the trend, he says, is now towards providing the flexibility to meet these demands.
For example, as an alternative to using an open cycle Rolls-Royce Trent gas turbine for daily cycling operation (around 42% thermal efficiency), the company also aims to provide a flexible combined cycle plant also based on the Trent gas turbine. This configuration uses supplementary firing to raise the gas turbine exhaust temperature. The steam cycle consists of a special OTSG single-flue (‘once through’ drumless) stack control heat recovery boiler and steam turbine connected to a common generator using a special clutch. The gas turbine and steam turbine each contribute around 50% of the generated power. Such combined cycle plant can be built up to 100 MW with 48%49% thermal efficiency, yet with the required flexibility.
A Rolls Royce RB211 industrial gas turbine. Such aero-derivative machines may be more suitable for the flexible operation demands of today’s plant, with thermal efficiency taking a relative back seat
Even so, when plant operates on a daily start-up and shut-down basis to provide power when it is most needed, there is usually a trade off between high efficiency and other factors. Aeroderivative gas turbines are usually better than dedicated industrial machines in this respect, as they are designed for greater operational flexibility from the outset.
There are many ways in which gas turbine plant overall fuel efficiency can be improved though careful operation (albeit through quite small increments). For still greater improvements, however, new generations of plant may be required. Raising gas operating temperatures still further is an obvious way, but this can only be achieved using very special, and usually highly expensive, hot path components. Single crystal and other exotic alloys for blading, as well as advanced ceramics, are examples of what will be needed, but will plant owners pay for them? This depends to a large extent on just how crucial it becomes to reduce exhaust emissions still further.
Where combined cycle plant is concerned, the best gas turbine will often be only of medium thermal efficiency (with higher exhaust temperature) working in conjunction with a relatively low efficiency steam turbine plant, yet which has good exhaust heat utilization properties. So, absolute maximum machine thermal efficiencies and best plant efficiencies are often not synonymous.
There has been a proposal to develop a combined gas turbine-Rankine cycle power plant. This would have an improved part load efficiency deriving from use of a gas turbine with an organic fluid Rankine bottoming cycle featuring an inter-cycle regenerator acting between the superheated vapour leaving the Rankine turbine and the compressor inlet air. The regenerator would be used as engine power fell below maximum rated power.
James Hunt writes on energy issues from the UK.