Location, site and climate can all have a substantial impact on the efficiency and power output of gas turbines. In hot climates and or at high altitude, gas turbines operating in single or combined cycle generate less power than their equivalent counterparts operating in a cooler climate or near sea level.
Seasonal and diurnal weather variations also affect turbine performance. With the demand for power in the Middle East and Southeast Asia growing, turbine experts have focused on developing techniques to improve the efficiency of turbines operating in hot and humid climates.
Gas turbines are air-breathing machines whose power output is dependent on the air mass through the compressor. Ambient temperature, altitude and humidity all affect the density of air. On hot days, when air is less dense, power output falls off. Hot and humid air is less dense than dry, cooler air and the density is thinner at high altitudes. As the density of air decreases, more power is required to compress the same mass of air. This reduces the output of the gas turbine and decreases efficiency.
Gas turbine manufacturers specify performance at standard conditions called ISO ratings. The three standard conditions specified in the ratings are Ambient Temperature 15oC, Relative Humidity 60 per cent, and Ambient Pressure at Sea Level. Gas turbine efficiency deteriorates by 1 per cent for every 10-degree rise in temperature above ISO conditions. Depending on the gas turbine, this translates into a power output reduction of 5 to 10 per cent.
Inlet air cooling systems
In the last 20 years in an attempt to compensate for the lower air mass at high temperatures, gas turbine (GT) manufacturers have introduced techniques to cool inlet air, thus boosting turbine output in single and combined cycle operations. Feeding cooler air into the turbine increases mass flow, resulting in higher output. The power required to compress air is directly proportional to the temperature of the air, so reducing the inlet air temperature reduces the work of compression and there is more power available at the turbine output shaft.
Three main types of system are available: evaporative cooling, overspray techniques (high fogging or wet compression) and chiller technology. In evaporative cooling, water is trickled through a porous medium to cool the air. Evaporative cooling is not effective in conditions of high humidity. Water is not injected into the system.
In a fogging system, water droplets are sprayed in the air to artificially create colder conditions. The water evaporates in the air inlet before reaching the compressor. In wet compression or inlet fogging, a fine spray of demineralized water enters the compressor, where it evaporates. Fogging and overspray systems require more water than evaporative cooling. In areas where water is in short supply, other techniques may be more appropriate.
Air inlet chilling cools the air by refrigeration. It is power-hungry but may be economic in cases where off-peak or cheap power can be used.
Each has advantages and disadvantages and it takes site-specific analysis of a number of factors to determine the optimum technology or combination of technologies.
Turbine expert Sasha Savic of SS&A Power Consultancy draws on wide-ranging experience to carry out the complex process. He starts by studying conditions at the site, including weather patterns and the availability of water. The next step is to consider the technology installed – as, for example, some GT technology is more prone to compressor erosion than others, in which case it might be necessary to limit the amount of water injected. Then the all-important economic aspects, such as capital investment and the added value from investment, must be evaluated. It is important to look at the payback as customers have different tariffs, boundary conditions, capacity and payback times.
Savic says that it is “a complex equation with no one solution”.
“You have to understand the behaviour and ambient conditions for the operating period. Normally cooling technologies have lower specific costs than buying or building new capacity. It is important to look at all these details before making a recommendation.”
In the Middle East, ambient temperature is very high in summer at the time when peak demand (notably for air conditioning) is at its highest. Wet compression is one of the available techniques for inlet air cooling. It can be retrofitted to existing frames as well as supplied with new systems. It works best in a very hot dry climate, but is effective in high humidity.
Wet compression increases the power output of the gas turbine by reducing compressor inlet temperatures, inter-cooling the compressor and increasing mass flow throughout the turbine.
Demineralized water is injected into the compressor. It evaporates in the air intake and increases the saturation of air, which increases the mass flow, leading to additional capacity. Wet compression systems can be easily switched on and off, enabling a rapid increase of output peak demand.
Retrofitting wet compression to existing turbines requires some adaptations to the plant (for example, coating compressors with advanced coatings), but it enables the addition of capacity without civil work such as adding generators and additional transformers. Once in place, the inputs for wet compression are demineralized water and power to run the forwarding pumps. The water evaporates in the compressor and cannot be recovered, so the technique is particularly suited to power plants running alongside desalination facilities.
Zaid Al-Sati specializes in wet compression systems for Siemens Power Generation Services in Dubai. He says that wet compression is perfectly suited to upgrade capacity for baseload machines, especially in Middle East areas close to the sea where humidity is high.
“The system has many benefits here in the Gulf region. It is very sustainable technology which is independent of ambient temperature and of humidity,” he says.
The company performed its first upgrade in North America in the late 1990s, followed by the ME region in 2004.
Operators’ decisions about plant upgrades will be based on economic, financial and technical considerations. On the technical side, any power plant being considered for upgrades must be individually assessed and a step-by-step check of plant components carried out.
Al-Sati describes the detailed process of assessing suitability for retrofitting wet compression technology:
“First of all, we define the amount of water which can be sprayed in the unit, depending on the frame, the site-specific boundary conditions and the history of the unit, including reports from previous outages. We look at casing limitations and condition of blades and vanes at the last inspection.
“We check maximum fuel supply pressures which can be delivered; check if there are any boiler limitations in terms of additional exhaust energy. We look at steam turbines and steam turbine generators and calculate their capability to accommodate the additional capacity generated by wet compression. We calculate maximum and minimum temperatures, and look at the generator electrical side and transformers to check that an additional 15 per cent can be accommodated.”
If the plant is suitable, wet compression technology can be fitted to the unit during a regular plant outage without affecting outage duration.
During the design of a new or upgraded gas turbine model, the major OEMs take into account the various extreme climatic conditions of their potential markets.
In Saudi Arabia and the Gulf countries, the gap between summer and winter temperatures can be substantial. On a hot day the density of air entering the compressor is less than on a cold day. Thus, during summer days, the compressor has less mass flow than the gas turbine capable of utilizing. By installing an oversized compressor, the OEMS can design their systems to utilize unused capability during hot days.
Alap Shah, AVP & Turbine Technologies Manager with Black and Veatch, explains:
“In that case, if you oversize the compressor you can include variable guide vanes in the first few stages of the compressor. Opening the guide vanes passes more volume through the GT and maintains a more or less linear output curve.”
This advance may not improve efficiency, but it enables more output at a higher temperature.
Another feature developed for hot climates is thermal energy storage, an extension of chilling inlet air. Chilling inlet air by mechanical chillers or vapour absorption chillers boosts the output of the GT by increasing density at the inlet to the compressor. However, while output goes up, there is a negative impact on the efficiency of the combined-cycle plant considering the auxiliary power consumed by chillers as well as reduced exhaust energy from the turbine.
Shah sees potential in using thermal energy storage for peak shaving, a technique used in a few newly-built combined-cycle plants in the Middle East and North America.
“The concept is to operate the chiller at night [off peak], store the cold energy in a significantly sized tank, and use that cold stored energy during the daytime when you have higher temperatures and higher demand,” he explains.
Thermal storage has become popular in the last few years as operating profiles have changed with the integration of renewables. Thermal storage makes good sense when plant is required to operate at peak load during the daytime and to operate at part or minimum load during the night to offset the increase in wind power.
The drive for efficiency
There are other areas for improving turbine performance in hot climates. One is to improve the aerodynamics of compressor technology. Another involves the overall efficiency in the classic turbine technology areas of materials, coatings and cooling. Improving the ability of turbines to operate at very high temperatures drives efficiency and reduces emissions. Work on the combustion system to improve fuel flexibility so that fuels such as shale gases and liquids or unrefined fuels can be burned is another area where work is underway.
Incremental improvements in combined-cycle technology and operations have seen overall combined-cycle efficiency rise to a current level of more than 61 per cent. Guy DeLeonardo, general manager for high efficiency gas turbines at GE Power & Water, believes that over the next decade this figure can be increased to 63 or 64 per cent, which will benefit operators in all climates.
Advances in materials, additive technologies and manufacturing techniques can all contribute to developments. For example, 3D printing can reduce the manufacturing costs of components in the latest-generation turbines. GE is now using an innovative manufacturing machine designed to produce cooling holes in gas turbine parts using a pioneering laser-cutting method.
An understanding of how turbines work in specific conditions is key to driving improvements in efficiency and preparing gas turbines for different conditions. GE is proud of its off-grid, full speed, full load testing facility in Greenville, South Carolina that tests its latest gas turbines beyond real-world conditions.
The $200 million test facility enables the company to fully validate its turbines at ambient ranges of -37°C up to 85°C. More than 6000 sensors and instruments collect data on all aspects of operation and components of the gas turbine during validation and more than 8000 data streams are captured continuously during testing. GE says that one unit running for 200 hours in the test facility is more valuable than 500 units in the field running for one year.
Add solar, save fuel
In the US and Spain, solar thermal power stations have been generating electricity for years. Concentrating solar power (CSP) technology is mainly based on the use of parabolic trough collectors, concentrating the solar radiation, heating up a thermal oil and transferring the thermal energy to a boiler generating steam, which then drives a steam turbine.
Additionally, a heat storage system with molten salt can increase operating time even at night. This can be added to a conventional power plant by integrating a burner into the collector field boiler. If there is no solar power (directly or from the storage), the boiler turns into a conventional one, using any standard fuels for steam production.
In a hybrid integrated solar combined cycle power station (ISCC), the first part of the plant is a standard combined cycle driven by a conventional fuel. For example, in the first stage a gas turbine generates the power. In the second stage, the exhaust heat is turned into steam (high temperature and pressure), directly used to feed an additional steam turbine. At the same time, the steam turbine takes additional steam (with low temperature and pressure) from a solar field boiler. Hence the solar collector field directly improves the power outputs of the steam turbine and the whole combined cycle, while storage is also used.
Development of ISCC is in its infancy. Florida Power & Light’s Martin Next Generation Solar Energy Centre was the first hybrid combined-cycle natural gas and CSP power plant to be developed in the US, and deploys 75 MW of parabolic trough CSP.
The MENA region’s largest SCC plant is the $554 million Ain Beni Mathar project in Morocco. The 160 ha site includes a huge solar field contributing about 20 MW to the total capacity of 472 MW. Hassi R’Mel integrated solar combined cycle power station in Algeria combines a 25 MW parabolic trough concentrating solar power array, covering an area of over 180,000 m2, in conjunction with a 130 MW combined-cycle gas turbine plant. Mexico’s first ISCC power plant comprises a 464.4 MW combined-cycle power plant and a 12 MW solar field.
Karim Saidi of MAN Turbo Machinery, which has provided turbines to Abengoa and other solar developers, is enthusiastic about the potential for ISCCs. He says that while the technology is not fully market-ready, the availability of new materials will drive it forward.
“The material to build a solar receiver with its storage at 900°C is not really available in the market. Some small developments have been done, but at lower temperature around 650°C-700°C.”
“The objective is to maximize the operating time of the solar share of the combined cycle. Next steps might take another 10 years, but the development of suitable storage material will bring interesting fuel savings,” Saidi says.
“Especially for the Middle East, where natural gas is cheap and solar direct radiation capacity is very high, ISCC solutions could then be turned into reality, bringing a lot of benefits.”
He points out that organizations in the Middle East often look for established solutions, and further development of CSP technology is needed to needed to make ISCC hybrids readily acceptable in the region.
CASE STUDY: FUJAIRAH 2 WATER AND POWER PLANT
Fujairah City on the Gulf of Oman is the business and commercial hub for the mountainous emirate of Fujairah.
From October to March, daytime temperatures average around 25°C, rarely venturing above 30°C. Summer temperatures climb to over 40°C. High population growth and rapidly expanding urban and industrial sectors have led to increasing demands for air conditioning and potable water.
A consortium of ADWEA, International Power and Marubeni Corporation formed the Fujairah Asia Power Company (FAPCO) to develop, own and operate Fujairah (F2) as a new IWPP on a Greenfield site next to Fujairah F1 plant at Qidfa near Fujairah on the Gulf of Oman coast.
In 2007 a consortium of Alstom and Sidem was awarded the $2.1 billion engineering, procurement and construction (EPC) contract for F2. The consortium also has a 12-year long-term supply agreement for operation and maintenance. F2 has been designed to provide a constant output of potable water alongside a demand for power that rises to 2000 MW in the summer and falls during the winter months to around 900 MW. The 2000 MW, 130 MIGD project started commercial operations in 2011.
Alstom used its Plant Integrator approach to design a flexible, tailor-made dual-fuel solution with in-house core components. Three gas turbine combined-cycle blocks incorporate five gas turbines and three steam turbines. Power output varies from 40 per cent to 100 per cent. All the gas turbines are provided with inlet air-cooling to raise power under the high ambient temperature conditions frequently found at Fujairah. Each gas turbine also has its own heat recovery steam generator, which is fitted with a duct firing to improve flexibility by allowing additional steam to be raised within the steam generator when required.
The plant operates on natural gas supplied via pipeline from Qatar while a 10-day backup supply of oil is held offshore as a fallback in case supplies are interrupted. The cooling system uses sea water.
Rajashekar Sharma, Head of Product Promotion for Gas Turbines at Alstom, told PEi that the station at Fujairah 2, which uses a combination of evaporative cooling and high fogging (wet compression), is one of the best examples in the region of how inlet cooling can be used to improve gas turbine performance in the hot climate of the Middle East.