Chemistry and Corrosion Aspects in Gas Turbine Power Plants

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1 Chemistry and Corrosion Aspects in Gas Turbine Power Plants Dr. Mirco Colombo and Rolf Rüetschi Alstom (Switzerland), Baden Summary The reliable operation of a gas turbine power plant depends on the operation media composition and purity. The possible impacts from the chemical environment of the gas turbine represented by air, fuel gas, fuel oil and water have to be considered. Excess concentrations of certain fuel components or a contamination in one or more of the operation media may have detrimental effects on gas turbine components like GT compressor, valves, burners, turbine airfoils, cooling channels, etc. Knowing the fuel properties the respective measures can be applied to guarantee trouble-free gas turbine operation. By the control of the impurity levels in all the operation media the corrosion, fouling and damage risk can be strongly reduced. 1. Introduction In the aftermath of the liberalisation of the national electricity markets during the last decade gas turbine power plants constantly gained market share. Their comparatively low investment costs and short project execution times offered independent power producers an affordable entry into new markets. But also the former state utilities are relying on gas turbine plants to diversify their generating capacity. With their short start-up times gas turbine plants are ideally suited to compete for profitable peak power supply, but in combined cycle configuration their high efficiency also allows for economic generation of band energy. However the increase of gas turbine plants was not paralleled by an equal increase of gas turbine specific themes in power plant chemistry discussion groups. About the reason for this can only be guessed. But it is important to be aware that there are a lot of areas in gas turbine power plants requiring chemical considerations during design and operation in order to guarantee the expected performance and lifetime of the plant. In the following an overview over the chemistry and corrosion aspects in gas turbine power plants will be given. The process and the main components of a gas turbine power plant are depicted in Figure 1. The chemistry in the gas turbine power plant is dominated by the combustion behaviour of the fuel to be used at the project site, followed by the corrosion and scaling properties of the combustion gas in the gas turbine and hot gas path. The two above subjects will be discussed in chapters 2 and 3, 1

2 respectively. Also very important, but more difficult to estimate than in the hot gas path, are the corrosion and fouling risks in the compressor and GT air path. This issue will be dealt with in chapter 4. The influence of inlet air cooling (evaporative cooling, fogging) for power output increase is included in the considerations in chapter 4 whereas the effect of water injection into the combustor for NO x reduction and power augmentation is discussed in chapters 2 and 3. Efficient cooling is crucial for the lifetime of hot running parts. Possible causes and effects of cooling channel fouling are shortly discussed in chapter 5. Figure 1: Process diagram of a gas turbine power plant 2. Fuels, Combustion and Emissions Modern high performance gas turbines with annular or can combustors generally require gaseous fuels or liquid distillate fuels whereas the combustion of ash bearing fuels is restricted to turbines with silo combustors. In order to evaluate the suitability of a fuel for GT application the following key parameters have to be checked against the specification of the respective GT type. Liquid Fuels: Gaseous Fuels: Properties and Composition Properties and Composition Kinematic viscosity Range of lower heating value (LHV) Density at 15 C max. Range of net Wobbe Index (WI) 2

3 Fuel temperature, max. Fluctuations of LHV and WI net Pour point Gas pressure Flash point Gas Pressure fluctuations Distillation recovery Gas temperature Carbon residue Hydrogen sulphide (H 2 S) Heating value Hydrogen Heating value fluctuations Higher Hydrocarbons (C 2+ ) Elementary composition (C, H, N, S) Impurities: Aromatics content Dust content Ash content Particle size of dust Impurities: Lube oil content Water and sediments Relative humidity Trace elements (Na, K, Ca, V, Pb, Ni, Zn) Trace elements (Na, K, Ca, V, Pb, Ni, Zn) Liquid Fuels: The kinematic viscosity of liquid fuels has to be within a defined range for optimum atomisation at the nozzle. If the viscosity is too high the fuel needs to be heated to reduce the viscosity. But the maximum pre-heat temperature has to stay below the limit value at which coke formation sets off. An elevated risk of coke formation is also indicated by increased carbon residue and aromatics content as well as high distillation recovery temperatures. Aromatic compounds additionally increase the radiation impact on components in the combustion chamber. A high aromatics content may require a reduction of the turbine inlet temperature. Coke deposits in fuel systems are very unpleasant since they are hardly soluble in any solvent. This results in affected components having to be removed from the machine for mechanical cleaning. Coke formation in the fuel distribution system is normally paralleled by smoke formation in the exhaust, leading to excessive CO and particulates emissions. High SO 2 emission are caused by corresponding high sulphur content of the fuel whereas fuel bound nitrogen will contribute to the NO x emissions. Water and sediment impurities may cause filter clogging and promote corrosion and wear in the fuel storage and forwarding system. Ash and trace element impurities contribute to corrosion and fouling of the components downstream (i.e. turbine and hot gas path). Gaseous Fuels: In comparison to liquid fuels the supervision of gaseous fuels is less demanding. One of the main concerns in gaseous fuels is the content on condensable molecules. Swells of hydrocarbon condensates may cause overheating of the burner. Condensed water can cause corrosion in the fuel distribution system. If the corrosion products reach the combustor hard deposits of the molten oxides will be deposited on the turbine. If the fuel gas contains elevated levels of sulphur 3

4 compounds, hard deposits are also formed by reaction with humidity and condensed hydrocarbons in the fuel gas system. In order to avoid condensation the fuel gas has to be pre-heated at least 20 K above the dew point. The contamination of gaseous fuels with volatile fuel bound trace elements is mostly restricted to biological and industrial waste gases. Otherwise the traces elements are present as dust and can be separated with appropriate filter systems. Emissions: For gaseous fuels the NO x emissions are controlled by lean premix combustion. For liquid fuels the injection of water is necessary in order to reduce the flame temperature and thus the NO x emissions. Normally a water to fuel ratio of about ω=1.2 is applied. 3. Turbine and Hot Gas Path In the combustion chamber the alkali metal impurities in the fuel react with the sulphur of the fuel to form sodium and potassium sulphates, which condense on the surfaces of the turbine and hot gas path. At temperatures in the range of 700 C C the alkali sulphates on the turbine are molten and react with the metal, causing the notorious hot corrosion (sulphidation). In order to control the hot corrosion the content of alkali metals in the combustion air has to be minimized. Crude and heavy fuel oils may genuinely contain some sodium whereas the sodium in distillate fuel oil is normally caused by pollution with salt water during transport. The water-soluble ions sodium and potassium can be removed from the oil by washing and dewatering in a fuel oil treatment plant. There are also attempts to reduce the corrosivity of the alkali sulphate melts by dosing of Cr, Mo and W based fuel additives. By the additive dosing the melts are transformed in dry deposits which can be washed off. However the deposit build-up between the wash cycles reduces the efficiency of the turbine. Alkali metals in the combustor are not only due to the fuels but may also origin from the ambient air and the water used for NO x reduction and power augmentation. Therefore all the contaminant concentrations of the individual streams have to be added, and their overall concentration in the hot gas must not reach levels which are detrimental to the hot gas path components. For Alstom gas turbines the alkali metal limit in the hot gas corresponds to 0.2 ppm and 0.5 equivalent fuel concentration, respectively, depending on the turbine material. The following formula shows how the concentration of any individual contaminant in the hot gas is composed (related to the fuel mass flow): f equiv f + a m a / m f + w m w / m f + i m i / m f 4

5 f equiv : max. specified summarized contaminant concentration of all media streams as equivalent fuel contamination (ppm) f: contaminant concentration in fuel (ppm) a: contaminant concentration in air (ppm) w: contaminant concentration in water/steam injected into combustion chamber and air stream (mg/kg) i : contaminant concentration in any other media stream (additives, etc.) (mg/kg) m a : mass flow of air (kg/s) m f : mass flow of fuel (kg/s) m w : sum of water/steam mass flows (denox water, quencher, power augmentation, fogging, carry-over of evaporative cooler, etc.) (kg/s) m i : mass flow of any further media stream to the gas turbine (kg/s) In ash bearing fuel oils additionally heavy metals are found. These metals, mainly vanadium and nickel, are chemically bound in oil soluble organometallic complexes and therefore cannot be removed in a fuel oil treatment plant. Upon combustion they form corrosive metal oxide melts that cause high temperature corrosion. With magnesium additive dosing the melts can be transformed into non-corrosive and washable deposits. But if the gas temperature is too high or the sulphur content in the fuel too low the deposits loose irreversibly their solubility, causing fouling of the turbine. Turbine fouling is also caused by calcium and silica impurities in the fuel, water and air. 4. GT Compressor and GT Air Path Dust and salts of the ambient air are normally retained at 80% -90% by a dry and well maintained air intake filter. But if the filter is overloaded or gets wet due to condensing ambient humidity the separation performance decreases. Volatile air impurities like SO 2, NO x and VOC pass the filter unhindered and also the small soot particles are hardly retained. The salts, dust as well as the organic air impurities precipitate on the compressor and the air path according to the local flow conditions. On the first rows the deposits consist to about 70% of organic matter and 30% dust and soluble salts. The sticky organic molecules are acting like a binder for the dust and salts. The compressor fouling does not only cause significant power loss but also poises a serious corrosion risk due to the high content of corrosive salts. During operation the corrosion is restricted to the first inlet stages since the latter stages run dry. But during standstill the hygroscopic salts in the deposits of the latter stages get also hydrated, thus forming concentrate brines. If the salts contain chlorides pitting corrosion underneath moist deposits has to be expected. In order to avoid standstill corrosion the compressor should be washed, dried and preserved for extended shutdown periods. Regular compressor washing is also required to restore turbine performance. In order to remove the adherent organic impurities a water / detergent wash with a compressor 5

6 cleaner is necessary. The corrosion properties and trace impurities of the cleaner have to be verified before use in order to avoid additional corrosion and fouling caused by the cleaner. Compressors can be cleaned on-line and off-line. Off-line cleaning is more thorough but requires the engine to be shut-down. On-line cleaning is used to bridge the period between off-line cleaning cycles. However after long periods without cleaning the compressor should first be cleaned off-line, otherwise the accumulated salts are flushed into the hot gas path. In order to increase the mass flow of the GT compressor and thus the power output of the turbine the inlet air can be cooled. There are two cooling systems based on water evaporation, evaporative cooling and air inlet fogging. In an evaporative cooling system the air passes through high surface media cells which are percolated with circulating water, thus cooling the air by evaporation of the water on the cell surfaces. The carry-over of water droplets into the cooling air increases the impurity flow to the compressor. For control of the carry over of salts drift eliminators are installed downstream of the evaporative cooler and the concentration factor of the circulating water is adjusted with the flow of the continuous blow-down. For air inlet fogging water is sprayed through fine nozzles into the inlet air plenum upstream of the compressor to create a fog of fine droplets. By evaporation of the water the air is cooled. In normal fogging applications the position of the nozzles and the amount of injected water are adjusted that the droplets of the fog have evaporated before reaching the compressor. In high fogging applications the fog enters the compressor and is evaporated in the warm sections of the compressor. All the impurities in the fogging water are carried into the compressor air. Therefore for the fogging water the same purity requirements as for the NO x reduction water apply (i.e. demineralised water). Since the fogging is only operated periodically the questions of the remobilisation of salt deposits after long non-fogging periods as well as possible biological fouling of the spray nozzles have to addressed in the operation concept of the plant. 5. Cooling Channel Fouling The hot running parts of gas turbines are cooled in order to assure their performance and lifetime. For the cooling air is taken from the GT compressor. The narrow channel and fine nozzle of the cooling system are very sensitive to fouling. Salts and minerals of the compressor air as well as corrosion and oxidation products of components upstream may lead to blocking of the cooling channels. For more efficient cooling in high performance turbines the hot GT compressor air is cooled before being used for hot part cooling. The large surface of air coolers increases the risk of oxide release into the cooling air. Alternatively efficient cooling can also be achieved by open cycle or closed cycle steam cooling. However steam cooling bears additional risks of cooling channel fouling. In steam the oxidation of 6

7 materials is accelerated, increasing the risks of oxide particles in the coolant. In high pressure steam the solubility of silica and salts is increased. In order to limit the risk of corrosion and fouling in the cooled parts the purity of the steam has to be monitored and controlled. 6. Conclusions The performance and component life of gas turbine power plants depend strongly on the chemical properties of the operation media. By control of the impurity levels in the media air, fuels and water the corrosion and fouling risk can be strongly reduced. 7

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