Turbine Guideline

POWER PLANT SIMULATOR TRAINING INSTITUTE Bakreswar Thermal Power Project :

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44 STEAM POWER PLANT TURBINE A steam power plant continuously converts the energy stored in fossil fuels ( Coal, Oil or natural gas ) or fissile fuel ( uranium, thorium ) into shaft work and ultimately into electricity. The working fluid is water, which sometimes in the form of liquid and sometimes in the state of vapour phase during its cycle of operation. Energy released by burning of fuel is transferred to water to generate steam at high pressure & temperature, and then it expands in turbine to a low pressure to produce shaft work. The steam leaving the turbine is condensed in a condenser. Thus it follows the cycle -

LIMITATIONS OF HIGHER EFFICIENCY: To achieve higher efficiency turbine inlet steam temperature should as high as possible and exhaust steam temperature of LP turbine should be as low as possible. Considering the metallurgical limitations turbine inlet steam pressure & temperature should be around 130-150 kg/cm2 & 540 0C. LP turbine exhaust pressure & temperature depends upon quality of cooling water available at site. However maximum wetness of LP turbine exhaust steam should be restricted to 12%. In India capacity of Thermal Power Plants are ranging from 50 MW to 500 MW. Most of the Turbines are either Russian design LMW sets ( Leningrad Machine Works) or German design KWU sets ( Kraft Werk Union).

210 MW LMW TURBINE :

210 MW KWU TURBINE :

Steam Turbines are of two types : 1. Impulse Turbine 2. Reaction Turbine. 1. Impulse Turbine : In impulse turbine fixed nozzles are used for expanding steam to convert steam pressure into kinetic energy of steam. The high velocity steam impulse acts on the moving blades to rotate the turbine shaft.

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Steam after gliding over the moving blades changes its direction of flow. This change of direction of flow causes change of momentum, which create rotational motion of turbine shaft. Steam pressure is dropped across the fixed blades to develop high velocity of steam. No pressure is dropped while gliding over the rotating blades 2. Reaction Turbine : When steam expands over the fixed blades, heat energy is converted into kinetic energy. This high velocity steam acts on moving blades. This results in change in momentum and reaction effects. Some heat energy of steam is converted into kinetic energy when it moves over the moving blades due to its typical shape. It is a continuous process in reaction turbines to convert pressure / heat energy into kinetic energy. The turbines may also be classified as: 1. Axial Flow Turbine. 2. Radial Flow Turbine. 1. Axial Flow Turbine. Steam flows along the axis of the shaft while passing through the turbine. Most of the turbines are axial flow type. Steam inlet & outlet pressure drop develops axial thrust on the turbine shaft along the direction of steam flow. 2

Radial Flow turbine : Steam flows along the radius of the blade in Radial Flow Turbines. It is also called L’lungstorm turbine. Normally it rotates two separate shafts and two generators are driven. It can be started very quickly and its capacity. Its maximum limited to 50 MW. Turbines may also be classified based on flow paths: 1. Single Flow Turbine. 2. Double Flow Turbine. 3. Reverse Flow Turbine. 1. Single Flow Turbine: In this system steam expands in one direction and exhausted. 210 MW LMW HPT & IPT and 210 MW KWU turbines are single flow turbines. In single flow turbine the difference of steam inlet & outlet pressure develops a huge amount of axial thrust on the shaft. To reduce this axial thrust a dummy piston is placed at the inlet to produce opposite force. Moreover a thrust bearing is provided in between HPT & IPT. 2. Double Flow Turbine : In this system steam inlet is through middle portion of the turbine and after that steam expands in both direction. After work done on turbine shaft it is exhausted. Normally specific volumes of steam at different points are:

Sl.No. 1. 2. 3. 4.

Location of Steam H.P. Turbine inlet I.P. Turbine inlet I.P. Turbine exhaust L.P. Turbine exhaust

Specific Volume ( m3 / kg) 0.0245 0.135 0.385 22.5

From above it is seen that steam expansion in L.P. Turbine is 58 times. 210 MW LPT and 210 MW KWU IPT & LPT are of double flow turbines. 3. Reverse Flow Turbine :

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In some big size turbine steam expand in first few stages in reverse direction to reduce axial thrust on the turbine shaft. Main components of steam turbines : 1. Turbine shaft. 2. Turbine casing. 3. Moving blades fixed on rotor. 4. Fixed blades fixed on casing. 5. Turbine bearing to support rotor. 6. Dummy Piston in HP Turbine. 7. Gland sealing. 8. Rupture Diaphragm in LP turbine. Turbine Shaft & Moving Blades: The rotor shaft transmits the torque generated by the change of momentum of steam. Turbine shaft or rotor holds turbine blades. The moving blades are used to convert kinetic energy of steam into driving force of the shaft. Shroudings are provided at the last stage of turbine blades to avoid vibration due to long length of blades. In impulse turbine moving blades change the momentum of steam to generate torque. No pressure / temperature drop occurs while passing through moving blades of Impulse Turbine. Impulse blades are compact, heavy and robust. In reaction turbine driving force is generated by reaction force of steam as it accelerates through the moving blades. In this turbine pressure drops both in the nozzles / fixed blades as well as in the moving blades since shape of the moving blade channels are also nozzle shaped. Due to the expansion of steam while flowing through the blades, there is an increase of kinetic energy, which gives rise to reaction in the opposite direction (Newton’s third law of motion). Blades rotate due to both impulse effect of the jets (due to change in momentum) and the reaction force of the exiting jets impressed on the blades in the opposite direction. Such turbines are called impulse-reaction turbines, or to distinguish from impulse turbine, simply reaction turbines. Outer Casing: It is the stationary part of the turbine. It holds the fixed blades/ diaphragm of the turbine. Casing may be single shell or double shell. Metal thickness of single shell casing is high to withstand the temperature difference of steam inlet temperature and atmospheric temperature 210 MW LMW turbine is of single shell type. To reduce metal thickness high pressure turbines are made of double casings. Each casing is designed to withstand relatively low temperature difference. This reduces metal thickness. 210 MW KWU turbines are made of double shell type. Fixed Blades: The fixed blades convert heat energy of steam into kinetic energy. The first stage of HP impulse turbine fixed blades is nozzles shaped to perform as nozzles. Steam pressure drop takes place in these nozzles. In reaction turbine small amount of heat drop takes place in each stage, hence size of each stage is smaller than of impulse turbine and no. of stages is high. One pair of fixed blade and rotating blade forms a stage of turbine. Front end pedestal: The following accessories are located in front end pedestal: 1. Main Oil Pump. 2. Over-speed trip device. 3. Hydraulic speed transmitter. 4. Shaft position measuring device. 5. Journal bearing of turbine ( Brg. No. 1 ) 6. Electric speed transmitter. 7. Speeder Gear. 8. Vibrations pick up etc.

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Dummy Piston: High pressure & temperature steam when expands in a single flow HP turbine along the axis of the shaft, it develops a huge amount of axial thrust acting on the shaft in the direction of steam flow. To reduce / minimize this axial thrust a dummy piston is provided at the inlet of turbine .A force opposite to the axial thrust is generated in dummy piston. The value of axial thrust is more in a reaction turbine than in an impulse turbine. Thrust Bearing: Thrust bearing is provided to absorb unbalance axial thrust generated in turbine. It is located in between HP & IP turbine at central pedestal. The bearing is called as ‘Michel type’ tilting pad bearing. The wedge shaped cavity between thrust pad & shaft collar is filled with oil. Diaphragms : Diaphragms are located inside inner casing of turbine to house stationary blades. The fixed blades in an impulse turbine have the form of nozzles mounted in diaphragms. Diaphragms are fixed in both upper & lower halves of the cylinder casing by means of keys so that during expansion of the cylinder fouling with the shaft seal is avoided. LP turbine diaphragms are cast type. The cast type diaphragms are made of iron castings with steel nozzle plates embedded in them. To avoid leakage of steam across the diaphragms seals are provided in between shaft and diaphragms. TURNING GEAR / BARRING GEAR : • Turning gear motor drives the TG shaft at a slow speed before steam rolling to avoid the need of large quantity of steam flow to get the rotor moving from rest. This avoids unwanted thermal stress on the rotor shaft. • After shutdown of turbine, various parts of it remain at high temperature and uneven cooling of the same takes place, which in turn may cause shaft bending and misalignment. To avoid this TG shaft is rotated at slow speed through barring gear for uniform cooling. In LMW turbine Turning Gear is mounted on LP – Generator coupling. It rotates TG shaft at 3-4 rpm. by a turning gear motor. In KWU turbine the shaft is rotated by a hydraulic turbine at around 120 rpm. Before putting the TG on barring gear the following must be ensured : • Generator seal oil is established. ( to avoid rubbing of seal block). • Turbine lub oil system is established. • Jacking oil pump is running properly. There is a provision of hand barring to rotate turbine shaft by engaging hand barring manually in case of failure of barring gear driving mechanism. Metallurgy of Turbine : Turbine operates at high temperature & pressure. Hence Creep & fatigue failure of the shaft may occur. Considering these factors the metallurgy of turbine shaft is selected. When any component is under thermal stress at high temperature for a considerable period creep stress occurs. The material may fail due to this creep stress. It varies directly with the duration of time. Creep failure occurs at the blade attachment with the rotor shaft. Thermal fatigue develops after repeated cyclic reversal of thermal stresses. This happens due to repeated heating & cooling of turbine. If steam temperature is fluctuated repeatedly at the inlet of HP & IP turbine fatigue failure may occur. Considering the above the metallurgy of the turbine should be : • Good creep resistance at high temperature. • High fracture toughness. • Good mechanical toughness. • Good proof strength. HP & IP rotors are made from Cr Mo V ferritic steel.

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LP rotors requirement is low temperature high tensile strength and high toughness. For this it is made of 3.5Ni Cr M0 V material. Expansion of Turbine: The turbine casing and rotor expands and contract due to heating and cooling. Due to difference of metal mass of rotor and casing the rate of expansion and contraction are different. The casing may expand both in radial and axial directions. Radial expansion is controlled by radial fixing points. The maximum expansion in axial direction at full load is called the absolute expansion. The casing may expand over the sliding support. The bearing pedestal is allowed to slide axially on keyways fitted between bedplates / soleplates and pedestal. Some cases pedestal bearings are fixed with the foundation and the casings are allowed to expand to one end by means of supporting feet. Axial Expansion of Rotor: For KWU 210 MW turbine the anchor point is at central pedestal i.e. at bearing no. 2. HP turbine rotor expands towards bearing no. 1, whereas IP & LP turbine rotors are expanded towards bearing no. 5. In LMW turbine HP-IP coupling is rigid one and IP-LP coupling is semi-flexible. The axial expansion of rotor is difference between HP & IP rotor expansion since IP for LMW turbine is single flow type. In 210 MW KWU turbines HP-IP & IP-LP both couplings are rigid. Permissible axial shift is 1.7 mm towards front end pedestal and 1.2 mm towards LP turbine. Axial Expansion of Casing: HP cylinder casing is anchored at bearing no. 2, so its casing expansion takes place towards bearing no. 1. IP cylinder casing is anchored at bearing no. 3, so it expands towards bearing no. 2. LP cylinder is anchored at middle of casing, so it expands towards bearing no. 4 & 5. Expansion bellows are provided I LP turbine to accommodate LP casing expansion.

Differential Expansion of Rotor: Both rotor & casing of turbine expands due to increase of temperature. Due to difference of geometry and mass of metals the expansions are different. The difference of expansion of rotor & casing is called differential expansion. Its value may be (+) ve or (-) ve. Positive expansion indicates Rotor is expanded more than casing and opposite in case of (-) ve expansion. The TURBINE BEARINGS : LMW 210 MW TG Bearing No. 1, 3, 4 & 5 are journal bearings, whereas bearing no. 2 is a combined journal cum thrust bearing. KWU 210 MW TG bearing No.1, 3, & 4 are journal bearings, whereas bearing no. 2 is a combined journal cum thrust bearing.

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Journal Bearings : Turbine Rotor is supported on journal bearings. The bearing is splitted into two halves. White metal is used as bearing metal. The bearings are spherical in shape to take over small deflection of shaft. Combine journal cum Tilting Pad Thrust Bearing : Michel type bearings are universally used to withstand heavy axial thrust of turbine shaft. It is accomplished by using oil film. Function of thrust bearing is to bear thrust load and to keep the shaft in position to maintain stator & rotor blade clearance. This bearing has a provision with a step on the back to tilt. Due to this tilting ability an oil film is formed in between shaft collar and white metal lining of thrust pad. Pads are usually fitted on both sides of the collar. This thrust bearing is combined with a journal bearing for supporting the shaft.

45 THERMAL POWER STATION TURBINE PLANT LAYOUT DESIGN & ITS LOCATION Introduction – Power station layout is concerned with the logical and economic use of space and the relationship of one piece of plant with another. The design & layout of Steam Turbine station building, which contain Main Turbine, Generator and Turbine auxiliary equipment and its system like condensing system and equipments, regenerative system & equipments, cooling system & equipments, lube oil system & equipments, feed system & equipments, compressed air system & equipments, etc are very much important for the erection cost control & easiness of operation and maintenance, good and safe working condition. An efficient turbine plant and system layout minimizes losses and running cost. Ideally, plant items should be located as close as practical considering adequate access for operation and maintenance. The best layout design of turbine plant & its system involves the correct balance between lowest cost and best arrangement from both constructional and operation point of view. The basic layout of a standard 210 MW capacity Turbine Station has already been standarised considering above stated aspects. However, the Turbine plant arrangements within the building envelope vary due to the design and manufacture of main plant items particularly Turbine, Generator, Condenser and its auxiliary equipments. The basic pattern consists of an integral building structure with Boiler and Turbine houses arranged in parallel but separated by annexe containing mechanical, electrical auxiliary plant items and its systems including instrumentation.

1. Main Turbine Plant Orientation – With fossil fired plant, the important determination and consideration for T.G. Plant layout design are – a) The overall dimensions of Turbine Generator with the condensing, feed heating and general Turbine auxiliary plant with walkway and passages. b) Provision for adequate access, unloading bay, lay down area for machine parts. c) Turbine hall dimension & space for lifting generator and turbine with casing. d) E.O.T. crane for lifting and installation of equipments. e) Regenerative heaters position and location. f) Type and design of B.F. Pump, C.E. Pump, etc. g) Piping layout from Boiler to Turbine & Turbine to Boiler. Beside this, one of the most important decisions, which influences overall station layout, is the choice of the relationship between T.G. and Boiler, since both the Boiler center line spacing and dimensions of the Turbine hall can be significantly influenced by this decision. The final out come depends on

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traditional expenses of plant layout, choice of plant supplier, relationship between civil, electrical, mechanical cost, scope of supply of particular contractor, site problem & concerned engineers liking/disliking. 2. Turbine Generator Island Concept – It is conventional practice for T.G. to be supported by foundation block, which are elevated above ground level of power station. The height (13 mtr. for Bk.T.P.P, 9 mtr. for K.T.P.P.) at which T.G. is located is termed as operating floor elevation. The operating floor layout of T.G. alone is termed as island layout. This layout is the most popular layout preferred by most power station manufacturers and designers. The preference is based on need to provide – a) b) c) d) e) f) g) h) i)

3.

Clear and unhindered access to main plant items. Direct crane access to all parts of the Turbine hall. Good maintenance access, efficient lighting and ventilation to all area. Opportunity for equipment location in intermediate floor levels. Better facility for Turbine maintenance and ample lay down space. Pleasing and uncluttered appearance of the Turbine hall. Control room is in same elevation of T.G. floor better monitoring facility. Most economic and practical layout. Best access and plant maintenance. Turbine – Generator Auxiliary System – The following system are included –

a) b) c) d) e) f) g) h) i)

Feed heating system. Condenser and condensate system. Compressed air system. Cooling water system. Circulating water system. Main lube oil, jacking oil & control oil system. Turbine oil purification system. Generator seal system, Gas system. Gland sealing cooling & Vacuum system.

4.1 Feed Heating System – It forms an integral plant of the generating process by raising the temperature and pressure of the condensate returning from the Turbine to Boiler end. In this system, a number of pumps (Boiler Feed Pumps, C.E.Pumps, Drip Pumps, etc.) and heaters (H.P. & L.P. Heaters) arranged in saris and which are linked by pipe work system. The location of each of the components in the system follow logical and defined sequence and it is important in terms of overall system economics and hydraulic performance. Each elements of this system should be correctly located in relation to the other and to the Turbine in particular. 4.2 Condenser & Condensate System – The condenser is an integral part of the Turbine as it serves as heat sink & creates vacuum. Recently more conventional under-slung arrangement is preferred. In this arrangement condenser, it self located directly beneath the L.P. Turbine. The main advantages of this location are: a) Easy condenser box erection facility. b) Access for tube insertion & withdrawal. c) Convenient C.W. pipe, condensate pipe connection & optimized C.W. pipe length. d) Good water distribution and uniform flow through condenser. e) Convenient efficient air extractions system related to condenser. 4.3 Circulating Water System – It serves to transform L.P.Turbine exhaust steam to water. The system-piping network located below ground and connected to condenser and Cooling Tower through C.W.Pumps.

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4.4 Auxiliary Cooling Water System & D.M.C.W. System – Cooling water system maintains temperature of Turbine Oil, Seal Oil, Generator Gas, etc. of T.G. system and working oil of B.F.Pumps. 4.5 Compressed Air System – Compressor are vital equipment for the control of Turbine, Boiler and auxiliary equipment operation, testing, cleaning. In Bk.T.P.P. compressors are located in ground floor between ‘AO’-‘A’ Row. Air system piping distributed from compressor drier discharge. 4.6. Turbine Lube Oil, Jacking Oil, Control Oil System, Oil Purification System & M.O. Tank – The location of the above system is very much important from standpoint of fire protection, cleanliness and safety. 4.7 Generator Seal Oil System & Gas System – Generator seal oil system is very much important for generator shaft sealing to prevent Hydrogen gas leakage from generator or ingression of air into generator. Gas system is important for maintenance of Hydrogen pressure in generator, H2 gas purging out by CO2 gas system & gas filling. 4.8 Gland Sealing, Cooling and Vacuum System – Turbine gland sealing, cooling & vacuum system are separate system provided with Turbine auxiliary system to maintain vacuum in condenser, to seal the Turbine gland and to cool gland Steam through condensate water. The above systems are connected with Turbine separately and located below Turbine floor for erection cost control and operation maintenance facility. System equipments like blowers, coolers, ejectors are located below Turbine floor. Some sub-systems like HP & LP Bypass system, oil vapour extraction system, on-load tube cleaning system are also include with the main system of steam system (MS, CRH, HRH) piping, Turbine lube oil system and circulating water system in modern power station like Bk.T.P.P. for assistance service to the system. The important sub-system are located within the main system separately and positioned in the Turbine house. Another most important location is piping and valves layout. More than 200 nos. power operated valves are installed and located in the powerhouse for remote / local operation of a standard 210 MW thermal power station.

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46 THEORY OF STEAM TURBINE, SPECIAL FEATURES AND CONSTRUCTION DETAILS OF TURBINE 1.

Introduction: The Steam Turbine is a most popular prime mover of generator, which requires steam as a working fluid, a source of high-grade energy and a sink for low-grade energy. When the steam flows through the Turbine, part of the energy content continuously extracted and converted into useful mechanical work. The main objective of the Turbine designer are to ensure that this process of conversion of heat energy of steam to mechanical work is carried out with – maximum efficiency, maximum reliability and minimum cost. Second objectives are that the plant should require minimum supervision and minimum starting time. Steam Turbine offers many advantages – a)

From thermodynamic point of view, the Steam Turbine occupies a favourable position as it can translate into mechanical work from the expansion of steam in the Turbine. Its thermal economy also good especially in Turbine of large output and operating at high pressure.

b)

From mechanical point of view, the Turbine is ideal because propelling force applied directly to the rotating element of machine.

2.

Theory of Steam Turbine :

2.1

Modern Steam Cycle – Thermal Power Station operates by using steam in closed power cycle, where water undergoes various thermodynamic processes in a cycle process. One-half of the cycle consists of the boiler cycle (heat source) and the other half is turbine cycle, consists of turbine, condenser, feed pump and feed water heaters. Feed water supplied to the boiler drum where water is boiled and converted into saturated steam and that steam further superheated to the super heaters and then fed to the turbine where the steam expands and give-up heat energy, a high proportion of which is transferred into work energy on the turbine shaft due to change of momentum in the moving blade and increment of velocity in the nozzles and/or moving blades. The exhaust steam from turbine, which is termed as carry over loss, passes to the condenser where it condense by transferring its latent heat of vapourisation to the cooling water. This condensed water enters into hotwell and the same is pumped by condensate extraction pump through L.P. Heaters, coolers to the Deaerator and Feed Storage Tank. Boiler Feed Pumps, in turn, takes feed water from Feed Storage Tank and pumps the feed water to the boiler drum routing through regenerative heaters. In this way water cycle and steam cycle is completed. This cycle follows modified Rankin Cycle. In this cycle steam after HP Turbine outlet sends for reheating to the boiler again. The reheated steam further expanded in the IP & LP cylinder for increasing the thermal cycle efficiency.

2.2

Development of various types of Turbine and their theory of operation – a) Simple Impulse Steam Turbine – Here steam expansion takes place in the set of nozzle and the pressure drops to about condenser pressure after expansion in nozzle. The expansion of steam results very high velocity and due to this high velocity steam jet blade/rotor velocity reaches maximum. In this Turbine carry over/exhaust loss also high and efficiency is poor. This type of Turbine is not economical and can be employed for small power generation. b) Pressure Compounded Impulse Turbine – This type of Turbine construction is arrangement of number of simple impulse Turbine in series on the same shaft, allowing the exhaust steam from one Turbine to enter the next Turbine nozzle. Each simple impulse machine is termed as a stage of Turbine. Each stage comprising of a set of nozzles and blades. Here total pressure drop in the Turbine is the summation of pressure drop in each stage nozzle & for that reason the Turbine is termed as pressure compounded. Here nozzles are fitted into partition, termed as diaphragm. It separates one

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wheel chamber to another. Due to pressure compounding, steam velocity, blade velocity, rotor speed and leaving loss is lower that that of simple impulse Turbine and its efficiency is higher. c) Velocity Compounded Impulse Turbine – This Turbine comprises a set of nozzle with two or more rows of moving blades & number of guide blades. Guide blades are fixed blade, fitted with stator, placed after first stage and in between moving blades for guiding steam & to direct in the next stage. The guide blades are set in reverse manner. In this Turbine, steam expands in the first stage nozzle & nozzle outlet pressure reaches about condenser pressure. There after steam passes through rows of guide blades and moving blades. In guide blade, there is a slight velocity drop due to friction. In this Turbine leaving loss is small; being about 1–2% of initial available energy of the steam with the ordinary nozzle arrangement, the most efficient speed of blade of this Turbine is 0.15 of steam speed. d) Pressure Velocity Compounded Turbine – This type of Turbine constructed on basis compounding both pressure and velocity in a single rotor. The wheel carried two rows of blades between nozzles. The efficiency of the Turbine is not so high. e) Pure Reaction Turbine – This type of Turbine is not a practical type though “Parson” tried to develop. f) Axial Flow Impulse Reaction Turbine – This Turbine is a joint application of the impulse & reaction principles of operation. Here, in every stage & steam expands in nozzles & enters in moving blade where it suffers a change in direction i.e. momentum and undergo small drop in pressure which gives rise to a reaction in the opposite direction of increased velocity. Thus, gross propelling force is vector sum of impulse & reaction force. This type of Turbine is very efficient & successful Turbine.

2.3

Factors of Turbine performance and sizing – Turbine performance and sizing is affected by followings i) Initial Steam Pressure. ii) Initial Steam Temperature. iii) Whether reheat is used or not, and if used reheat pressure and temperature. iv) Condenser Pressure. v) Regenerative Feed Water Heating. i) Initial Steam Pressure: With increase in the initial steam pressure at constant temperature & constant condenser pressure, wetness of steam in the last stages of turbine increases, thereby reducing internal efficiency of these stages. Usually 1% moisture in steam in a particular stage results in 0.9 to 1.2% reduction, erosion becomes so severe that life of turbine in endangered. With increase in initial steam pressure, blade heights of initial stages get reduced. If blade heights of initial stage blades are less than 25 mm, this stage becomes very inefficient due to three dimensional flow and vortex formation etc. Sometimes this problem is overcome by partial admission in first or first few stages. With increase in pressure, shell thickness of casings and size of flange and flange bolts increase. Bigger and thicker flanges and flange bolts implies non-symmetric casing resulting in higher incremental stress, thereby restricting rate of speeding loading of Turbine. This problem to certain extent can be solved by using multi (double) shell design for casings or by flange and flange bolt heating arrangement.

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In light of above considerations lower initial steam pressures and used for smaller Turbines (resulting in simple design and quicker start ups) and higher initial steam pressure are used for larger Turbines (resulting in higher efficiency). The following are typical recommended value of initial stream pressure for various rating Turbines:50 MW 50 – 100 MW 100 – 200 MW 200 – 300 MW 300 – MW & above

-

50 to 90 ata (non-reaheat) 90 to 130 ata. 130 ata. 130 to 170 ata. 130 to 240 ata.

ii) Initial Steam Temperature: As initial temperature increase, the thermal cycle efficiency increases and hence from thermodynamic (theoretical considerations) there is no upper limit for initial steam temperature. Material considerations do restrict the initial steam temperature. Up to 4000C plain carbon steels can be used and up to 4800C low alloy steels can be used. Above 4800C and up to 6000C heat resistant ferritic steels can be used. It gives limiting value of initial steam temperature to be 5650C (Leaving margins for temperature swings). During operation of power plants, it was found that plant outages due to boiler failure with initial steam temperature 5650C were enormous as compared with initial steam temperature 5350C. Now-adays, practical limit for initial steam temperature is 5350C to 5400C. Above 5400C temperature, austenitic steels could be used, which have higher coefficient of thermal expansion & lower thermal conductivity but poor machineability and weldability as compared to ferritic steels. For these reasons, use of austenitic steels is not preferred. iii) Reheat: Reheating the steam after it has partially expanded, improves the thermal cycle efficiency by 4 to 5% as a more efficient cycle is added to original cycle. With the reheat, available heat drop (for conversion to work) increases by almost 12% per unit mass of working fluid, resulting in almost corresponding reduction in mass flow of working fluid for generating same power output. This results in smaller auxiliary equipment (like condenser, heaters, condensate and boiler feed pumps), resulting in savings in investment. Reheating reduces moisture in last stage of Turbine, thereby improving the internal efficiency of Turbine. Reheat is universally used for unit ratings higher than 100 MW. Sometimes, double reheat is also employed for supercritical pressure units. Steam after partial expansion is usually reheated to initial steam temperature at pressure 0.15 to 0.3 times initial pressure. Absolute increase in thermal cycle efficiency and thermal plant efficiency by reheating is approximately 1.5 to 2% respectively. iv) Condenser Pressure: A condenser provides heat sink, low vacuum and preserves working fluid (Condensate water). Lower condenser pressure implies lower mean temperature at which heat is rejected to sink, thereby increasing the thermal cycle efficiency. Lower condenser pressure also means larger volumetric flow of steam at Turbine exhaust, resulting in larger L.P. Turbine and larger condenser. The increase in capital cost of L.P. Turbine and condenser due to lower condenser pressure is usually offset by increase in efficiency.

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v) Regenerative Feed Water Heating: In modern power thermal power station, usually feed water is heated to 0.65 to 0.75 times saturation temperature in 5 to 9 heaters by regenerative heating for achieving optimum efficiency. As a consequence of steam extraction for feed water heating, increased steam flow through Turbine is required to generate the same power. Usually thermal cycle employing regenerative feed water heating will have 30% higher flow at stop valves and 30% lower flow at Turbine exhaust as compared to thermal cycle without regenerative feed water heating. This makes regenerative feed water heating even move attractive due to following reasons: a) Increased steam flow in initial stages results in increased blades heights resulting in improving internal efficiency of Turbine. b) Reduced flow at Turbine exhaust demands lesser exhaust area, resulting in smaller blades in last stages blades, which limiting factor in Turbine design. c) The decrease in steam flow at Turbine exhaust also reduces flow of working fluid through auxiliary equipment (like condenser, condensate pumps, ejectors and low-pressure heaters), thereby reducing their sizes and saving in capital investment. Construction of Steam Turbine: Main components of a Steam Turbine are i) Rotors, ii) Cylinders or casings, iii) Emergency Stop Valves and Control Valves, iv) Liners and Diaphragms, v) Blades, vi) Bearings, vii) Sealings, Viii) Barring Gear, ix) Governing and Protection System, x) Turbine Supervisory System.

3.

i)

Rotor: If the Turbine is impulse type the rotor is disc type, i.e. blades are carried in the discs, which may be integral forged with shaft or shrunk on the shaft. If the Turbine is reaction type, the rotor is drum type, i.e. blades are directly carried on the rotor. In the integral forged rotors discs and shaft are machined from one single forging. The main advantage of integral rotor is that there is no disc loosening problem and as such are commonly used in high temperature zones (H.P. & I.P.) integral rotors are expensive and difficult to forge and there is relatively high incidence of rejections. Also more material is to be removed by machining. Now a days, it is becoming more and more popular for fossil fuel Turbines. Build-up type rotors can be of two types (a) Shrunk-on disc rotor - It is used when rotor is too heavy to be forged in single piece. Shaft and disc are forged separately and are assembled after machining is shrinking of discs on shaft. (b) Welded (Hollow drum) rotors – In this case discs are separately forged, rough machined and welded together at periphery to make the complete rotor. Radial holes are drilled in the rotor so that steam can go inside the voids of rotor and help in uniform heating of the rotor. Welding and subsequent heat treatment has to be performed with extreme care. Rotors are coupled by means of coupling. Earlier semi flexible coupling were used because these allowed a limited amount of misalignment and required original rigidity. In this case, each rotor required its own set of bearing. Now-a-days trend is to use rigid coupling, because in this case only one bearing is required between two rotors (because whole rotor system behaves as a single rotor).

ii)

Casings:

Turbine casings are essentially pressure vessels, their weight being supported at each end. These are therefore, designed to withstand and hoop stresses in transverse plane and to be very stiff in longitudinal direction to maintain accurate clearance between stationary and rotating components.

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Usually casings are of two designs (a) Single shell casings, (b) Multi (double) shell casings. Single shell casings take pressure drop from steam pressure to atmospheric pressure in single shell and hence required thick wall and heavy flanges at parting planes. This causes very large incremental thermal stresses during transients, resulting in slower start-ups and shutdowns. This problem to certain extent is solved for flange and stud heating. In Multi (double) shell casings, there is intermediate pressure (approximately 25% pressure of main steam) between the shells and hence two shells resulting in thinner walls and lighter flanges at parting planes share pressure drop. This type of casing has lower incremental thermal stresses during transients resulting in quicker start-ups and shutdown. Multi (double) shell casings are now commonly used for H.P. and L.P. Turbines.

iii)

Emergency Stop Valves and Control Valves: Turbines are equipped with emergency stop valves to cut off steam supply and with control valves to regulate steam supply. In case of reheat Turbines emergency stop valves are also provided in the hot reheat line. Emergency stop valves are actuated by servomotor controlled by the protection system. ESV remains either fully open or fully close. Control valves are actuated by the governing system through servomotors to regulate steam supply as required by the load.

iv)

Liners and Diaphragms: In reaction Turbines, guide blades are directly carried in the casings and hence liners and diaphragms are not generally used. In impulse Turbines, most of the pressure drop of a stage takes in guide blades resulting in higher deflection guide blades. Additional bending strength to guide blades is provided by diaphragms. Welded diaphragms are used in higher temperature zones while cast diaphragms are used in low temperature zones.

v)

Blades: Blades are single most costly element of Turbine. Blades fitted in the stationary part are called guide blades or nozzles and fitted in the rotor are called moving or working blades: Blades are of three types: a) Cylindrical (or constant profile) blade. b) Tapered cylindrical (tapered but similar profile) blades. c) Twisted (twisted and varying profile) blades. This type of blade is used for very long blades. Blades have three main parts (a) Aerofoil: it is working part of blade and is one of the types described above. (b) Root: It is portion of the blade which is held with disc, drum or casing. Three type of root arrangement are commonly used; (b1) T-Roots: from small blades; (b2) Firtree or Serrated Roots: for longer blades; (b3) Fork and Pin Root: for longer blades but it can be used with shrunk on disc type rotors only.

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(c) Shroud: It can be either riveted to main blade or it can be integrally machined with the blade. Now-a-days trend is towards integral shroud for shorter blades and free standing for larger blades. Some times lacing wires are also used to dampen the vibration and to many frequencies in the longer blades (e.g. LMW machine – 210 MW)

vi)

Bearings: Journal bearings are manufactured in two halves and usually consist bearing body faced with antifriction tin-based babbiting to decrease coefficient of friction. Bearing body match with adjustable seating assembly in the pedestal. Bearings are usually forced lubricated and have provision for admission of jacking oil.

The thrust bearing is usually Mitchell type and is usually combined with a journal bearing, housed in spherically machined steel shell. vii) Sealings: Sealings in Turbine casings are provided to check steam leakage from H.P. and I.P. Turbines and air leakage into L.P. Turbine. Sealing of Turbines are usually Multi-labyrinth type, which provide maximum amount of throttling in a given axial length. viii) Barring Gear: Barring gear rotates the Turbine as high speed when Turbine is being started or shutdown, thus allowing uniform heating or cooling of the rotors to avoid any distortion of rotors. .

ix)

Governing and Protection System: Governing system is provided on utility steam Turbines to maintain rated speed (within steady state regulation) at all the loads and to provide predetermined load sharing among the Turbines operating in the grid. Governing system has speed control in parallel to speed governing to maintain constant speed at all the loads when set is running is isolation and change load share of Turbine when running in parallel.

x)

Turbine Supervisory System:

Instrumentation is provided for indication/recording of important parameters like vibrations, eccentricity, differential expansion, overall expansion, valve position and stresses in major components. Hooked up with indicators are suitable alarms and tripping mechanisms for cautioning the operating men and tripping the Turbine, if these values reach alarmingly inadmissible values. Special features of Bk.T.P.P. Turbine (Similar to KWU design):

4. 1.

Fuji Electric Company, Japan make, Tandem compound condensing type, three-cylinder reaction turbine with reheat cycle and regenerative feed water heating system. No. of stages in H.P. = 23, in I.P. = 17 and in L.P.T = 8 x 2.

2.

Individual rotors of H.P., I.P. and L.P. cylinder are rigidly coupled.

3.

All rotors are machined from single forging.

4.

H.P. cylinder – Barrel type design and permit flexible operation, rapid start-up and high load change. The casing has no flanges and hence thermal stress is minimized. The inner casing is vertically split.

5.

H.P. Turbine employed with throttle governing without a control stage.

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6.

H.P. Turbine main steam pipe connection after valve designed by easy detachable breech nut and ‘U’seal ring elements. Cold reheat pipe designed as single pipe construction tapped from H.P. Turbine exhaust for materials saving and erection advantage. The pipe divided into two sections at boiler area.

7.

I.P. Turbine is single flow double shell construction fitted with two nos. combine reheat stop valves and intercept valves to control steam flow from reheater to turbine (I.P.) and to prevent acceleration during trip-out of turbine by the remaining steam of reheater pipe and flow back to H.P. Turbine.

8.

I.P. inlet steam pipe fixed at outer casing vertically is provision of expansion in all direction fixing special type ‘L’-ring.

9.

Double flow, three casing L.P. Turbine is connected with I.P. Turbine through cross around pipe and Turbine exhaust is multi exhaust type and extraction (L.P.) tapped at difference stages for moisture control and sizing control. The L.P. exhaust directly connected to the twin condensers.

10.

L.P. Turbine gland packing with connected through bellows for keeping turbine rotor centre unaffected.

11.

H.P. & I.P. rotors, exposed to high temperature, are designed as integrally forged reaction blades with shroud and formed as rigid shaft. Therefore, blade vibration chance can be avoided.

12.

The entire turbine blading is provided with reaction blading for achieving highest efficiency. The stationary blades are inverted ‘T’ or ‘L’ and shrouds are machined from solid. Last three stages of L.P. Turbine blades are designed without shroud ring and of taper twisted type.

13.

Critical speed of H.P. and I.P. rotors are designed to be above normal rated speed. Critical speed of this Turbine is 3700 and 1739 rpm.

14.

The bearing pedestals of the L.P. Turbine are mounted on the foundation. L.P. cylinder carries shaft seal housing are joined with outer casing by diaphragm. Here the flexibility factor of each bearing is greater than double point bearing and the bearing type is dynamically stable.

15.

The journal bearing is double wedge type. At the bottom of bearing centre oil hole with nozzles provided for jacking of shaft.

16.

The turning gear, positioned between I.P. & L.P. rotor and at bearing no.-3, is provided with oil hydraulic type turbine for high-speed turning (80 – 120 rpm) by oil pressure.

17.

Turbine is provided with two nos. oil coolers of each capacity 100%.

18.

The Turbine oil pumps for lubrication and governing is directly mounted on main oil tank and oil pipe connections are welded type routed through oil canal.

19.

Turbine equipped with Electro-hydraulic governor with provision of a standard hydraulic governor as a back up.

20.

Governor impeller serves as speed detector and generates primary oil pressure corresponding to speed, which in turn regulates speed governor bellows.

21.

High pressure jacking oil system for Turbine rotor jacking during coasting down of speed or rising of speed or during turning operation is provided to eliminate chance of bearing Babbitt material rubbing.

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The axial shift of each Turbine is about to ‘zero’ irrespective of loading. The differential expansion/contraction problem is avoided in this design for multi casing construction of Turbine cylinder. Large load dumping of Turbine, islanding and house operation, quick start-up and shutdown facilities are provided with incorporation of 60% capacity H.P. & L.P. bypass system.

23. 24.

a) b) c) d) 5.

Important parameters: Main Steam Inlet RSV Inlet Exhaust Pressure No. of Extraction

-149 Kg/Cm2, 5370 C. - 33.9 Kg/Cm2, 5370C. - 0.103 Kg/Cm2. - 6 nos.

Special features of Turbine (LMW design): 1.

210 MW capacity, BHEL make, Tandem compound condensing, three cylinder, horizontal, disc and diaphragm type with nozzle governing.

2.

High pressure Turbine comprises 12 stages, 1st stage is governing stage.

3.

After H.P. Turbine steam flows for reheating and fed to I.P. Turbine of 11 stages.

4.

I.P. Turbine coupled with L.P. Turbine by semi-flexible coupling.

5.

L.P. Turbine is double flow with a multi exhaust is each flow. No. of stages is 4x2 and in penultimate stage is Baumanian exhaust provided for large moisture separation. L.P. Turbine handles 88% dry saturated steam. Three Turbine rotors are supported on five bearings.

6. 7.

Turning gear with motor is mounted on L.P. rear bearing cover to mesh with spur gear & to rotate rotor at 3.4 rpm during start-up and shutdown.

8.

High response hydro-mechanical governing is provided for speed/load control.

9.

30% H.P. & L.P. bypass system provided for start-up.

10.

Initial steam unloading gear is provided for unloading Turbine when main steam press drops more than 10% of rated steam pressure.

11.

Flange & stud heating system is provided for casing heating during cold start-up and rotor heating is provided for hot start-up.

12.

Main steam parameters at inlet at rated load – 130 kg/Cm2, 5350C. Rated steam flow – 670 T/hr, CW flow – 27000 T/hr, Turbine exhaust pressure – 0.08 Kg/Cm2.

*** *** ***

47 TURBINE START UP FROM COLD, WARM, HOT, VERY HOT CONDITION ALONG WITH ITS AUXILIAIRES. TURBINE START – UP 1).

PREPARATION FOR TURBINE START UP.

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(a) At least one CW pump and ACW pump are running (b) Turbine lub. Oil system is healthy i.e. Auxiliary oil pump is running and AC EOP & D.C. EOP are in auto. AC JOP is running and D.C. JOP is in auto. (c) Generator seal oil system is healthy with normal H2 pressure (2Kg/cm²) and normal H2 purity (> 99.5%). (d) Turbine is running at barring speed (80-120 rpm) with turning oil supply valve full open. (e) Turbine interlock system is healthy. (f) MOT oil level normal. MOT vapour extractor running and lub. Oil temp. at oil cooler outlet is more than 35°C, Lub. Oil temp. control in auto & set point 40°C. (g) DMSW pump is running and DMCW make up tank level is normal (h) DMCW (T) pumps running (at least one). (i) Service Air and instrument air compressors running. (j) C.T fans are running (k) At least one condensate pump (CEP) and boiler feed Pump (BFP) running on recirculation and also condensate path and feed water path are through. Check the quality of Hot well and deaerator water, if necessary take fresh DM water. (l) Hot well level and deaerator level are normal and respective controllers are on auto. 2).

MAIN TURBINE PRE-WARNING: (a) Check that M.S line and H.P. bypass drain valves to unit flash tank is open. All the drains connected to HP. Flash tank should be closed and alternate drains to unit flash tank will be opened till condenser vacuum min. 320 mm Hg is achieved. HPBP warm up line valves are closed till condenser vacuum pulling. (b) Charge M.S. lines at boiler outlet pressure 10 kg / cm² and temperature 200°C (c) Warm up M.S. lines for 30 minutes. (d) Raise M.S. pressure to 35Kg/cm² and temp. 280°C (e) Put the TAS system in service and maintain its normal pressure & temp. In auto (>9kg/cm² & 270°C)

3).

VACUUM UP OPERATION: Gland steam exhauster is running. Put starting ejector in service after achieving gland steam header temp. more than 21°C and steam pr at starting ejector >7Kg/cm². At condenser vacuum. 135mm of Hg, put gland steam controller in service and set G.S. header pressure at 0.068 kg in auto At condenser vacuum 200 mm of Hg, close vacuum breaker and put on auto. Close all atmospheric drains (connected to UFT) and open their drains to HP flash tank. Watch continuously LPT exhaust temp. Check drip line loops and ejector loops are sealed with normal water level and established. When vacuum reaches 680mm of Hg withdraw starting ejector.

(a) (b) (c) (d) (e) (f) (g) 4).

HP-LP BYPASS SYSTEM OPERATION: (a) After achieving vacuum (>670mm of Hg) set the HP bypass downstream temp. at 320°C. (b) Ensure water supply before spray control v/vs of HPLP BP (c) After warning HP-LP bypass lines through warm up lines gradually open HP-LP bypass valves up to 5% and allow steam to flow through these lines. (d) Set the HP BP and LPBP down stream pressure at 25 kg/cm² respectively and put them on auto. If required increase boiler firing rate.

5).

CHECK THE FOLLOWING CONDITION OF DRAIN VALVES: (a) All the drain valves of M.S. lines are open to UFT. (b) Open all the drain of CRH and HRH lines to flash tanks (i.e. CRH 101, HRH

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101,102,103,104,109,110,115,116). Open drains of MSV warming (L) –MAL - 11 and MSV warming (R) –MAL-12 up to 25%. Open HP connection pipe L & R drain valve (MAL-13, MAL-14) full. Full open HPT casing drain v/v (MAL-22). Full open drain of ICV warming (L&R) MAL -26, MAL -31 Full open drain of IP connection pipe (L&R) MAL-27 & MAL 32 Full open drain of cross side pipe and balancing pipe MAL-40 Full open gland steam pipe drain MAL-18 Full open HRP steam strainer (L&R) drains Full open before & after seat drains of all extraction steam lines to flash tanks. Observe M.S. pressure and temp. reached at least 35kg/cm² and 300°C.

6).

CHECK THE METAL MATCHING CONDITION : (a) Check the boiler outlet temp. and R.H. outlet temp. superheat is more than 50°C (b) Check the steam purity PH - 9.0 to 9.3 ; conductivity < 1.0 µ mho/cm. Silica < 0.05 ppm ; total iron < 0.05 ppm It required sufficient steam dumping may be done to achieve above steam purity. (c) Raise the M.S. parameters for metal matching condition of MSV, HPC and IPS according to the following graphs. (SEE FIGURE – 1 TO 5 ATTACHED AT THE END).

7).

TURBINE STEAM ROLLING: Depending upon the HP turbine outer casing metal temp. at 50% metal thickness, the type of turbine start up can be chosen: Cold start up : < 250°C Warm start up : 250 -410°C Hot start up : 410 -460°C Very hot start up : > 460°C

(A) 1)

2) 3) 4) 5) 6)

7) 8) 9)

Cold start up (HP casing temp. <250°C ) Manual rolling : Select EHG Governor All the trip devices and generator relays are in reset condition Speeder gear (65M) : 100% EHG speed setter (65F) : 0% EHG power setter (65P) : 0% Slowly bring the starting device (77M) to 0% and reset the turbine (TLR). Slowly increase 77M from 0 to 42%. At 77M 0% auxiliary starts up oil will reset the trip devices and start up oil will reset stop (MSV, RSV) valves. At 42% starting device position start up oil and aux. start up oil pr. will be reduced to zero. As trip oil pr. develops at the bottom portion of stop valves, pistons, stop valves (MSV, RSV) start opening. Thus heating of MSV & RSV starts as MAL drain valves are previously opened. Full open MSV (L& R) warming drains valves (MAL-11, MAL-12). Checking the warming of MSV and RSV casing Check the MSV (L) casing metal diff. temp. ∆Ø< limit value (30°C) Check the HP turbine casing neutral diff. temp. ∆Ø < limit value (30°C) Check the IP rotor metal diff. temp. ∆Ø < limit value (30°C) Check the diff. temp. of turbine casing between top & bottom HPT < 55°C IPT < 65°C Close the MSV (L&R) warming drain valve from 100% to 25%. Check the shaft eccentricity < 75 µM. Check the LPT exhaust temp. Within limit and put spray valve on auto.

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13)

14) 15) 16)

17)

18) 19)

20)

21) 22) 23) 24) 25)

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Now increase the starting device (77M) position to 100% Confirm the condition for speed up from curve and metal matching condition for MSV, HPT, and IPS. Select TSC influence: ON and turbine speed raise mode selected slow (200 rpm/ min.). Selection of speed raise mode is given below:Speed change rate Start up mode Zero to heat soak (1080RPM) Heat soak to rated (3000RPM) Cold (<250°C) 200 rpm/ min. 500 rpm/min. Warm (250-410°C) 500 rpm/min. 500 rpm/min. Hot (410-460°C) 500 rpm/min. 500 rpm/min. V. Hot (460°C above) 500 rpm/min. 500 rpm/min. Set the EHG speed setter (65F) : 1080 RPM (soaking speed). This increases EHG output and thus develops secondary oil pressure to open CVs proportionately. Don’t hold the turbine between 400 to 1050 rpm . In case of any trouble, decrease the speed to turning speed. Confirm that at turbine speed more than 400 rpm, turning oil supply valves closes automatically. At speed more than 500 rpm AC JOP stops on auto. Hold the turbine at soaking speed 1080 ± 30 rpm for 30 min. for heat soaking. Check turbovisory readings are within limit HPT diff. Exp. + 4.5 to -3.0 LPT DE + 7.5 to - 2.0 LPT DE +18.5 to - 2.0 Check the following : (a) Turbine Bearing metal temp. <90°C (b) Lub. Oil temp. maintaining at 40°C (c ) HPT exhaust steam temp. < 480°C (d) LPT exhaust steam temp. < 90°C (e) Shaft vibration < 125 µM (f) Bring pedestal vibration < 62 µM (g) Steam purity < limiting value (h) HPT top bottom diff. temp. < 55°C (i) IBT top bottom diff. temp. <65°C (j) Check HPT casing, HPT rotor metal diff. temp. <30°C (k) IPT rotor metal diff. temp. < 30°C (l) MSV (L) casing metal diff. temp. <30°C Confirm the condition for turbine speed up as per the curve for turbine speed up. Set the EHG speed setter (65F) to 3000 RPM (rated). Speed rise rate will be 500 rpm/min. Don’t hold the turbine between 1110-2850 rpm. Turbine critical speeds are at 2439 rpm and 3700 rpm. In case of any abnormality such as vibration, brg. Temp. etc. crosses limit, decrease the speed to heat soak speed (1080 rpm). At rated speed (3000rpm) hold the turbine for 5 min. Close the MSV (L&R) warming drain valves and ICV(L&R) warming drain valves. At 2950 rpm AOP stops automatically. Control oil pr. > 8.5 kg/cm² . Charge DM water to generator H2 gas cooler and exciter air cooler. Check all the turbine parameters similar to the checking done after soaking (1080 RPM) speed. Now synchronize the turbo-generator with grid as per the synchronizing procedure. Keep the load at 10.5 MW (5%) for 55 min. observe M.S. pr. and temp. as 70 kg/cm² and 370°C . Close HP connection pipe (L&R), MS line & HPC drain valves. Refer to the start up diagram, confirm the condition for load increase and check the following limiting values.

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(a) Steam purity (b) Differential expansions (c) Shaft vibrations (d) Brg. Metal temp. (e) Lub. Oil Temp. at maintaining at 45°C (f) MSV (L) casing, HPT casing, HPT rotor and IPT rotor metal differential temp... 26) 27)

28)

29) 30) 31) 32)

Just after synchronization, EHG will change over from speed controller to power controller. To increase load, target load set point is given to power setter (65P) and load rate (65PD) set point is given manually. After keeping 55 min. at 10.5 MW load, further increase of load up to 27% (56MW) at a rate of 0.37% / min. (0.8MW/min.) can be done. After that load can be increased up to 100% at 0.91% / min. (2MW/ min.). Hence, at least 195 min. is required to increase load to 100% from synchronization. (SEE FIGURE FOR COLD START UP MODE ) For cold start up to synchronization form BLU – 205 min. From synchronization to full load - 195 min. Total = 400 min. At 42 MW load gradually take LPHS in to service and close drain valves for extraction lines. Whenever load is increased, MS pressure decreases if HPLP Pp is in auto; HPLP system closes to maintain the pressure. Otherwise, if on man mode HPBP valves are to be closed manually. But HPBP valves should not be closed below 2% before reaching 30% (63MW) load) to avoid MFR tripping through R.H. protection logic. At 42 MW load check all MAL drains auto closing. At 50MW load 6.6 KV auxiliary supplies are changed over from station to UAT. Increase load to 60MW and change deaerator pegging from TAS to CRH. Change over TAS from HC to LC. Increase load up to 84MW. LPBP closes automatically. At 84MW, put ALFC on auto (ALFC –auto load limiter follow up controller). So that load limiter can follow the current load on auto. 80-90 MW load but HPHS in service. Change deaerator pegging from CRH to 4th extraction (extraction from IPT exhaust). Gradually increase the load to 125MW (2MW/min). TURBINE WARM START UP

1) 2) 3) 4) 5) 6)

HP Turbine outer casing metal temp. at 50% is between 250 -410°C (32 hours after unit shut down). Condenser vacuum is achieved more than 670 mm of Hg. All the drain valves of MS lines, CRH, HRH, HPBP, LPBP including MAL drains are opened similar to cold start up. Put HP-LP bypass in operation and achieve M.S. parameters for metal matching of MSV, HPC, and IPS. Confirm the metal matching condition from metal matching curve for speed up. Observe the MS temp. and pr. as 70Kg/cm² and 410°C. Select TSE influence ‘ON’ speed fast and start turbine to rated speed at 500 rpm / min. After achieving 3000RPM check the turbovisory parameters etc. as per cold start up condition and synchronize the turbo generator with grid. Hold the turbine at 5% (10.5MW) load for 10 minutes. (SEE FIGURE FOR WARM START UP MODE)

After that load can be increased up to 24% (50MW) at rate of 1.9 % / min (4MW/min) and then increased up to 100% load at 0.95% / min. (2MW/min.). Hence at least 100 min. is required to achieve full load. 7)

LPHS, HPHS, UAT, TAS LC, deaerator pegging etc are taken in to service similar to cold start up.

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TURBINE HOT STARTS UP. HPT outer casing metal temp. at 50% depth is between 410 -460°C ( 8 hrs. after unit shut down). 1) Increase boiler firing to achieve M.S. temp. for metal matching of MSV, HPC, IPS as per metal matching curve. Check all the O.K. mark on start up page in CRT.M.S. temp. & pr. required as 435°C & 70 kg/cm². 2) All MAL drains are in open condition as per MAL drain chart. 3) Select EHG, hot mode, TSE – ON, speed rise fast and give command for rated speed (3000 rpm). Speed rise 500 rpm / min. 4) Synchronize and increase load up to 20% load (42MW) at 2.5%/ min (5MW/Min.), then up to 30% (63MW) at 0.87%/Min. (1.8MW/min) and then full load at 1.4% / min (3MW/Min.). Hence, at least 68 min. is required to achieve full load. 5) Put LPHs, HPHs, UAT, TASLC, deaerator pegging etc. similar to cold start up procedure TURBINE VERY HOT START UP HPC outer casing metal temp. At 50% more than 460°C 1) Steps up to synchronization similar to hot start up mode. M.S. Pr. & temp. 149 kg/cm² & temp. 537°C. 2) Machine load can be increased just after synchronization up to 100% load at a rate of 2.0% / min (4.2MW/min). Hence, at least 48 min. is required to achieve full load. 3) LPHS, HPHs, TASLC , UAT, deaerator pegging etc are charged similar to hot start up procedure . TURBINE NORMAL SHUT DOWN 1) 2) 3) 4) 5) 6) 7) 8) 9) 10) 11) 12) 13) 14) 15) 16) 17)

18) 19) 20) 21) 22)

Decrease load at 2% /min (4.2 MW/Min.). At 100-90 MW deaerator pegging change over from EX-4 to CRH. At 83-60MW LPBP control valves open on auto. At 60MW load deaerator pegging change over from CRH to TAS. Before this TAS HC to be put in to service. Change over auxiliaries bus (6.6 KV) from UAT to station. At 40MW take HPHs out of service. Check turbine master drain valve (MAL valves) in auto. At 20MW take LPHs out of service At 10.5MW(5%) turbine is tripped by operating TLR. Ensure S.V. and C.Vs are closed . Ensure voltage has come down to zero. Ensure turbines speed is decreasing, Note down the turbine coasting down time. Check whether MAL drains have operated according to the drain chart. Check AOP starts at 2850 RPM. Check JOP auto starts at 400 RPM Turning gear oil valve opens at 300 RPM and turning is established at around 150 to 200 RPM. Close HPBP manually Close LPBP after reducing HRH pr. to zero. Isolate H2 coolers and excite air coolers. In case of vacuum breaking (a) Withdraw main ejector (b) Vacuum breaker is opened. (c) Gland sealing steam CV closed at 140 mm of Hg. TAS out of service Boiler outlet valve close Gland steam condenser exhaust fan stop. Open M.S. lines drain valves. During coasting down check the turbovisory parameters such as vibration, D.E. Brg. Metal temp., lub. Oil temp etc. TURBINE STRESS INFLUENCE :

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The turbine stress controller generates a hold function i.e. it does not allow turbine to increase a decrease load or speed if metal matching conditions are not satisfied. This prevents the turbine from excessive stress during load change or speed change. The turbine stress controller calculates the temp. margin from the midwall temp. and surface temp, of main stop valves (MSV), HPC, HP shaft and IP shaft and if these margin falls below 15°C if generates a trigger to the EHG and consequently EHG blocks any increase or decrease of load during such conditions. Here it must be noted that this ‘HOLD’ function is generated only if turbine stress controller is made ‘ON’.

It is obvious that during load increase, dt will be positive and during load decrease dt will be negative. If we plot a curve between tm & dt, then the instantaneous point can be defined on it. The point must be within allowable limit defined in the curve. Say for tm being same as that for the current point, the max. allowable dt for positive side is dtu and for negative side is dtl. Then upper temp. margin a dtu –dti and lower temp. margin =dti … dtl which should not fall below 15°C . TURBINE INTERLOCKS AND PROTECTIONS : 1) 2) 3) 4) 5) 6) 7) 8) 9) 10) 11) 12) 13) 14) 15) 16) 17) 18) 19) 20) 21) 22) 23)

AOP auto starts at 2280 RPM and pr.< 5.1 ksc. AOP auto stops at 2850 RPM and pr. > 8.0 kg/cm² AC EOP auto starts at 1.1 kg /cm² AC EOP auto starts at 1.1 kg /cm² with time delay AC JOP auto starts at 400 RPM Similar for DC JOP AC JOP auto stops at 500 RPM Turning oil stop valve auto open at 300 RPM Turning oil stop v/v auto close at 400 RPM MOT oil capacity -20m³, type of oil ISOVG32 Turbine over speed 3330 RPM (Mech.) 3360 RPM (Elect.) (Trip) Cond. Vac very low - 542 mm of Hg(T) - 608 mm (A) Control oil pr. low < 5.0 k Sc. (A), < 2.0 Ksc (T) Lub. Oil pr. low < 1.0 Ksc (A), trip 0.3KSc(T) Shaft vibration high 125 µM (A) , trip 250 (T) LPT exhaust temp. high 90°C (A), 117°C (T/S),115°C(G/S) trip. M.S. temp. high - 545°C (A), 565°C (T), M.S. temp. low - 440°C (A), 430.8°C (T) Turbine I/L pr. low - 63.5 KSC (A), 60 KSC (T) , when Turbine load > 40% HPT diff. Exp. + 4.75 - 3.02 (A) + 5.69 - 3.96 (T) IPT DE + 7.6 - 2.0 (A) + 8.4 - 2.9 (T) LPT DE + 18.5 - 3.0 (A) + 19.2 - 3.8 (T) Axial Thrust + 0.51 - 0.53 (A) + 0.98 - 1.03 (T) Tur electricity high> 76 µM (A) Very high> 200 µM (T)

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48 ROUTINE CHECK UP OF TURBINE AND EMERGENCY OPERATION. The following routine check-up should be done (for turbine area) from time to time at CRT and at least once local checking must be done in a shift. TURBINE LUB OIL AREA: At CRT checking’s I. MOP disch pr ii. Turbine lub oil pr iii. Control oil pr

Normal value 9.0 Kg/cm²(i.e ksc 2.8 ksc 8.5 ksc

Alarm value 1.1 ksc(low alarm) 2.0 ksc (low alarm)

Trip value 0.8ksc(V.Lo-Tur Trip) 2.0ksc(V.lo-tur trip

Check Secondary oil pr at HPCVs and IPCVs. Check AC AOP, AC EOP, DC EOP, AC JOP, DC JOP, Turning oil supply V/V, MOT Vapour extractor (stand-by), turbine drain v/v Master are in AUTO mode. Lub oil temp before & after cooler 62ºC/45ºC & 55ºC (Hi at cooler O/L) iv) Lub oil temp control v/v position. v) Brg drain oil temp 65ºC 75ºC (High) vi) Brg metal temp : brg-1:100ºC (high) 120ºC(v.hi- Tur trip manually) brg-2: 90ºC ,, --- do--brg-3,4 : 105ºC ,, ----do--At LOCAL checkings-

1. Look for any leakage of oil, air, steam, water etc and hear for any abnormal sound and also check approach, cleanliness of equipments. 2. Check lock out switches of AC AOP, AC EOP, AC JOP, Turning oil supply v/v, stand-by equipments, drain v/vs are in released condition. All available equipments must be in lined-up 3. Condition. 4. check turbine lub oil local pr gauge ,DP across lub oil filter (normal value below0.5ksc& high at 0.9ksc) 5. check MOT level(Normal: 0.0cm,high/low value :+7.5cm/-7.5cm),MOT oil temp,MOP disch pr,tur lub oil temp &cooling water temp before /after tur lub oil cooler,cooling wtr control v/v position,stand-by cooler status(whether back charged or not etc ) 6. Check all brg drain oil temp gauges. 7. DP across control oil filter (Normal: 0.2ksc,high:1.0ksc). 8. both JOPs are lined –up from MOT & tur lub oil disch hdr,DP across jacking oil filter (normal: 0.2ksc, high:0.5ksc) TURBO-VISORY PARAMETERS: At CRT checkingsSl.No. 1. 2. 3. 4. 5.

Description Axial Shift Differential expansion of HPT Differential expansion of IPT Differential expansion of LPT Diff temp bet top& bottom of HPT

Normal value

High value

V. High & (Trip) value

-0.30mm -1.1mm

⍨0.5mm(high) +4.5mm/-3.0 mm

⍨1.0mm(tur-trip) +5.5mm/-4.0mm

+3.7 mm

+7.5 mm/ -2.0mm

+8.5 mm / - 3.0 mm

+11.0 mm

+18.5 mm / -2.0 mm

+19.5 mm / -3.0mm

55ºc(high)

70ºc (trip- manual)

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Diff temp bet top& bottom of IPT Diff temp bet top& bottom of LPT Brg. Pedestal Vib. Shaft vibration

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65ºc (high)

80ºc (trip- manual

62 microns 125 microns

125 microns. 250 microns

viii) check HPT,IPT,LPT I/L & O/L steam parameters, condenser vacuum, LP turbine exhaust hood temp, HP Casing temp, HP Rotor metal temp, casing inner(50% & 100%) temp, and same parameters for IP Turbine. ix) Check upper and lower temp margins of MSV, HP Casing, HP Rotor, IP Rotor, casing expansion. x) Check LP Turbine exhaust hood temp control spray v/v is in AUTO. At LOCAL Checking: i) Check all local temp, pr gauges and other meters. Check for any type of leakage. ii) Check local condenser vacuum gauges. iii) Check the position of isolation v/v (before & after) of LPT exhaust hood temp controller. TURBINE GOVERNING SYSTEM At CRT Checking: i) Check mode of operation (i.e. CMC, Turbine Follow, Boiler Follow, Manual mode) ii) IF M/C on CMC mode check load set-point, actual load, maximum /minimum load set point, effect of frequency influence, MS pr set point and actual MS pr, coal flow, load rate set point. iii) Check TSC is ON and ALFC is ON. iv) Check MSVs and RSVs opening feed-back are persisting. v) Check position of MCVs, ICVs, position reference, 77M, 65M, 77E. At LOCAL Checking: i) Check for any leakage etc. ii) Check control oil pr, secondary oil pr, aux. sec oil pr, trip oil pr, primary oil pr (in terms of rpm) iii) Check sec. Oil pr and aux. sec oil pr at MCVs and ICVs. iv) Check all pr gauges at MSVs & RSVs are showing trip oil pr. All pr and temp gauges at different areas are showing correct values. GLAND STEAM SUPPLY SYSTEM: At CRT Checking: i) Check gland steam pr set point and actual pr, gland steam temp, gland steam supply v/v and exhaust v/v position. ii) Check the v/v position of AS-9, CRH-7, and CRH-105. iii) Check gland steam exhauster status and that of stand-by gland steam exhauster. At LOCAL Checking; i) Check locally gland steam supply v/v and exhaust v/v position. ii) Check lock out switch of stand-by gland steam exhauster in released condition with duly lined up. iii) Check vacuum created by gland steam exhauster on compound gauge mounted on gland steam condenser. GENERATOR SEAL OIL & COOLING SYSTEM: At CRT Checking: i) Check hydrogen pr, purity at generator casing. ii) Check seal oil pr at turbine end and exciter end, vacuum at vacuum tank. iii) Check stand-by AC Seal Oil P/P, DC Seal Oil P/P, vacuum p/p are in auto mode. iv) check cold gas temp set point & actual temp, check hot gas temp, cold & hot air temp of exciter, cold gas temp control position, cooling water I/L & O/L temp.

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At LOCAL checking: i) Check for any leakage. ii) Check stand-by seal oil p/p , vacuum at vacuum tank, vacuum tank level, IOT level, seal oil temp before and after seal oil cooler, seal oil pr and flow at turbine end / exciter end, hydrogen gas pr. iii) Check hydrogen cooler I /L, O/L water pr/temp, position of cold gas temp control v/v. HP-BP & LP-BP AND OIL SUPPLY UNIT: At CRT checking: i) Check HP Bypass pr set point, actual pr, temp set point, BP-1, BP-2, BPE-1, BPE-2 and BD Valve position. ii) Check BP-3, BP-4 and HP Bypass drain v/vs are in closed condition. iii) Check HP Bypass oil supply unit p/ps status; ensure both oil p/ps are getting started alternately. iv) Check LP Bypass stop v/vs, control v/vs position, open feed-back & AUTO position, spray v/vs are on AUTO. At LOCAL checkings : i. ii. iii. iv. v.

Check locally BP-3, BP-4 & drain v/vs lock out switches are in released condition, BD v/v isolation in open condition. Check oil supply p/ps LOS position, both oil tank oil level, p/p disch pr, supply manifold pr, auto cut in & auto cut out of both p/p. Check all filters/strainers are O.K.(whether chocked ) Check oil level of LP BP oil tank, p/p selection, p/p disch pr, filter p/p status, cooling fan status auto cut in & cut out of selected p/p ,p/p disch pr supply manifold pr. Check attemperation lines lined-up.

TURBINE EXTRACTION CYCLE: At CRT checkings: i. Check all extraction steam pr and temp parameters. Check allforce closing NRVs (FCNRV) are in open condition and OPEN feed-back is coming at CRT. ii. Check condensate/feed water pr and temp rise in each heater. iii. Check drip level set point and actual level ; position of controller to cascading, condenser and deaerator as the case may be. At LOCAL checking : i. Check locally all extraction steam pr and temp. ii. Check position of each drip controller and check their isolation v/v status. iii. Check for any leakage, hammering sound etc. iv. Check vent v/v to deaerator of running HP heaters are in open condition at both end. v. Check lock out switches of condensate/feed water I/L, O/L & by-pass v/vs are in released condition and check all drain v/vs of running heaters are in closed condition. TURBINE AUXILIARIES STEAM AND OTHER CYCLE : At CRT checking : i. Check TAS pressure set point, temperature set point and their actual values. ii. Check position of controllers (of High consumption / Low consumption hdr) of steam and attemperation. iii. Check condensate cycle, feed cycle parameters, parameters of running BFPs, CEPs and line up of stand-by equipments. At LOCAL checking: i. Check all isolation v/vs of TAS header (HC/LC) are in open condition (if available). ii. Check for any leakage, hammering sound. Also check the drain v/vs are in closed condition. iii. Check all local parameters of condensate cycle, feed cycle, for running BFPs, CEPs are normal and stand-by equipments are in lined up condition.

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PLANNED SHUT DOWN OF UNIT 1. Unit is running with 210 MW load in CMC mode with 4 nos. coal mills (say, Mill- B, C, D, E) are in service with all the feeders are in AUTO mode. Two nos ID Fans, Two nos FD Fans, Two nos BFPs, Two nos CEPs, Two nos CW P/Ps and One no ACW P/P are in running with combustion control , feed control (three element ), are in AUTO mode . All the boiler and Turbine parameters are normal and well within limits. 2. Take clearance from Shift Charge Engineer regarding Unit shut down and ask GCR to inform CLD that unit is going shut down. Check AC AOP, AC EOP, DC EOP, Turning Oil supply v/v ,AC JOP, DC JOP, Turbine drain v/v master are in AUTO mode and in lined up condition. 3. Reduce the M/C load up to 160 MW in some steps at the rate of 2.96 MW per Min. Control oxygen percentage at air heater O/L and gradually reduce main Steam pr set point. Check from time to time al Boiler parameters and Turbine, turbovisory parameters. Avoid any sharp fall in pr and temp. Now select bottom most Mill, which have ignition permit from other running Mill, for cutting out from service (bottom mill is selected to avoid temp falling problem at Bk.T.P.P.). Turn the feeder of the selected Mill to MAN mode and reduce the feeding to 9TPH. Before stopping the feeder confirm the feeding of adjacent running Mill is above or equal to 22TPH,if not then bring it to 22TPH.Stop the feeder, when feeder become empty, stop Mill, PA Fan, and Seal Air Fan , close hot air gate. 4. Again reduce M/C load to 120 MW in CMC mode. Turn operating mode to Turbine Follow Mode from CMC mode. Select another bottom Mill for cutting out from service. Reduce its feeding to 9TPH.Took corresponding oil burners (at least 3 out of 4 burners are to be come into service). Stop feeder, Mill, PA Fan, SA Fan as usual. 5. Bring M/C load to 90 MW by reducing coal feeding and oil pr of oil burners in service. Charge pegging steam from cold reheats line. Convert operating mode to MANUAL mode from TFM. Stop one BFP, one set ID Fan FD Fan, one CW P/P . 6. Bring M/C load to 60 MW to 70 MW, open HP-LP By-pass as per requirement. Charge pegging steam from TAS Header. Cut out HP Heaters from service. Stop another Mill from service after putting corresponding oil burners in service. Change Drum level control to single element from three element control. 7. Bring M/C load to 30 MW to 40 MW .Cut out LP Heaters from service. Change over UAT to Reserve source (here Station Transformer #2, #3). 8. Bring M/C load to 10.5MWand stop the last Mill with oil support; reduce firing rate and close HP bypass as per requirement. 9. Trip the Turbine by pressing emergency push button (TLR). After tripping Turbine, HP Bypass will to 100%, close HP Bypass to former position (position just before tripping).Control Drum level in Man mode if required. 10. Reduce firing rate to minimum oil pr. Stop upper two elevation oil burners, Trip MFR by pressing emergency push button (two nos- MFR).Close MS valves at Boiler end. Close HP Bypass V/V fully before closing LP Bypass, then after some time close LP Bypass. Close steam supply v/v to ejector and open vacuum breaker. When vacuum reaches to 140 mm Hg, close gland steam valve and stop gland steam exhauster after 5 min. 11. Flood the Boiler drum before stopping BFP, stop ID Fan/FD Fan. 12. On the other side Turbine speed is decreasing, AC AOP will take start as Turbine speed is decreasing to 2200 rpm (when control oil pr become 5.0 ksc). AC JOP will cut in at 400 rpm, Turning oil supply v/v will open at 300 rpm and Turbine will be on turning. Turning operation is to be continued until HP casing temp falls to 150 deg C. 13. Hot draining of boiler is to be done at Boiler drum pr 5 ksc. Keep one CEP and one CW P/P on running condition (CEP on recirculation) until LP exhaust hood temp reaches to 500C. UNIT SHUT DOWN THROUGH ATRS / ASD Automatic Turbine shut down (ASD) can be put into service when M/C load is less than or equal to 20% i.e. 42 MW. 1. Before putting ASD in service ,check Turbine Drain v/v master is in AUTO, AC AOP , AC EOP , DC EOP , AC JOP , DC JOP ,Turning Oil supply v/v are in AUTO mode. All extraction stop valves

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are in closed condition and there is no extraction steam flow. All Turbo-visory parameters are in normal condition. 2. Select ASD mode i.e. AUTO mode, Semi-auto mode, Operators guide mode (for ASD auto mode and semi-auto mode are same) from CRT or Back-up panel. 3. Put ‘ASD ON’ push button and ‘ASD ON ' lamp will glow. For ASD steps 51 to steps 55 will occur: STEP-51: (Total time required 5 sec) * ASD command will be started. * EHG power unload rate will be set at 2% i.e. 4.2 MW per min. STEP-52: (Total time required 3600 sec) * Load willbe reduced to 5 % i.e. 10, 5 MW. * Power setter (65 P) will be fixed at 5%. STEP-53: (Total time required 15 sec) * Command to Generator Circuit Breaker ‘OPEN’ will go. * Check feed-back of Generator Circuit Breaker OPEN and Generator Field Breaker OPEN come. STEP_54: (Total time 15 sec) * Command for TUrbine Trip will generate. * Check Turbine tripped and closing command for MSVs & RSVs will generate. Check the same. * AC AOP will start on reduction of Turbine speed. * AC JOP will start at 400 rpm. * Command for opening Turning oil supply v/v at 300 rpm will go. Check all this. STEP-55: * 'ASD END ' signal will come & 'ASD END' lamp will glow. * Press 'ASD OFF’. Now 'ASD END" lamp gets off and ‘ASD OFF ' lamp will glow.

EMERGENCY OPERATIONS A) Total Power Failure: The following prompt actions are to be taken during total power failure i.e. at blackout: 1. Check Turbine has tripped and its speed is decreasing. DC Seal Oil Pump took start on AUTO, if not taken start on auto then starts it MANUALLY. On speed reduction (at about 2200 rpm) DC EOP will take start. Confirm that Vacuum Breaker has opened; if not then open it manually. 2. Close isolation valve before gland steam supply control v/v. Isolate TAS. Close MS-1 & MS-2 at Boiler end manually if not closed by DC power. 3. Give ' OFF ' command to all running equipments, close oil v/v of all running burners. 4. Took all control valves to MAN mode from AUTO. 5. Start Diesel Generator set in the mean time, restore power of emergency bus. Start AC AOP, AC Seal Oil P/P and stop DC EOP, DC Seal Oil P/P. Start AC JOP and stop DC JOP (if turbine speed has fallen below 400rpm then DC JOP will come into service). On further reduction of speed turning oil supply v/v will open, otherwise open it manually, Turbine will be in turning. Close all extraction v/vs. Start lub oil p/ps of Mills, ID fans, FD Fans, PA Fans, BFPs. 6. If it was not possible to restore power from DG set and in the mean time auxiliary power is not restored, then turbine is to be rotated by HAND BARRING operation at small intervals. (During this time both DC EOP and DC JOP must be in service) 7. After restoration of auxiliary power and normalization of Bus, start one ACW P/P, one CW P/P. Then start air compressors and DMCW (Turbine), DMCW (Boiler), and then start one CEP on recirculation. Start CT Fans one by one as per requirement. 8. Start one set ID / FD Fan and one BFP. Start Furnace purge. Bring the Drum level to light-up level. 9. After getting clearance, lit-up Boiler and follow normal start up procedures. B) TURNING GEAR IS NOT ENGAGING AFTER DEAD STOP OF TURBINE Possible Cause: The rotor has taken Bow shaped due to temperature difference between upper and lower part. Remedy/Action: Do not try to rotate the turbine by force. Wait until the temp distribution becomes uniform. When temp falls, then rotor will come back to its original position. Then start barring gear.

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C) SPEED DROPS DURING TURNING OPERATION Possible Cause: 1. Inadequate lubrication. 2. Shaft rubbing on seal rings. 3. Shaft rubbing at blade seals and shaft seals due to temp difference in the casing. 4. Failure in turning oil supply v/v or failure in AC AOP or AC JOP. Remedy/Action: 1. Check Turning oil v/v, AC AOP, AC JOP, turning oil pr, jacking oil pr at each brg. Check Seal Oil system also. If at any place any abnormality noticed, rectify it. 2. Clearance at sealing rings will increase during operation (For the m/cs coming from overhauling). 3. If this is happening due to temp differential, then don’t rotate by force; wait until temp differential comes to normal. D) HIGH POSITIVE TURBINE DIFFERENTIAL EXPANSION Possible Cause: • Inlet steam temp too high. • High pressure deviation from normal value. • M/C started too fast. • M/c kept in 3000 rpm for long time with synchronization. • Flow and volume of steam is insufficient for heat transfer in outer casing. • Gland steam temp High. Remedy/Action: • Try to maintain steam pr and temp within limit. • Soaking time is to be allowed if required. • Try to synchronise m/c after achieving 3000 rpm as fast as possible if there is no technical problem. • Reduce vacuum in case it happens at LP Turbine. E) HIGH NEGATIVE TURBINE DIFFERENTIAL EXPANSION Possible Causes : • During hot start-up , rolling or loading Turbine too slowly. • Boiler steam temp lower than Turbine metal temp. • Low condenser vacuum. • Remedy / Action : i) Increase condenser vacuum. • ii) Increase Boiler steam temp and load Turbine at faster rate. F) AXIAL SHIFT HIGH Possible Causes : • Abrupt change in load. • Sudden drop in steam temperature. • Sudden drop in condenser vacuum. • Sudden closure of HP Heaters. • Too fast pick up load. • Too high flow in Reheater. • Salting on Turbine blade. • Viii) Lub oil failure to thrust bearing. Remedy / action : • Avoid any sudden change in parameters. • Control condenser vacuum. • Check return oil from thrust brg pads through inspection glass for adequate quamtity, colour and temp. • Cut out reheater spray if exhisting, to balance reheater flow. • Reduce load to reduce axial shift within limit.

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G) TURBINE VIBRATION HIGH Possible Causes : • Sudden change in steam parameters. • Sudden change in load, speed. • Gland steam temp low. • Temp difference between Top and Bottom cylinder exceed permissible limits. • High Turbine differential expansion. • High axial shift. • Low condenser vacuum, high exhaust hood temp. • Rotor eccentricity high. • Lub oil temp / pr too high or too low. Remedy / Action : • Turbine vibration readings are to be crosschecked by other instruments and also by feelings. • Listen for any sound at any Turbine bearings. • Check gland steam temp. • Check lub oil temp at Turbine inlet, drain oil temp, lub oil pr at brg. • During start up soak Turbine if required. • Try to maintain axial shift, differential expansion, and condenser vacuum, exhaust hood temp, eccentricity within limits. • Try to maintain Boiler and Turbine steam parameters as per recommended value. • Reduce m/c load to suit. H) HIGH DIFFERENTIAL TEMP BETWEEN TOP AND BOTTOM CYLINDER OF HPT/IPT Possible Causes: • Non-uniform heat dissipation due to improper insulation. • Non-uniform admission of heat due to leaky MS connection at seal rings. • Absolute temp in bottom half portion is higher due to leaky drain fitting. Remedy / Action: • Try to maintain load to suit. • Operate drain v/v on MAN mode if required. I) LP TURBINE EXHAUST HOOD TEMP HIGH Possible Causes: o Fall in condenser vacuum. o CW Pump failure. o High steam parameters during start-up. o High load steam dump to condenser at low vacuum or steam dump at high temp. o Running at 3000 rpm without synchronizing Generator or running at low load for long period. Remedy / Action: • Increase CW flows if found low. • Try to increase vacuum. • HP drains connected to condenser (if any) is to be reduced. • Reduce steam dumping to condenser. • Synchronise Generator as quick as possible. • Check gland steam parameters and regulate to recommended value. • Charge LP heaters as quick as possible. • If all the measures are not successful , trip the Turbine, break vacuum, cool down the exhaust hood temp. J) FALL IN CONDENSER VACUUM Possible Causes : o Reduced gland steam pressure. o Failure of ejectors due to high level at condenser. o Failure of CW Pump.

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o Drains of vacuum system opened to atmosphere. o Ejectors supply steam pr low due to failure of TAS. o Leakage / ingress of air into vacuum system from loose flanges , instrument tapping points. o Failure of GSC, Main Ejector syphon to condenser. o Opening of vacuum breaker. Remedy / Action : o Check ejector GSC performance. o Maintain correct steam pr and temp at TAS header. o Check and maintain gland steam parameters. o Check CW flow. o Reduce hot well level if it becomes high. o vi) Check vacuum breaker. o Check drains/tapping points/flanges of vacuum connected lines for air ingress. o Reduce m/c load to increase condenser vacuum. K) BOTH CW PUMP FAILS AND STAND-BY PUMP NOT-AVAILABLE Possible Causes : o Low CW sump level. o Supply failure to CW Pump due BUS failure. o Failure of thrust brg cooling water supply. o Disch v/v of CW Pump gets closed o Instrumentation failure. Remedy / Action : o Immediately try to restarting CW Pump and establish cw flow. o If it was not possible to start CW Pump trip the MFR immediately. o Even after tripping of Unit, start at least one CW Pump immediately to control exhaust hood temp. L) ONE RUNNING CW PUMP TRIPS AND STAND-BY PUMP NOT TAKING START Possible Causes: o Motor trips due to motor protection relay operated. o Thrust brg temp becomes high. o Motor brg temp becomes high. o Instrumentation failure. o Pump disch v/v gets closed. Remedy / Action : o If m/c is on CMC mode load set point will be automatically reduced to 125 MW. Manually trip 4th Mill group immediately, keep close watch on Drum Level and other steam parameters, if required take drum level control on Manual mode. o If m/c is on Turbine Follow Mode, then reduce the m/c load immediately by tripping 4th Mill to safe limit. o Immediately start reserve CW Pump or tripped CW pump if the fault is not so major. M) HOT WELL LEVEL LOW Possible Causes : o Over-feeding to deaerator. o Inadequate hotwell make up. o Excessive dumping to CST. Remedy / Action : o Maximise hotwell level make-up by opening make line bypass v/v. If yet not possible to build up level , then start CTP immediately otherwise hotwell level may become very low resulting in CEPs trip. o Reduce deaerator flow. o If atmospheric drains on MS line, Boiler or CBD v/v are in open condition, reduce their opening or if required close them.

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o Check dumping line to CST and isolate them. o Check drains lines on feed waterline, deaerator are in open condition, close them. N) HOTWELL LEVEL HIGH Possible Causes : i) Too high make-up. ii) Less flow to deaerator. iii) Make-up line by-pass v/v in open condition. iv) Make-up v/v in open condition and goes to man mode v) Deaerator level high and over-flow line opened. Remedy /Action : i) Increase flow to deaerator. ii) Close make-up line by-pass v/v if it is in open condition. iii) If deaerator level is high , open drain v/v . iv) Reduce make-up. v) Watch out for water suction of ejector. (If hotwell level becomes very high, then chances of blocking of air off-take line of ejector causing fall in condenser vacuum) O) BOTH BFP TRIP AND STAND-BY PYMP NOT TAKING START Possible Causes: I) Deaerator level very low. ii) Failure of DMCW cooling water pumps. iii) Power failure of BUS. Remedy /Action: I) Unit will trip due to drum level very low. ii) Check the causes of tripping and rectify. P) ONE RUNNING BFP TRIPS BUT STAND-BY PUMP NOT TAKES START Possible Causes : i) Power failure to respective BUS. ii) Pump trips due to working oil temp high, lub oil pr low, suction v/v gets closed. iii) Instrumentation failure. Remedy / Action :i) If m/c is on CMC then unit load set point will automatically reduced to 125MW and excess of 3rd Mill will be tripped. ii) If m/c on TFM , then reduce m/c load to safe limit. If 4th Mill not tripped in auto trip it quickly. Control drums level in Man mode if required. Keep close watch on Boiler & Turbine parameters. iii) Start the reserve p/p or tripped p/p if the fault is not so major. Q) BOTH CEP TRIPS AND STAND-BY CEP NOT TAKE START Possible Causes : i) Hot well level very low ii) CEP disch header per very low. iii) Failure of DMCW cooling water pump. iv) Power failure. v) Instrumentation failure. Remedy / Action : i) Start CTP immediately to build up hotwell level if CEP tripped due to hotwell level low. ii) Reduce m/c load quickly to as low as possible. iii) Keep close watch on Deaerator level. iv) Start at least one CEP as quick as possible. v) Keep close watch on TAS.

49 CONDENSER 1. INTRODUCTION : The closed vessel in which steam is condensed by abstraction of heat and in which vacuum is maintained is called Condenser. Condensation of steam enables expansion of steam to a lower back pressure. The available enthalpy drop increases. Consequently more work is done and the plant efficiency improves. In our plant Surface type condenser is used to condense the exhausted steam from L.P. Cylinder and to produce vacuum in order to increase the heat drop and the turbine output beside making it possible to reuse condensate thus obtained. Optimum utilization of steam space by providing rectangular cross-section of tube nest is an added feature of this condenser. For ensuring equitable loading of condenser tubes without incurring appreciable steam side pressure drop, tubes have been segregated in small bunches leaving wide lanes between

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them. Tube bundle has been kept ½0 inclined towards front water box side for self draining during CW pump tripping. The condenser has provision for isolation of half of the condenser for no-load leak detection. 2. CONSTRUCTIONAL FEATURES OF CONDENSER : It is rectangular surface condenser having stiffened steam dome, consisting of stiffening rods, welded on either side with the opposite side wall of dome shell. Except tubes, the remaining construction is of fabricated type. The tubes have been expanded into main tube plates and are supported by the tube plates at intermittent points to prevent their sagging and to curb the flow induced vibrations. Non-condensable gasses are continuously extracted in order to maintain vacuum in the condenser. Water boxes incorporate hinge arrangement to facilitate the removal of covers for enabling retubing and cleaning of tubes etc. Water box inside surfaces and circulating water side of water chambers including tube plates have been protected against corrosion by the application of protective coating of epoxy paints. Two numbers Steam Throw Device (STD) have been provided in condenser for dumping steam during start-up and sudden load throw off. Fittings : Fittings provided on the condenser are as follows:• Level indicators for Hotwell. • Level switches with isolation valves. • Two numbers stand pipes with provision for isolation and draining. • Vent and drain valves for water boxes. 3. TECHNICAL DATA :

4. INSTALLATION : Condenser has been floated over the springs, which take empty weight of condenser while operating weight is taken by the turbine foundation. Tube installation is tested by filling water into the condenser steam space up to one metre above the top tube row. Prior to filling water for above testing, screws provided with spring support should be used for ensuring that water weight is being passed on to them., to avoid over stressing of turbine foundation. Prior to putting the system back into operation, condenser should again be floated over springs to avoid excessive upward thrust being passed on to the turbine foundation. 5. SOME IMPORTANT INSTRUCTION : • While isolating one part of condenser on CW side close the isolating valve provided in the pipe line connecting condenser with air evacuating equipment. During above operation turbine load should be reduced to 50 to 60%. • Locate and plug the leaking tube by observing higher conductivity of condensate. Use copper for plugging tube ends. • Attend / Replace the instruments and fitting found not functioning properly. • Attend to the cause if excessive rise in CW temperature is noticed. • Attend to the cause if appreciable variation in CW side pressure drop across condenser tube system is noticed.

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Investigate the reason for condenser vacuum not commensurate with turbine loading, CW inlet temperature, site barometric pressure etc. and attend to the possible causes. The best possible obtainable condenser vacuum at particular CW inlet temperature is the difference of barometric pressure minus condenser back pressure at that particular CW inlet temperature. The condenser back pressure is the pressure corresponding to saturation temperature obtained by adding 3 to 40C for terminal temperature difference to the condenser CW outlet temperature. Excessive air leakage (more than 20-30 kg/hr) into vacuum system which includes condenser, lowest LP heater, drain cooler, LP flash tank, inter connecting steam/drain side piping, fittings etc. cause deterioration in condenser vacuum. To ensure that air leakage is not excessive, conduct vacuum drop test by shutting off ejector and noting down the vacuum drop test. An acceptable vacuum system shall have the vacuum drop rate within 1 to 2 mm/min. CW side should be charged only after ensuring priming of CW system. Periodically check the vacuum system tightness.

6. TUBE LEAKAGE DETECTION : A. When Turbine Is In Operation : Condenser has been provided with the divided water chambers thus making it possible to locate the leaking tube and plug its ends, even when turbine is in operation For locating the leaked tube, concerned portion of water chambers should be isolated on CW side and tube plate should be dried commencing from top to bottom by the application of dry air. For attending above job individual can enter into the water box through the water box cover man-hole opening. • •Tube opening should be covered with a thin polythene sheet, which will get sucked into the failed tube end, alternatively tube ends should be scanned through with a lighted candle tick/smoke generator. The flame/smoke will get attracted in the leaky tube end. • Leaky tube can also be detected by the use of U-tube manometer. Plug one end of the tube with soft rubber plug and connect the other end of the tube with U-tube manometer having colored water. Colored water will get sucked into the tube in case of leaky tube, otherwise water level will remain unchanged. B. When Turbine Is Under Shut Down : Drain the water boxes and fill condenser steam space with DM water only up to 10 M from bottom plate. Prior to DM water filling in steam space, condenser should be supported as described in Article No.4. 7. INITIAL CHARGING PROCEDURE OF CONDENSER CW SIDE : Before charging of condenser the followings should be checked :• Condenser is floated over springs. • At least one CEP is running on recirculation. • Only ACW pump is running. • CW inlet valves (CW13 & CW14) and CW outlet valves (CW15 & CW16) are closed. • Condenser Water Box drain valves are closed and Water Box Vent valves are fully OPENED condition. • CW/ACW Cooling Tower inlet valves are Opened position. After confirming the above conditions, Back Charge the condenser water box side by slowly crack opening of CW outlet valves CW15 & CW16. Trapped air from water box will come out from W/B vents. When sufficient water is coming out from these vents, it is confirmed that condenser W/B is fully charged. After that fully open the CW15 & CW16 and close the W/B vent valves.Then run one CW pump as per operating procedure of CW pump. After sufficient CW discharge header pressure is developed, open the CW inlet valves of condenser (CW13 & CW14). After that check the water is flowing through Cooling Tower cells. 8. CONDENSER HOTWELL LEVEL CONTROL SYSTEM : The steam from LP turbine exhaust is condensed in the condenser and this condensate is collected in the Hotwell. Condenser hotwell level is an important parameter during operation of the plant. This level is to be maintained as a controlled manner for the safe operation of LP turbine and CEP. Two electronic level transmitters (MAG11CL101 & MAG12CL101) in “1 out of 2” logic is used for hotwell level control. Normal level in hotwell is maintained by hotwell level controller (CD19) which is positioned in

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the main condensate line in between GSC & Drain Cooler. As the hotwell level rises above the normal set point, the hotwell level controller (CD19) opens (if it is on “Auto”) to increase the flow rate from the hotwell and maintains the constant level in the hotwell. If the hotwell level decreases from the normal set point, the reverse action will take place. Motorized regulating valve (CD21) is provided in bypass line of CD19 which can be put into operation remote manually during malfunction of hotwell level controller (CD19). For initiating alarms, protective action and controls, the following have been provided on the condenser hotwell :• Normal level : One level switch for CEP start permissive. • Low level : One level switch for alarm. • Very low level : Three level switches have been provided in “2 out of 3” logic for annunciation and CEP trip interlock. • High level : One level switch for alarm. 9. CONDENSER ON LOAD TUBE CLEANING (COLTC) SYSTEM : 9.1. INTRODUCTION : Condenser plays a key role in the process of power generation. A lower back pressure of the turbine results in a higher generation of power and this largely depends on the performance of the condenser. It is essential to maintain the heat transfer rate and co-efficient close to the designed parameters for an improved steam condensation. Hence the cleanliness of the condenser tubes should be kept as high as possible to the design condition values in order to increase the condenser efficiency which will result in an optimum power generation. On Load Tube Cleaning of the condenser by using sponge rubber balls has been in use all over the world, for more than a decade now. This system is found to be an effective solution for maintaining the cleanliness factor at the optimum level. Sponge rubber balls with a special composition and size 1 to 3 mm greater than the inner diameter of the condenser tubes are injected into the cooling water stream at the inlet. These balls which have a specific gravity same as that of the cooling water are carried into the condenser by the velocity of the inlet cooling water. Cleaning balls are then pushed through the tubes by the differential pressure existing across the condenser. While passing through the condenser tubes, the balls are pressed against the walls of the tubes removing all deposits on the inner surface of the tubes. Specially designed screen arrangement called the Ball Separator, separates the balls going out of the main cooling water system and the balls are collected in the all Vessel through the Ball Transport Pipes. The balls are injected again into the cooling water through the Ball Recirculation Pump. The Ball Separator is specially designed to facilitate the smooth passage of the Cleaning Balls to the extraction point. The unique design of the Ball Separator ensures that the cleaning balls will have to move through only a small angle, since larger angles may result in the balls sticking to the screen in case of adverse conditions. The differential pressure across the Ball Separator Screens is constantly monitored by a differential pressure measuring system, wherein the measured value is sensed by a differential ressure transmitter. The differential pressure is displayed on the indicating controller mounted on the control panel. This is backed up by a differential pressure switch. The Ball Recirculation Pump is a non-clog type centrifugal pump capable of handling soft solids under suitable pressure and injects the sponge rubber balls into the cooling water. The Ball Vessel is specially designed with no moving parts and hence it is maintenance free. The Ball Vessel is used for charging the cleaning balls and recovering the same. V-piece with a sight glass enables monitoring of the circulation of cleaning balls. injection pipe facilitates transportation and even distribution of the balls in the branches at the injection points. Ball Oversize Cum Recirculation Monitor is used to count the total number of balls and total number of effective balls in circulation during a preset cycle time. The system is provided with a Control Panel suitable for both manual and automatic operation. The control panel has got a mimic diagram at its front fascia which explains the system functioning. The main advantages of a On Load Tube Cleaning System are as follows :• Increase in heat transfer rate • Optimum turbine back pressure • Increased generation efficiency • Avoidance of corrosion in tubes • Avoidance of shutdown for manual cleaning • Reduction of chemical costs for water treatment • Reduction in fuel costs 9.2 DESCRIPTION OF COMPONENTS : The description of various components which form part of the tube cleaning system is given

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below : Ball Separator (A01) : The ball separator is of shell type construction with flanged ends. The ball separator consists of two screens which are mounted on two shafts. These shafts are fitted with separate drives which facilitate independent operation of screens and easier maintenance. The screens separate the cleaning balls which enter the ball separator and guide these into funnel shaped Ball Extraction Pipes. The screens can be set in either OPERATION position or in BACKWASH position. The actuator and worm gear enable the movement of screens to the required position. Operation Position : The screens inside the ball separator are in normal position. In this position the cleaning balls are separated from the cooling water and are guided to the ball extraction nozzle. Backwash Position : The screens inside the ball separator are in an inverted position. In this position the balls are not circulation and the screens are thoroughly washed. The differential pressure across the ball separator exceeds a certain value due to the fouling of screens and this initiates Backwash position. D.P. Measuring System : The D.P. measuring system constantly monitors the differential pressure across the ball separator screens. This is done to avoid any damage to the screens when the differential pressure exceeds a preset value, the screens are moved to Backwash position. The above system consists of the following :D.P. Transmitter and D.P. Switch with 5-way manifold valves which sense the differential pressure and transform this into an electrical output. D.P. Indicating Controller (E01) which is fitted in the control panel. This facilitates visual observation of the differential pressure reading. The indicating controller has got two alarm contacts for Backwash and Emergency Backwash. Three way Reversing Ball Valve (M01) with actuator when in operation allows the positive and negative impulse lines to be flushed alternatively and when not in operation isolate the lines. DP Flushing Pump (F32) is a monoblock pump which delivers high pressure water through the 3-way reversing valve for flushing of D.P. sensing lines. The water for this purpose is taken from the ball separator itself. Isolating Valves (N21, N22, N23) which isolate the DP Transmitter, Monoblock Pump from the cooling water Impulse Piping. Ball Recirculating Skid : The ball recirculating skid consists of the followings :The Ball Recirculation Pump (F01) is a non clog centrifugal pump which compensates the pressure drop across the condenser pressure loss in the ball transport line. This pump transports the cleaning balls to the ball injection point at the main cooling water pipe line. The motor for the ball recirculation pump (T91) is a totally enclosed fan cooled squirrel cage induction motor. Ball vessel (G01) which controls the circulation of cleaning balls that are extracted from the ball separator. The ball vessel is used for charging and collection of cleaning balls. The ball vessel has a perforated screen basket which traps the balls inside the vessel. The ball vessel acts as a reservoir for the sponge balla when the system is not in operation. Ball Valves with actuators (N01, N02, T01, T02) at the inlet and outlet of the ball vessel which allow the movement of balls when in open condition. Manual Ball Valve (N05) is provided for bypassing the water from the ball vessel. Ball Valves (N91, N92) are provided in the ball vessel for venting and draining purpose whenever required. Pressure Gauges (P01, P02) which measure the suction and discharge pressure of the Ball Recirculation Pump. Ball transport piping. V- Piece : V piece (H11, H12) is used to branch off a ball transport pipe into two separate pipe lines. A sight glass is provided to monitor the movement of cleaning balls. Injection Pipe : The injection pips (L31, L32) are installed at the cooling water inlet pipe line. Cleaning balls are injected through these pipes into the system. For a good ball distribution the end of the injection pipe is directed against the flow. A deflector is provided at the end of the injection pipe for even distribution of balls. Manually Operated Ball Valves : These ball valves (N41, N42, N31, N32) act as isolation valves. These valves are operated manually by a lever. Two valves are provided near ball extraction and two valves are provided near ball injection.

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Ball Transport Piping : Ball transport pipes are installed between the ball separator extraction nozzle to the injection nozzle. These pipes are used to transport the cleaning balls from the ball extraction nozzle to injection nozzle. Control Panel : The control panel (S01) is a common control panel for tube cleaning system and debris filter, which is a programmable logic controller type which enables automatic and manual operation of the system. The control panel is fitted with a mimic diagram which explains the system functioning. Necessary audio and visual annunciations in the MIMIC for easy operation and fault tracing. Ball Oversize Cum Recirculating Monitor : The ball oversize cum recirculating monitor is to monitor the condition of cleaning balls in a tube cleaning system. Since, the cleaning balls are subjected to wear while being used , their diameter must be measured regularly. A plexiglass pipe integrally installed in the tubes system, allows to continually count the number of balls passing by and to compare their diameters with the desired size. A cleaning ball, the size of which is not less than desired value in an “effective ball”. If the proportion of the effective ball is less than a specified percentage or if the total number of the measured balls is less than required, the cleaning balls must be replaced. Counting and measuring the balls is made free from any mechanical contact with the use of three light barriers the signals of which are assessed by microprocessors. The course of beams of the three light barriers being perpendicular to the flow direction of the balls is set to the centerline of the plexible pipe. The course of beam of the two exterior light barriers is set so that an effective ball would interrupt both light beams for a short moment. A ball will, however, not be detected unless the light barrier ion the centre is also darkened. This allows to identify balls or dirt particles. Hence, an effective ball would interrupt all three light beams for a short moment, whereas only two light beams would be interrupted by an effective ball. Prior to the operation of program the user may define the following parameters : - measuring time of test cycle - minimum number of all measured balls per test cycle - minimum number of effective balls per test cycle During the preset period of time the unit determines the total number of balls and the number of effective balls. On termination of test cycle verification is made whether the minimum number of all measured and effective balls was reached. If not, the related alarm signals are initiated. The test cycle is repeated automatically. The alarm signals are maintained and will not be stopped or reset until the next test cycle is completed. Cleaning Balls : The cleaning balls are used for preventing formation of hard deposits and scales inside the condenser tubes. The composition of balls is based on a natural rubber mixture containing inert filler material. To ensure that all the condenser tubes are cleaned, the cleaning balls should have a specific gravity close to that of cooling water. The cleaning balls should be squeezed under water in the ball vessel about 3 times to expel air. The ball diameter should always exceed the internal diameter of the tube to be cleaned. The maximum permissible oversize is dictated by the available pressure drop across the condenser and need to avoid balls sticking in the tubes. Ball life is strongly dependent on the cleaning frequency and the surface condition of the tubes to be cleaned. 9.3. OPERATION PROCEDURE OF COLTC SYSTEM : (A) PRE-REQUISITE OR CHARGING OF CLEANING BALLS : • Check all manual isolation valves [N41, N42, N21, N22, N23, N25, N31, N32] are opened , except bypass valve of Ball Vessel [N05]. • Check motorized 3-way reversing valve [M01] of DP flushing system is closed. • Check the Ball Recirculation Pump [F01] & DP Flushing Pump[F32] are OFF. • Check the inlet & outlet motorized valves [N01 & N02] of Ball Vessel are closed. • Manual bypass valve [N05] of Ball Vessel should be closed. • Open the vent valve [N91] of Ball Vessel. • Open the drain valve [N92] of Ball Vessel for short time. Water level in Ball Vessel falls. • When water level in Ball Vessel is up to half of its capacity, close the drain valve [N92]. • Open hand hole [G01] of Ball Vessel. Charging the cleaning balls and squeeze in water to remove air. • Close the hand hole [G01] of Ball Vessel. • Open a little bit the bypass valve [N05] of Ball Vessel. Ball Vessel will slowly filled with water. • When water flows out from the vent valve [N91] of Ball Vessel, close this valve.

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• Open the Ball Vessel bypass valve [N05] fully. (B) MANUAL OPERATION OF COLTC SYSTEM : • Check the Control Panel is in energized condition and there is no Fail Indication • persisting. • Check the Ball Separator Screens [A01] are in “OPERATION” position. • Turn the control cabinet mode of operation function Selector Switch to “Manual” mode. • Start the Ball Recirculation Pump [F01/T91] by pressing ON PB. • Open the Ball Vessel inlet valve [N01] by pressing OPEN PB. • Observe the cleaning balls are circulating in Ball Vessel. • After 5 minutes of Ball Recirculation Pump starting, open the Ball Vessel outlet valve [N02] by pressing OPEN PB. • Now the system is under operation. Balls are circulated. Ball movement can be observed when viewed through the sight glass of Ball Vessel & V-Piece. • Start Ball Oversize Cum Recirculating Monitor by pressing ON PB (if required). This monitor starts counting the effective and total number of balls in circulation. • Check the DP across the Ball Separator Screens in DP indicating controller. • Stop the Ball Oversize Cum Recirculating Monitor by pressing OFF PB. • After certain time of manual operation (1 hr) , close the Ball Vessel outlet valve [N02] by pressing CLOSE PB. 30 minutes later close the Ball Vessel inlet valve [N01] by pressing CLOSE PB. • Stop the Ball Recirculation Pump [F01/T91] by pressing OFF PB. Manual Operation Of DP Flushing System : When DP measuring system is in operation, lamp indication for Backwash & Emergency Backwash will be available when DP exceeds the set limit (30 mbar & 50 mbar respectively). DP flushing system will have to be initiated manually when the system is in “Manual” mode. • Start DP Flushing Pump [F32/T92] by pressing ON PB. • Open 3-way reversing valve [M01] by pressing OPEN PB. • After a certain time close 3-way reversing valve [M01] by pressing CLOSE PB. • Stop DP Flushing Pump [F32/T92] by pressing OFF PB. (C) AUTO OPERATION OF COLTC SYSTEM : • Check the Ball Separator [A01] Screens are in Backwash position. • Confirm balls are available in Ball Vessel. • Check Ball Vessel vent valve [N91] & drain valve [N92] are fully closed. • Check Ball Vessel bypass valve [N05] is fully opened. • Setting the timer of ball collection time [Tb : ball collection time = 1 hr] and flushing operation time [Tf : flushing time = 30 min.]. Operation time of tube cleaning is 1 hr. • Turn the control cabinet mode of operation function Selector Switch to AUTO. • Check Ready To Start lamp is ON. • Start the system by pressing “Automatic Start” PB Now observe the following operation steps in auto mode :• Ball Separator Screens turn to OPERATION position. • Ball Recirculation Pump [F01] starts. • Ball Vessel inlet valve [N01] opens. Cleaning balls circulate in Ball Vessel. • 5 minutes later Ball Vessel outlet valve [N02] opens. • After completion of operation time [1 hr] Ball Vessel outlet valve [N02] closes. • After completion of ball collection time [30 min] Ball Vessel inlet valve [N01] closes. • Ball Recirculation Pump [F01] stops. (D) AUTO OPERATION OF COLTC SYSTEM BY DP CONTROLLER : When Differential Pressure Is Greater Than 30 mbar & Less Than 50 mbar : When the DP across the Ball Separator Screens is greater than 30 mbar and less than 50 mbar during auto operation of COLTC system, the following steps will take place automatically :-

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POWER PLANT SIMULATOR TRAINING INSTITUTE Bakreswar Thermal Power Project : • • • • • • • • • • • • • • • •

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Indication lamp of “Screen Backwash” is ON. Ball Vessel outlet valve [N02] closes. Cleaning balls are being collected in Ball Vessel. 30 minutes later i.e. after completion of ball collection time Ball Vessel inlet valve N01] closes. Ball Recirculation Pump [F01] stops. Ball Separator Screens turn to “Backwash” position. Screens are backwashed and cleaned for 30 min. (screen backwash time is adjusted by timer). DP will display 0 mbar. DP Flushing operation is ON. DP Flushing Pump [F32] starts. 3-way reversing valve [M01] opens. Immediately 3-way reversing valve [M01] closes. DP Flushing Pump [F32] stops. After completion of backwashing (i.e. after the timing of 30 min. is elapsed), Ball Separator Screens turn to “Operation” position. Ball Recirculation Pump [F01] starts. Ball vessel inlet valve [N01] opens and cleaning balls circulate in Ball Vessel. After 5 minutes Ball Vessel outlet valve [N02] opens and cleaning balls distributethemselves through the system. Now unit is again in operation.

When Differential Pressure Is Greater Than 50 mbar : When the DP across the Ball Separator Screens is greater than 50 mbar during auto operation of COLTC system, the following steps will take place automatically :• DP Indicator on control panel displays “Failure” indication and lamp of “Emergency • Backwash” is ON with alarm. • Ball Separator Screens turn to Backwash position. • Ball Vessel outlet valve [N02] closes. • Ball Vessel inlet valve [N01] closes. • Ball Recirculation Pump [F01] stops. • Ball Oversize Cum Recirculating Monitor OFF. • Screens are in Backwash position for 30 min. • DP flushing is ON. • DP Flushing Pump [F32] starts. • 3-way reversing valve [M01] opens. • 3-way reversing valve [M01] closes. • DP Flushing Pump [F32] stops. After flushing is over, DP value comes down and then do the following operations: • Turn the function Selector Switch from Auto to Manual. • Press fault accept and reset push button. • Turn the function Selector Switch from Manual to Auto. • Press the Automatic Start PB for starting the COLTC operation with Auto mode. NOTE : After each Emergency Backwash operation, cleaning balls are counted and the number of balls lost are replaced with new cleaning balls to maintain the basic charge. (E) AUTO SHUTDOWN PROCEDURE OF COLTC FOR CHARGING OF CLEANING BALLS : For charging of new cleaning balls during auto mode operation of COLTC, press the control cabinet illuminated “Automatic Stop” PB. Then the following operations will take place automatically :• Ball Vessel outlet valve [N02] closes. Cleaning balls are being collected in Ball Vessel. • 30 minutes later (adjusted by timer) Ball Vessel inlet valve [N01] closes. • Ball Recirculation Pump [F01] stops. • Automatic Stop PB glows steadily i.e. OFF program is completed.

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• Turn the Function Selector Switch to Manual. After completion of the above automatic operation, follow the procedure for charging of cleaning balls as discussed in Art. No. 9.3.A.

10. DEBRIS FILTER SYSTEM : 10.1. INTRODUCTION : Debris such as shells, sticks stones and plastics are common cause of failure in condenser tubes by localized attack (erosion-corrosion). When water flows through the condenser tubes, a shear stress is developed in the tube surface which is dependent on the C.W. velocity. Every alloy has a critical shear stress corresponding to a critical CW velocity, above which erosion-corrosion will occur. The free cross-sectional area at a lodged obstruction is reduced and this leads to a corresponding increase in the CW velocity to maintain volume flow rate. This increase may then be sufficient for the critical shear stress to be exceeded and for erosion-corrosion to take place. Erosion-corrosion is particularly a rapid form of attack. The protective oxide film is removed and attack of the tube material can therefore proceed virtually unimpeded. Tube penetration in a few thousand hours is common. Where an extremely large number of tubes are blocked by debris, it is possible that the CW velocity in the remaining tubes will be sufficiently high to cause film breakdown and subsequent erosion-corrosion. The source of lodged obstructions originate from within the CW system. This could typically be pieces of concrete or stones from the CW basin / culverts, packing material from within the cooling tower or bio-species which have grown to maturity in the CW system. Mussels, barnacles etc. can easily penetrate the primary screening in the larval state and grow rapidly under the very favourable conditions (warmth, ready supply of nutrients and oxygen) pertaining in the CW intake system. Sooner or later the mussels etc. get detached an the shells enter the condenser tubes causing blockages. Improvements in the primary screening would only lead to a partial solution. It would not solve the problem of debris from within the CW system itself. Similarly chlorination can be used to kill mussels etc. but will not prevent the shells entering the condenser. Recognition of these problems

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and the severe consequences of debris trapped in the condenser tubes has meant that some form of secondary screening located as close as possible to the inlet water box , is now regarded as essential. GEA INDIA made Debris Filter is used in our plant to fulfill the above requirements. This “V” type of Debris Filter continuously remove the debris such as mussels, fish, grass, leaves, pieces of wood, plastics from circulating water system. Filter perforation of 5 mm is chosen to meet actual conditions. Pressure loss across strainer in clean condition maximum 50 mbar at a velocity of 2 m/sec. The filter is characterized by its compactness, the housing diameter being equal to the diameter of the CW inlet. With this design of filter the CW enters the housing and coneshaped strainer basket axially. The Debris Extractor is located on the inside of the filter basket, extending along the whole length of the basket wall. The separation between the extractor and the basket wall is 30-60 mm. The Water Injector is located next to the outside wall of the basket directly opposite to the extractor and enables the separator basket to be back-flushed free from debris. During intermittent flushing the quantities of water extracted from and injected into this GEA INDIA DEBRIS FILTER are practically the same and thus balance each other. In this V-type Debris Filter the strainer basket is fixed and the Debris Extractor and Water Injector are rotated around it during flushing. The compact design of “V” type Debris Filter means that the ratio of free cross-section of the strainer to the CW inlet cross-section is normally limited to 2:1 and in extreme cases it can be 1:1. This limitation is counted, however by the extremely good flushing capability of this type of filter. It only leads to more frequent flushing being necessary which is perfectly acceptable in view of the very low CW loss during flushing. 10.2. DESCRIPTION OF COMPONENTS : The description of various components which form part of Debris Filter System is given below:Debris Filter (C11) : The Debris Filter is of shell type construction with flanged ends. The Debris Separator consists of a screen basket, Flushing arm assembly with rotation motor drive and a Debris Discharge Unit. The basket prevents the debris from entering the main inlet line. The flushing action activated by he rotation motor, accumulates the debris, which after collection through a pipe, are discharged through the discharge unit. The discharge unit comprises of a pipe line running through the central axis of the separator and an actuator operated valve that drains the debris out. D. P. Measuring System : The DP measuring system constantly monitors the differential pressure across the Debris Separator. This is done to avoid any damage to the screen basket. When the differential pressure exceeds a preset value, the flushing arm assembly activated by the rotation motor drive, flushes the basket. The above system consists of the following :• DP transmitter and DP Switch with 5-way manifold valve which sense the differential pressure and transform this into an electrical output. • DP Indicating Controller (E01) which is fitted in the control panel. This facilitates visual observation of the existing differential pressure reading. • DP Flushing Pump [F32] is a monobloc pump which delivers high pressure water through the 3-way reversing valve for flushing the impulse lines. The water for this purpose is taken fro the Debris Separator. • Isolating Valves [N21, N22, N23] which isolate the DP Transmitter from the cooling water. • Impulse piping. Flushing Pump Skid : The Flushing Pump Skid comprising of a centrifugal pump and motor which activates the flushing cycle, flushing the Screen Basket to clear the debris out.The Flushing Pump [F31] is a centrifugal pump that supplies the flushing water to the flushing arm that clears the debris blocked in the screen basket. Motor for flushing pump [T91] is a totally enclosed fan cooled squirrel cage induction motor. Pressure gauges [P01, P02] measure the suction and discharge pressure of Debris Flushing Pump. Flushing pipes. Manually Operated Ball Valves : These Ball Valves [N61, N71] act as isolation valves. These valves are manually operated using a lever. Debris Flushing Pipe Lines :

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The flushing pipes bridge the Flushing Pump and Debris Filter and form a closed cycle, thereby flushing the screen basket. Control Panel : The control panel [S01] is a common control panel for COLTC system and Debris Filter, which is Programmable Logic Controller type which enables Automatic and Manual operation of the system. The control panel is fitted with a Mimic Diagram which explains the system functioning. Necessary audio and visual annunciations in the MIMIC for easy operation and fault tracing. 10.3. OPERATION PROCEURE OF DEBRIS FILTER UNIT : (A) MANUAL OPERATION OF DEBRIS FILTER CLEANING SYSTEM : • Check the cooling water system is completely vented by the operation of Debris Filter • vent valve [N32]. • Check all the isolation valves [N21, N22, N23, N24, N25 N61 & N71] are opened. • Turn the Selector Switch to Manual mode. • Start the Debris Flushing Pump [F31] by pressing ON PB. • Open the debris outlet / discharge valve [M31] by pressing OPEN PB. • Start the geared motor drive [B21, T21] of rotary spray water arm by pressing ON PB. • After completion of flushing the debris (5 min.), stop the geared motor drive [B21, T21] • of rotary spray water arm by pressing OFF PB. • Close the debris outlet valve [M31] by pressing CLOSE PB. • Stop the Debris Flushing Pump [F31] by pressing OFF PB. (B) MANUAL OPERATION OF D.P. TRANSMITTER FLUSHIN SYSTEM : • Start the DP Transmitter Flushing Pump [F32] by pressing ON PB. • Open the 3-way reversing valve [M01] by pressing OPEN PB. • After a negligible time delay close 3-way reversing valve [M01] by pressing CLOSE PB. • Stop the DP Transmitter Flushing Pump [F32] by pressing OFF PB. (C) AUTO OPERATION OF DEBRIS FILTER CLEANING SYSTEM : Setting the timer of flushing operation. Set flushing time – 5 minutes & operation cycle time – 1 hr. • Turn the Selector Switch to Auto mode. • Check that Ready To Start indication appears. • Start the system by pressing the “Automatic Start” PB. • The following operations will take place step by step automatically :• Debris Filter Flushing Pump [F31] starts. • Debris outlet valve [M31] opens. • Geared motor drive of rotary water spray arm [B21, T21] starts to rotate after the debris • discharge valve is fully opened. • The flushing timer picks up. When the timing is elapsed the geared motor drive of • rotary water spray arm stop. • Debris discharge valve [M31] closes. • Debris Filter Flushing Pump [F31] stops. • System is ready to start. (D) AUTO OPERATION OF DEBRIS FILTER CLEANING SYSTEM THROUGH D.P. TRANSMITTER (When DP > 100 mbar) : • Debris Filter Flushing Pump [F31] starts. • Debris outlet valve [M31] opens. • Geared motor drive of rotary spray arm [B21] starts to rotate. • After completion of cycle time (duration of flushing) geared motor drive stops. • Debris outlet valve [M31] closes. • Debris Filter Flushing Pump [F31] stops. • DP transmitter impulse line Flushing Pump [F32] starts. • 3-way reversing valve [M01] opens. • 3-way reversing valve [M01] closes. • DP transmitter impulse line Flushing Pump [F32] stops.

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DEBRIS FILTER SYSTEM:

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49 TURBINE GOVERNING SYSTEM In order to maintain the synchronous speed under changing load/grid or steam conditions, the FUJI steam turbine. is equipped with electro-hydraulic governor fully backed-up by a hydraulic governor. The measuring and processing of electrical signal offer the advantages such as flexibility, dynamic stability and simple representation of complicated functional systems. The integration of electrical and hydraulic system is an excellent combination with following advantages :i) Exact load-frequency droop with high sensitivity. ii) Avoids over speeding of turbine during load throw-offs. iii) Adjusting of power frequency droop in fine steps even during on-load operation. In this chapter the following discussions will be made step by step :(a) Governing oil system. (b) Main elements of the governing system. (c) Electro- Hydraulic Governing (EHG). (d) Mechanical Hydraulic governing (MHG). (e) Turbine protection devices. (A) GOVERNING OIL SYSTEM Introduction :Please refer to the “Turbine Hydraulic Governing Diagram” in which the turbine control devices and turbine protective devices are shown with its line. Items Nos. of equipment used in this explanation are same as those in

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the above drawing. The oil for control devices and protective devices is normally supplied by the main oil pump (1.1) directly coupled with the turbine rotor. This MOP also supplies the lubricating oil as well. The discharge oil from this main oil pump (1.1) is called “pressure oil or control oil” which is indicated as yellow line in the drawing. The value of the pressure of pressure oil is normally approximately 8.0 kg/cm2. As to other oil lines of the governing oil system, coloured lines are used in the drawing. Detail Explanation :1. Trip Oil (Red Line) : The pressure oil from the main oil pump (1.1) is led to the emergency trip device (2.1) through the oil filter (1.18) and the solenoid trip device (41.3) of the three way magnet valve. The trip oil line means the following lines :i) Line from the emergency trip device (2.1) to the follow-up pistons (3.20, 3.21, 3.22, 3.25) which give the signal oil to the main steam control valves (6.1) and intercept valves (8.1). ii) Line from the emergency trip device (2.1) to the test valves (5.2, 7.2) for the main and reheat stop valves. If the trip oil pressure in this line is lost, the main stop valves (5.1), reheat stop valves (7.1) and main steam control valves (6.1), intercepts valves (8.1) are fully closed and the turbine is tripped. The value of the trip oil pressure is normally 8.0 kg/cm2. 2. Auxiliary Trip Oil (Dotted Red Line) : This line means the line from the emergency trip device (2.1) to the vacuum trip device (2.3), the releasing device (1.3.1) for the emergency governor (1.3) and the releasing device (1.5) for the thrust failure protection device (1.4). Auxiliary trip oil pressure is lost by operation of the above protective devices. If the auxiliary trip oil pressure is lost, the force balance between the differential piston and the spring of the emergency trip device (2.1) is lost, the emergency trip device (2.1) operates and the turbine is tripped. 3. Primary Oil (Green Line): The speed governor of FUJI steam turbine is of oil hydraulic type and the signal oil for this speed governor is called “Primary Oil”. The primary oil is supplied from the governor impeller (1.2) which is assembled in the shaft of the main oil pump (1.1). The primary oil pressure is in proportion to the square of the turbine speed. So, if the turbine speed goes down, the primary oil pressure is reduced and the turbine speed goes up, the primary oil pressure is increased. The value of the primary oil pressure is about 2.5 kg/cm2 at the rated turbine speed. The primary oil is led to the governor bellows (3.2) of the speed governing device (3.1) from the governor impeller (1.2). The governor is controlled so that the force balance between the spring force of the speeder gear spring (3.3) which is set by the speed setter (3.8), and the force of the governor bellows (3.2). A tachometer (43.6) for which this primary oil pressure is used, is mounted on to the gauge panel of the turbine governor pedestal. 4. Secondary oil ( Light Blue Line) : The trip oil is supplied for the follow-up piston systems (3.21, 3.22) incorporated in the electro-hydraulic converter (3.50) through the throttle and by these follow-up piston systems, the secondary oils are supplied to the lower side of the pilot valves (6.3, 8.3) of the servomotors (6.2, 8.2) which operates the main steam control valves and the intercept valves. If the secondary oil pressure is reduced, the main steam control valves and the intercept valves are closed. The value of the secondary oil pressure is normally 2.0 kg/cm2 at the fully closed position of those valves and normally 5.0 kg/cm2 at the fully opened position of those valves. 5. Auxiliary Secondary Oil (Dotted Light Blue Line) : The principle of this line is same as that of the secondary oil line of the above item No.4. This secondary oil is supplied by the follow-up piston system (3.20) and led to the upper chamber of the pilot valve of the electrohydraulic converter (3.50). The follow up piston system is used for not only magnifying the variation of the primary oil pressure up to several times but also reversing the direction of the variation of the auxiliary secondary oil pressure in comparison with that of the primary oil pressure. So, if the primary oil pressure goes down, the auxiliary secondary oil pressure goes up and if the primary oil pressure goes up, the auxiliary

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secondary oil pressure goes down. When the auxiliary secondary oil pressure is reduced, the secondary oil pressure which is produced by the follow-up piston systems (3.21, 3.22) for main steam control valves and intercept control valves incorporated in the EHC (3.50), is reduced as well as the auxiliary secondary oil pressure. Therefore, the main steam control valves and intercept control valves are closed. The value of the auxiliary secondary oil pressure is normally 2.5 kg/cm2 at the beginning position to open the main steam control valves and normally 5.0 kg/cm2 at the fully opened position of the main steam control valves. 6. Start-Up Oil (Orange Line) : The pressure oil is led to the change-over valve (3.9) of the starting and load limiting device (3.10) through the oil filter (1.18) . The start-up oil line means the line which is connected to the upper side of the test valves (5.2, 7.2) of the main and reheat stop valves from the lower side of the change-over valve (3.9) of the starting and load limiting device (3.10). At the starting-up of the turbine, the change-over valve (3.9) is set at lower limit position (position as shown in the drawing) and the change-over valves of the test valves (5.2, 7.2) are pressed below against the spring force. At that time, the trip oil arrive in the upper chamber of the plungers of the main and reheat stop valves via the test valves (5.2, 7.2). Thereby these valves are ready for opening. Then, the main and reheat stop valves are fully opened by means of the starting device (3.10), the change-over valve (3.9) is set at the upper limit position and the start-up oil line is connected to atmosphere by change over of the changeover valve (3.9) and the oil pressure is lost. 7. Auxiliary Start-Up Oil (Dotted Orange Line) : This line means the line from the upper side of the change-over valve (3.9) of the starting and load limiting device (3.10) to the lower side of the emergency trip device (2.1). This line is used for auto reset of the emergency trip device, the releasing device for emergency governor (1.5) and the thrust failure protection device (1.4). This auxiliary start-up oil has no gauge pressure as well as the start-up oil of the above item no.6 at the normal operating condition because the starting device (3.10) is operated for the upper limit side. 8. Test Oil (Purple Line) : This oil is used for the oil pressure test of the emergency governors (1.3). The pressure oil is supplied through the oil filter (1.18) for the oil trip test device (1.6) which is assembled in the governor pedestal, and by operation of the oil trip test device (1.6), the test oil is led to the emergency governors (1.3) through the hole which is bored at the axial centre of the shaft of the main oil pump (1.1). (B) MAIN ELEMENTS OF THE GOVERNING SYSTEM The main elements of the governing system and the brief description of their functions are as follows :1. Remote trip solenoids (RTS) 2. Emergency trip device (Main trip valve) 3. Starting and load limiting device (77M) 4. Hydraulic governor or speed governor (MHG) 5. Auxiliary follow-up piston valves 6. Follow-up piston valves 7. Electro-hydraulic converter (EHC) 8. Solenoid for load shedding relay 9. Test valve 10. Emergency governor 11. Oil trip test device 12. Mechanical vacuum tripping device. 1. REMOTE TRIP SOLENOIDS [Item No. 41.3.1 & 41.3.2] : The remote trip solenoid operated valves are two in number and form a part of turbine protection circuit. Under their normal de-energized condition, the control oil for governing is free to through them to main trip valve (Emergency trip device). The solenoid gets energized whenever any electrical trip command is initiated or turbine is tripped manually from local or

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UCR. Under energized condition the control oil supply gets connected to the drain. The solenoids can be reset by resetting the Unit Trip Relays from UCR.. 2. EMERGENCY TRIP DEVICE [Item No. 2.1] : The emergency trip device or main trip valve is the main trip gear of the turbine protective circuit. All turbine tripping take place through these valves. The control oil from remote trip solenoids is supplied to emergency trip device. Under normal conditions, this oil flows into two different circuits ; the Trip oil and Aux. Trip oil. Trip oil supplied to the main and reheat stop valves and auxiliary secondary oil circuits. The auxiliary trip oil flows in a closed loop formed by the emergency trip valve and turbine hydraulic protective devices. The construction of emergency trip device is such that when the auxiliary trip oil pressure is adequate, it olds the valve spools in open condition against the spring force. Whenever control oil pressure drops or any of the hydraulic protective devices are actuated, the emergency trip device is tripped. Under tripped condition, trip oil pressure is drained rapidly through the main valve ; closing turbine stop and control valves.. 3. STARTING & LOAD LIMITING DEVICE [Item No.3.10] : The starting and load limiting device (77M) is used for resetting the turbine after tripping, for opening the main and reheat stop valves, and releasing the control valves for opening. The starting device basically consists of a pilot valve that can be operated either manually by means of a hand wheel or from remote by means of an electric motor. It has got port connections with the control oil, start-up oil and auxiliary start-up oil circuits. The starting device can mechanically act upon the hydraulic governor bellows by means of a lever and link arrangement. Before start up, the pilot valve is brought to its bottom limit position by reducing the starting device to 0% position. This causes the hydraulic governor bellows to be compressed thus blocking the build-up of secondary oil pressure. This is known as control valve “CLOSED” position. With the valve in the bottom limit position (i.e., 77M 0%) control oil flows into the auxiliary start-up oil circuit (to reset protective devices) and the start-up oil circuit (to reset the main and reheat stop valves). A build-up of oil pressure in these circuits can be observed, while bringing the starting device to zero position. When the pilot valve i.e. the starting device position is raised, the start-up oil and auxiliary start-up oil circuits are drained. This opens the stop valves ; MS stop valves open at 42% and RH stop valves open at 56% positions of the starting device. Further raising of the starting device release the hydraulic governor bellows which is in equilibrium with hydraulic governor’s spring tension and primary oil pressure (turbine speed), and raises the auxiliary secondary oil pressure ; closing the auxiliary follow-up drains of hydraulic governor. 4. HYDRAULIC GOVERNOR OR SPEED GOVERNOR [Item No.3.1] : The speed governor is an assembly of a bellow and a spring, the tension of which can be adjusted from remote by an electric motor or locally by a hand wheel. The bellow compression depends upon the position of the starting and load limiting device and the speeder gear position which alters the spring tension on the top of the bellow. The bellow is also subjected to the primary oil pressure which is the feed back signal for actual turbine speed. The zero position of the speeder gear corresponds to 2820 rpm i.e., hydraulic governor comes into action after 2820 rpm. The bellow and spring assembly is rigidly linked (3.4) to the sleeves of the auxiliary follow-up piston valves. The sleeve position changes with the equilibrium position of the bellow. The function of the hydraulic speed governor is to regulate the opening of the control valves in such a manner that the steam input to the turbine corresponds to the required load conditions. 5. AUXILIARY FOLLOW-UP PISTON VALVES [Item No.3.20] : There are two numbers of auxiliary follow-up piston valves in parallel. The trip oil is supplied through throttles to the aux. follow-up valves. The sleeves of these valves are attached to the speeder gear bellow link. The lift of the hydraulic governor bellows (3.2), which can be limited by the starting and load limiting device (3.10), is transmitted to the sleeve (3.5) of the aux. follow-up piston systems (3.20) through the lever (3.4). The position of the follow-up pistons (3.6) are determined and kept by the force of the springs (3.7) against the oil pressure. The oil overflows from the slit between the follow-up piston (3.6) and the sleeve (3.5) to produce oil pressure corresponding to the force of the spring (3.7). so, the sleeve position determines the drain of trip oil through the aux. follow-up valves. According to trip oil pressure , the pressure at upstream of these valves changes. Upstream of circuit is termed as AUX. SECONDARY OIL CIRCUIT. Hence, aux. follow-up piston valves can be said to control aux. secondary oil pressure.

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6. FOLLOW-UP PISTON VALVES [Item No.3.21, 3.22 & 3.25] : There are five numbers of follow-up piston valves in parallel. The principle of operation of follow-up piston valves are same as that of aux. follow-up piton valves. The trip oil is supplied to the follow-up piston valves through throttles and flows in the secondary oil piping to MCVs and ICVs. The secondary oil pressure depends upon the position of sleeves of follow-up piston valves ; which determines the amount of drainage of trip oil. The drain port opening of follow-up pistons depends on aux. secondary oil pressure or the position of pilot spool valve (i.e. position of the amplifier piston) of the electro-hydraulic converter (i.e. EHC output). The follow-up piston valves constitute a minimum value gate for both the governors (EHG/MHG). This means that the governor with lower reference set point is effectively in control. This is also termed as “Hydraulic Minimum (MIN) Selection” of governors.

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7. ELECTRO – HYDRAULIC CONVERTER (EHC) [Item No.3.50] The electro-hydraulic converter or EHC is the connecting link between the electrical and hydraulic parts of electro-hydraulic governing system. Fig.4 shows the EHC system. EHC consists essentially of the amplifier cylinder (20), amplifier piston (13), pilot valve (25), feed back systems (50,51,39), follow-up pistons (44), differential transformers (3) and moving coil system (19). The electrical control pulses emitted from the electric governor actuate the sleeve (21) via a moving coil system. The sleeve slides on the piston end of the pilot valve and is provided with oil drain ports. Auxiliary secondary oil passes to the space above the pilot valve, through a centre bore oil passage at its upper end and discharges through the drain ports of the sleeve. The oil pressure in the space above the pilot valve varies according to the gap between the piston valve and sleeve. With a normal size gap, the oil pressure holds the pilot valve in the centre position against the spring force (30), thus closing the control oil passage to the amplifier piston (13). During a control sequence, the cross section of the aux. secondary oil outlet is changed when sleeve (21) moves, thereby causing the pilot valve to leave its central position as a result of the change in oil pressure. The control oil is thus admitted to the space above or below of the amplifier piston, with the opposite side of the piston being connected to drain. During movement of the amplifier piston, feed back is initiated via three differential transformer to return the pilot valve to its central position by repositioning of sleeve (21). This closes the oil inlet and outlet to the amplifier piston that will then remain in its new position. If the hydraulic speed governor is in service, sleeve (21) will be in its lowest position. The auxiliary secondary oil pressure produced by the hydraulic governor varies according to load requirements. If the governor increases the auxiliary secondary oil pressure as a command for further opening of control valves, the pilot valve of EHC moves downward against the spring force, thus opening the control oil passage to the space above the amplifier piston while the oil in the space below the piston is permitted to flow off via the drain cross section. The downward movement of the amplifier piston causes the pilot valve to be returned to its central position via the linkage mechanism (15,49,50,51) and sleeve (39). The proportional is set by a adjust screw (33). The control sequence is completed when the oil inlet and outlet are closed off. If on the other hand, the aux. secondary oil pressure drops, the spring (30) will unload and move the pilot valve upwards. Corresponding with the admission of control oil, the amplifier piston moves upwards until feed-back has returned the pilot valve to its central position. 8. SOLENOID FOR LOAD-SHEDDING RELAY [Item No. 41.20.1 &

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41.21.2] : When the turbine load is shed, solenoid valves (41.20.1, 41.20.2) are provided in the secondary oil and aux. secondary oil lines respectively in order to keep the turbine from accelerating up to the emergency trip level, in company with load shedding relay. Load shedding relay detects the load changing rate. When the turbine load decreases with more rapid rate than set rate, load shedding gives a signal to solenoid valves and makes solenoid valves operate. Solenoid valves ( 41.20.1) mounted in the secondary oil circuit of ICVs open and release that secondary oil pressure to close intercept valves. Solenoid valve ( 41.20.2 ) mounted in the auxiliary secondary oil circuit open and release the auxiliary secondary oil pressure, then the pilot valve of EHC moves rapidly up to the upper limit position. Oil flows into the lower part of follow up pistons (3.21,3.22) and makes follow up pistons move rapidly up to the upper limit position. Then secondary oil pressure produced by the follow up pistons is rapidly released. Therefore, main control valves close slightly later than intercept valves, but both intercept and main control valves close much earlier than the speed governor follows the turbine acceleration. At the same time, reheat check valve (17.1), extraction check valves (18.5) are also closed by solenoid valves (41) through pressure switches (40) operated by secondary oil pressure. After an adjustable time delay, solenoid valves for load shedding relay close and the secondary oil pressure is produced again corresponding to the new load.

9. TEST VALVE [Item No. 5.2 & 7.2] :Each of the HP & IP stop valves servo motors receive trip oil through their associated test valves. The function of the test valve is to open or close the MSSV and RHSV. The test valves have got port openings for trip oil as well as start- up oil. The test valves facilitate the supply of trip oil pressure beneath the servo motor disc under normal condition (i.e. stop valve “open” condition). For the purpose of resetting MS Stop valves and RH stop valves after turbine tripping, start - up oil pressure is supplied to the associated test valves which moves their spool downwards against the spring force. In their bottom most position, the trip oil pressure starts building up above the stop valve servo motor piston while the trip oil beneath the disc gets connected to drain. When start- up oil pressure is reduced, the test valve moves up draining trip oil above the servo motor piston and building the trip oil pressure below the disc, thus opening the stop valves. A hand wheel is also provided for manual operation of test valves.

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10. EMERGENCY GOVERNOR [Item No. 1.3.1 & 1.3.2.] : The emergency governor is provided to trip the turbine when its speed exceeds the allowable limit. Refer Fig.5. The centrifugal bolt (6) is so positioned that its centre of gravity is apart from the turbine rotor centre by means of the specially designed adjusting bolt (7). At the rated speed, the centrifugal bolt is held in the position shown on the figure by the force of the spring (5). The spring force under this condition

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overcomes the centrifugal force applied on the centrifugal bolt. When the turbine speed exceeds the allowable limit, the centrifugal force imposed on the bolt increases correspondingly, and at a specified emergency trip speed the centrifugal force become equal to the spring force causing the centrifugal bolt (6) projects out of the turbine rotor (8) and stops the turbine. The hole in the rotor (8), closed by the lock bolt (4) and the flange of the centrifugal bolt is in contact with the lock bolt when the turbine speed is held within the normal range. From the hole of the lock bolt (4), which is fixed by the fixing screw (3), the adjusting bolt (7) for setting the trip speed of emergency governor can be taken out for adjustment. Accurate performance is of the great importance for the emergency governor. A special test method under turbine operation is therefore available through oil trip test device. 11. VACUUM TRIPPING DEVICE (Mechanical) [Item No. 2.3.1] : The purpose of the vacuum tripping device is to operate the emergency trip device when a failure of vacuum occurs in the condenser, thus tripping out the main and reheat stop valves and control valves to shut off the supply of steam to the turbine within the shortest possible time. Refer Fig.6. Condenser vacuum is connected via “1” with the top side of the diaphragm (27). The space below the diaphragm is at atmospheric pressure. Upon failure of the condenser to maintain proper vacuum, diaphragm (27) is forced downwards by the increase in pressure and the force of the spring (26) against trip the force of spring (30), thus moving change-over valve (12) downwards. This establishes a connection between “v” (auxiliary oil) and drain “c” so that the auxiliary trip oil circuit is depressurized and the emergency trip device operates. Concurrently spring disc (29) actuates through bolt (33) limit switch (34), which initiates an alarm contact. Any leakage oil is drained off through the passages in the valve sleeve (13) and in the casing (11). In order to isolate the trip oil circuit during starting, changeover valve (12) is lifted by means of spring (30) so that oil drain “c” is shut off, thereby establishing the pressure in the auxiliary trip oil circuit when no vacuum exists. As the turbine is brought up to speed, primary oil flows through connection “d” to the top side of the piston (18). As primary oil pressure builds up with increase in turbine speed, piston (18) is forced into the lower position. This lower position is reached at approximately 50% of rated speed at which time the vacuum tripping device is ready to operate. The range in which the vacuum tripping device operates can be varied by adjusting the initial tension of spring (26) by means of the adjusting screw (22). 12. OIL TRIP TEST DEVICE [Item No. 1.6 ] : The function of the oil trip test device is to test and exercise the emergency governor. The emergency governor consists of an centrifugal bolt which protrudes out by the centrifugal force against the spring force under an over-speed condition. The centrifugal bolt strikes a bell crank and thus opens the trip oil circuit so that the stop and control valves immediately interrupt the admission of steam to the turbine. It is therefore of major importance that the emergency governor works reliably. Refer Fig.7. The oil trip device consists of three changeover valves (8,18,26) installed in the casing (25). The changeover valve (26) is held in the position show in section A-A by spring (23) that bears against the stand (22) and spindle (21). In that position the auxiliary trip oil can pass to the releasing device for emergency governor (refer to the other section) via connection “X” and “X1” when the grip (20) is pushed in and held by manual, the changeover valve (26) is positioned so that the connection “X” and “X1” are cut off each other, thus isolating the auxiliary trip oil circuit from the releasing device. A small quantity of oil is permitted to pass the changeover valve (26) even during this operation, which ensures a pressurization of the line to the releasing device after a test. The changeover valve (18) performs the function of admitting test oil to the centrifugal bolt of the emergency governor, causing them to protrude from the turbine rotor during the over-speed trip test operation. The changeover valve (18) is guided in the stand (14) and the guide bush A centre bore with radial openings is provided in the changeover valve (18) (see section BB). An annular chamber in guide bush (19) is connected to the pressure oil connection “a” (see section A-A). In the position shown in the figure, pressure oil is prevented from entering the bore of the changeover valve (18). By means of the hand wheel (11) or motor operating (13), the changeover valve (18) can be moved inwards so that the passage from connection “a1” is isolated from drain “c”. The pressure oil can now flow from connection “a” to connection “a1” via the guide bush (19) and the changeover valve (18) for testing the emergency governor. The changeover valve (8) is used for resetting the releasing device for emergency governor after the test operation. When the grip (1) is pushed in against the force of spring (6) by manual, the changeover valve (8) is positioned to supply pressure oil from connection “a” to “u1” , thus latching the

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releasing device. During start up, connection “u” and “u1” provide a passage for auxiliary start-up oil for latching the releasing device. Passages in the casing (25) are provided to carry the leakage oil from the changeover valve to drain “c”. (C) ELECTRO-HYDRAULIC GOVERNING (EHG) Introduction : This document covers the basic function and brief explanation of turbine governing system for Bakreswar Thermal Power Plant. The EHG system is a PLC based system and works on the HDC 500 PLC system of FUJI Electric. The governing logics are programmed on “FAISES” software. This forms the main controller for turbine governing backed up by a Mechanical system. Electro-hydraulic governing ensures smooth rolling, synchronizing and loading of turbine. A brief account of various features and their operation is given below. EHG is based on three controllers : 1. Speed Control 2. Load Control 3. Pressure Control. C.1. SPEED CONTROL : 1. OPERATION : The speed control of turbine is active whenever the Generator Circuit Breaker is open. It ensures smooth rolling and synchronization of turbine. Basically speed control maintains constant speed of the turbine according to the set point. During rolling the set point is generated automatically and the rate of speed change is selected depending on the condition of the turbine. If turbine rolling take place in Very Hot Mode, Hot Mode or Warm Mode, the speed change rate will be Fast at 500 rpm/min while in Cold Mode the speed change rate will be Slow at 200 rpm/min. There are three selections available at the control desk : (a) Turning , (b) Soaking , (c) Rated. • Turning : In turning, the speed set point is 0 rpm so no command goes to the E/H converter and all MCVs and stop valves are closed. Turning of turbine take place by the oil supplied by AOP through turning oil supply valve with necessary lifting by jacking oil. In Bakreswar , turning speed is approximately around 140-220 rpm depending on vacuum and AOP discharge pressure. • Resetting of Turbine : Soaking can only be selected if turbine is in reset condition. Resetting of turbine is possible only when all the trip conditions for turbine are removed. Turbine reset means that echanical trip devices and stop valves are reset and sufficient trip oil pressure is generated. The main source of trip oil is the control oil which is supplied by AOP during start up and by MOP after sufficient speed is attained. This control oil passes through two remote trip solenoids and Emergency Trip Device to form trip oil. So to generate trip oil, the remote trip solenoids are deactivated and Emergency Trip Device is reset. RTS are deactivated if no trip conditions persist and emergency trip device is reset by generating sufficient auxiliary start-up oil by starting device. When starting device is fully closed start-up oil and auxiliary start-up oil are generated which reset stop valves and trip device respectively. Thus trip oil pressure increases and resetting the turbine. • Soaking : Once the above condition is achieved, soaking of turbine is done by selecting “HEAT SOAK” from the desk. In ATS mode Heat Soak is automatically selected. This raises the set point to 1080 rpm at a rate depending on the mode of operation. If under certain conditions metal matching conditions are not satisfied a hold signal will be generated which will not allow the turbine to increase the speed. There is another feature called the Run Down operation. It takes care of the fact turbine speed increases above a certain rate to avoid unnecessary vibrations during critical speeds. If the actual rate of increase of speed falls below 100 rpm/min during rolling from 400 rpm to 1080 rpm , this action will be triggered and the turbine will be brought down to turning speed. The turbine is kept at soaking speed depending on the mode of rolling. • Rated :

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After necessary soaking, “RATED” is selected from the desk which brings the turbine at rated speed i.e. 3000 rpm. There are three critical speed zones : (a) Range – 1 : 1260 – 1610 rpm. (b) Range – 2 : 1710 – 2185 rpm. (c) Range – 3 : 2295 – 2800 rpm. If the rate of speed increase falls below 100 rpm/min during these critical speed zones Run Down becomes active and turbine is brought down to soaking speed. 2. HARDWARE : The speed is sensed by three hall probes mounted on bearing 1 of the turbine. They generate pulse signals which are fed to Pulse Input Cards in the PLC. They are converted into corresponding digits by these cards which are used by the processor for processing. The mean value of the three signals are taken and the deviation from the set point generated from the speed secondary setter is processed by a PI control loop to give appropriate signal to the E/H converter.

Speed setter generates required set points which are fed to the speed secondary setter which determines the rate of change of speed set points according to the selected rate of change of speed. 3. INTERFACING OF GOVERNING WITH AUTOSYNCHRONISER : The EHG system is interfaced with the autosynchroniser. The autosynchroniser gives speed raise or lower command to the speed setter according to the beat frequency sensed by the autosynchroniser. The speed of the turbine increases or decreases according to the command. 4. MAIN ELEMENTS OF SPEED CONTROL : 4.1. Speed Setter (65F) : Turbine speed can be set by the following ways :• Turbine speed setting from the ATS system. • Manual turbine speed setting. • Turbine speed setting by automatic synchronization system (ASS). • Automatic setting operation according to the other conditions. Turbine Speed Setting From The ATS System : This setting is done by supplying a heat soak turbine speed command and a rated turbine speed command and target speed commands (pulses) at automatic start up of the turbine. When one of these commands is applied, the speed setting increases the speed up-to the target value according to the predetermined stroke time (refer to Table.1). but the actual turbine speed is increased at a change rate based on the starting mode by a secondary speed setter.

Manual Turbine Speed Setting :

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There are two methods of manual setting. One is by target speed PB on the insert panel in the unit control room. The other is by 7-65F (raise/lower by PB) in the unit control room which are used for the manual synchronizing operation and for the over speed test etc. The set value is indicated by the setter position indicator in the unit control room. Turbine Speed Setting By ASS : The signal from ASS is connected to the speed setter for matching the turbine-generator speed with the system frequency for the purpose of synchronization with grid. Automatic Setting Operation According To Other Conditions : • The speed setter is returned to the lower limit value (0 rpm) for restart when the turbine is tripped. • When the turbine speed increase rate becomes under the preset value, the speed setter is run down to heat soak speed in order to avoid stopping at critical ranges. • After closing the main circuit breaker, the power controller is turned on automatically and the speed setter is held at the rated speed. 4.2. Speed Change Rate Setter (65 Fd) : The speed change rate setter limits the turbine speed increase according to the turbine start mode. It activates the secondary speed setter. The speed change rate setting is done in the following ways :• Speed change rate setting from ATS. • Manual speed change rate setting. Turbine Speed Change Rate Setting From ATS : This setting is done via a selected start mode at automatic start-up of the turbine. When the starting mode is selected, the change rate setter is automatically set at the predetermined hange rate for each mode.

Manual Speed Change Rate Setting : The turbine speed change rate is set by selecting one of the predetermined change rates in manual mode. 4.3. Secondary Speed Setter : A buffering action is performed so that the setting change of speed setter (65F) is kept within the allowable change rate of the turbine. Speed Change Rate Limiting : The secondary setter is activated by the speed change rate setter to determine the change rate. In the secondary setter, raise command from the primary speed setter (65F) is limited by the change rate from 65Fd and then the turbine speed is up to the speed given by 65F with the change rate given by 65Fd. The mutual relation between the speed setting (65F) and the speed change rate setting (65Fd) is shown in the following Fig.

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Quick Balance (not in use of change rate limiting) : The quick balance is a function for automatically removing the change rate limiting circuit. The integral time constant of the speed setter (65F) & speed secondary setter is decreased, practically this circuit is excluded. The condition is as follows : • Turbine trip (Emergency trip circuit switch – off ). Turbine Speed Setting Hold : The turbine speed is held on the following condition, but not within the critical speed. Either ON or OFF of HOLD function is selected, are used in order to block or release the speed secondary setter. This function is used just in testing of turbine and also used for power secondary setter. 4.4. Turbine Speed Increase Rate Monitoring Circuit (65F rundown circuit) : In order to avoid interference with the turbine speed in the critical speed range, where a critical speed exists in the process of turbine speed increase, the turbine speed increase rate is monitored, and when the increase rate is below a defined rate, the turbine speed setting goes to heat soak speed automatically and then the turbine speed is rundown to the heat soak speed accordingly. This function is considered for the trouble of boiler pressure control fault, the bypass valve control fault etc. 4.5. Over Speed Test : Over speed test is done by raising the speed setter manually (7-65F) after the over speed test “ON” is selected by key switch in the unit control room. C.2. POWER CONTROL : 1. OPERATION : The power controller ensures smooth loading of the turbine. It is active when the Generator Circuit Breaker (GCB) closes. Various features are incorporated in this controller which includes : • Initial Load Concept. • Governor Free operation. • Limiting Pressure Control (LPC). • Frequency Influence. • Interfacing With Coordinated Master Control. 1.1. Initial Load Concept : When Generator is synchronized the power set point automatically becomes 5% of the rated load i.e. 10.5 MW. Since the turbine goes on power control with an initial load of 10.5 MW, this ensures that generator never goes on motoring which was one of the synchronization problems. It should be noted that this set point goes directly to secondary setter, hence no influence of rate is present. 1.2. Governor Free Operation : In the Governor Free operation turbine responds directly with speed even though the turbine is on power control mode. In Bk.T.P.P. the Governor Free has a droop of 4.5%. The present dead band of this circuit is 0%, i.e. loading and unloading of machine starts just as it crosses 50 Hz. However this is a variable quantity and can be changed as desired. The droop and the maximum load change can also be changed as desired. Presently the maximum load change from Governor Free operation is 50% i.e. 105 MW. The response of the load change can be controlled by proper setting of time constant for an integrator circuit.

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When the grid frequency variation is large, the Governor Free operation is very difficult because of large variation of load changes. 1.3. Limiting Pressure Control : If due to certain abnormal condition the pressure of the system falls, a control system reduces the load to a certain extent to control the pressure. This type of pressure control within the power control is known as Limiting Pressure Control. Here it should be mentioned that LPC can be switched on only if the turbine is on power control. In Bk.T.P.P. load rejection starts if pressure falls below 10% of the limiting pressure setting and total 21 MW load rejection take place when the pressure deviation becomes more than 20% of the set point.

1.4. Frequency Influence : There is a proportional controller whose value depends on the speed deviation and which directly influences the power controller. The purpose of this controller is to decrease the load at high frequency. Here it must be mentioned that Governor Free operation does not have dead band and it is mainly a frequency controller. But the Frequency Influence circuit within the power controller restricts turbine loading at high frequency. Unlike the governor free operation this circuit always remains active when power controller is ON. Initially a dead band of 1.5 Hz was present but now this dead band has been increased to 3.5 Hz.

1.5. Interfacing With Coordinated Master Control : Under CMC mode of operation the power controller becomes active and load set point is given by the unit load set point of the CMC circuit. The secondary power setter tracks the unit load demand set point. In this mode of

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operation the rate of load change is determined from the CMC circuit and secondary power setter has no influence under CMC. Thus the turbine maintains load according to the demand from the CMC. 2. FINAL OUTPUT OF THE POWER CONTROLLER : As discussed above the final set point for the power controller is influenced by the Governor Free Control, Limiting Pressure Control and Droop Control (Frequency Influence).

3. MAIN ELEMENTS OF POWER CONTROL : 3.1. Power Setter (65P) : Turbine output power is set in the following ways : • Power setting from the ATS • Manual power setting via 7-65P (Raise or Lower P.B.) • Power setting from the unit coordinator control • Automatic setting operation according to other conditions The set value is indicated on the power setting indicator in the Unit Control Room, and the actual load is indicated on the output power indicator in the UCR. Power Setting From The ATS : This setting is done by supplying the initial setting (0%) command, and the 20% power command at ATS. When these commands are applied, the power setter increases or decreases to the target value according to the stroke time. The actual power under ATS is controlled at a change rate based on the starting mode by a secondary setter. Manual Power Setting : It is accomplished by use of the 7-65P (PB) installed in the UCR in case of not using the ATS system or voluntary setting by operator. Power Setting From The Unit Coordinator : On the coordinated mode (ALR mode) the demand signal from the unit coordinator is applied to the power setter. Automatic Setting Operation According To Other Conditions : The power setter is returned to the lower limit value (0%) for restart when the turbine is tripped. Automatic follow up of 65P. Power setter (65P) is automatically following the actual load during the initial pressure mode operation or Run Back ON. 3.2. Power Change Rate Setter (65Pd) : When the power controller is on operation, the excessive load variation is set by the power change rate setter (65Pd). The power change rate setting is done in the following ways :• Power change rate setting from the ATS. • Manual power change rate setting. The set value is indicated on the indicator in the Unit Control Room.

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Power Change Rate Setting From The ATS : This setting is done via the selected start mode at the automatic start up of the turbine.

When the starting mode is selected, the change rate setter is automatically set at the predetermined change rate for each mode. Power change rate of load down is also set automatically to 3% /min by ASD. Manual Power Change Rate Setting : This setting is done by 7 – 65Pd (raise or lower PB) in case of not using the ATS/ASD system or normal operation. 3.3. Limiting Circuit According To Wall Temperature Monitoring (WT) : This system affects the secondary speed setter and the secondary power setter to limit the speed change rate and power change rate for keeping the temperature difference (the wall stress) within allowable limits. This wall temperature monitoring system (TSC) is installed in DCS supplied by BHEL, is capable of switching ON or OFF in the UCR. 3.4. Secondary Power Setter : A buffering action is performed so that the setting change of the power setter (65P) is kept within the allowable change rate of the turbine. Power Change Rate Limiting : The power secondary setter is activated by the power change rate setter (65Pd) to determine the change rate. The signal of the limiting circuit via the wall temperature monitoring (WT) also activates the secondary power setter to limit the change rate as necessary. The secondary power setter has a step component. When the wall temperature monitoring (WT) is not limited, the power variation ratio is as follows : Sustained component : MW/min. Step component : Approx. MW (two different setting values are applicable, one for loading and one for unloading). The mutual relation between the power setter (65P) and the secondary power setter (65Pd) and via the wall temperature monitoring circuit (WT) is shown in the following Fig.

Quick Balance (not in use of the change rate limiting) : The quick balance is a function for automatically excluding the change rate limiting circuit. The integral time constant of the power change rate setter (65Pd) is decreased, practically this circuit is excluded. The conditions are as follows : • Turbine trip • Pressure control – ON.

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Power Setting Hold : The power setting is held on the following conditions :

3.5. Electrical Load Limiter (77E) & ALFC : Electrical Load Limiter can be used for sudden decrease of load during emergency conditions. Electrical Load Limiter works in association with ALFC or Automatic Load Limiter Follow Up Control which is activated above 82 MW. If ALFC is ON then the Electrical Load Limiter tracks the controller outputs (valve position) with a 10% higher value. This tracking is done at a certain rate controlled by the Load Limit 2ndry setter. During ALFC this rate is 33%/min. Thus this also ensures that no sudden increase or decrease of load changes take place under any abnormal conditions.

4. AUTO FOLLOW UP OF MECHANICAL GOVERNING : This circuit makes the Speeder Gear to follow the Electro-hydraulic Governor at a value above 5% of the valve position of the E/H Converter. A function generator makes the 65M position with the EHC valve position.

Due to large variation of grid frequency at the commissioning period the auto follow up circuit was not functioning properly at Bakeswar and hence the normal practice here is to keep 65M at 100% . MHG droop curve changes as 65M is lowered and if there is a fluctuation in frequency it may so happen that MHG sometimes come into action which is undesirable. The disadvantage of this that if due to certain reason the EHG fails, the control valves will suddenly go to 100% causing accidents and damage in certain conditions.

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C.3. PRESSURE CONTROL : There is a pressure controller within the EHG system which maintains constant pressure at HP turbine inlet. The pressure setting value is given from the CMC desk. This controller becomes active only in the Turbine Follow Mode (TFM). In this mode the EHG is in AUTO and no set point for load can be given. The power controller tracks at 5% higher value i.e. 10.5 MW higher than the original load. If due to certain reason the pressure controller output reaches a value below 50% , then the output is limited to 50%. In this condition the pressure controller will not work properly. This is done to ensure that boiler has sufficient energy to give desired load.

C.4. VALVE POSITION CONTROLLER : 1. OPERATION : All controller output is finally fed to the valve position controller which controls the opening of the control valves. This is a PI Controller.

If Generator Circuit Breaker is opened then speed controller is always active. The output of the speed and power controller is fed to an adder circuit. When GCB is closed output of the speed controller becomes zero and power becomes active. The output of this and pressure controller output is fed to a Low Value Selector. When pressure control is not selected the output of this controller is 100%, thus the power controller becomes active. If we select the pressure control then the power control output tracks the load at a value 5% higher than the actual load thus pressure controller output is selected for the control. A logical diagram above describes the operation. 2. HARDWARE : The valve position controller gives command to the EHC. The output card generates a voltage of 0-10V which is used for lifting the pistons within the EHC. If 0 voltage is applied to the EHC the piston is lifted and the auxiliary secondary oil pressure is maximum leading to

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opening of control valves. At a voltage of around (-) 5.5V the lift is 0% and the auxiliary secondary oil pressure is negligible leading to closing of control valves. C.5. STARTING DEVICE & SPEEDER GEAR FOR EHG : The starting device or 77M is used as a mechanical Load Limiter and also to generate start up oil for resetting the stop valves and auxiliary start up oil for resetting all trip devices. Control oil is the main source of start up oil. This oil is generated when the starting device is brought to 0%. If all trip conditions are removed the turbine resets when starting device goes to 0% as trip oil pressure becomes available once Emergency Trip Device is reset. Under normal operation the starting device is kept at 100%. However this can be used to decrease load as this also acts as the mechanical load limiter.

Thus for EHG starting device is used as the resetting device. Speeder gear or 65M is the mechanical governor and we can control the load when MHG is selected. If auto follow up feature is selected then this follows the E/H valve position with a 5% higher value. Otherwise the normal practice is to keep it at 100% so that Mechanical Governor does not influence the EHG system. One thing must be mentioned here that 65M has certain droop characteristics and this droop depends on frequency.

Above figure shows the droop characteristics of 65M. Presently MHG droop is set at 7.5% and turbine can generate 210 MW without the influence of 65M droop up to a frequency of 51.75 Hz. This should be noted that this is the case when 65M is 100%. If 65M position is decreased, the droop characteristics will also fall parallely i.e. at 75% 65M position we can supply 210 MW at relatively lower frequency. If there is a frequency fluctuation and auto follow up of 65M is made ON then there may be a position where 65M falls below EHG command and Starting Device 0% comes into action which may be undesirable. So for smooth running of 65M we should maintain a constant grid frequency. (D) MECHANICAL HYDRAULIC GOVERNING (MHG) 1. INTRODUCTION : The turbine generator is equipped with an electro-hydraulic governing system (EHG) backed-up mechanical hydraulic governing system (MHG). Under normal operation mode EHG is used, however, in case of any fault with EHG, transfer of control to MHG will be done seamless. And then the MHG will continue to operate the turbine unit, but manually, that is, automatic operation such as automatic turbine start-up and shutdown system (ATS) is not available for the MHG system. The MHG system operates the EHC with oil pressure. When the electrical system is not used, this oil pressure is directly fed to the oil servo system for controlling the control valves. For the EHG system, the oil pressure from the MHG system is adjusted in the EHC by using electrical signals from the valve position controller, then the oil pressure is fed to the oil servo system. Therefore, the output oil pressure of EHC can never exceed the control oil pressure from the MHG system. In other words, the

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oil pressure from the EHC depends on the signals from the EHG or MHG system (whichever is lower). Since the oil servo system performs P action, a linear relationship is established between the output oil pressure of the EHC and the opening of the control valves. The MHG system consists of a mechanical speed setter (65M) and a mechanical load limiter (77M). In the case of EHG operation, 65M will be in auto follow up with EHG keeping a constant width in order to change over to MHG system seamless in EHG system failure. After changing to MHG system, control valves position will be adjusted by the 65M manually, if necessary. 2. OPERATION OF MHG : 2.1. Mechanical Speed Setter (65M) : The 65M can be operated by any of the following ways :• Automatic follow-up command from EHG panel • 7 – 65M (Raise/Lower) PB in central control room • Hand operated device in local • Automatic position reduced by width of follow up at EHG fault In the normal operation by the EHG system, the 65M will follow the EHG at a constant width higher points than the EHG, so that turbine operation can be changed over to the operation by the MHG system without sudden change in the case of EHG failure. Owing to the automatic follow-up function, the motor for 65M is connected to the AC power source via the static relay. The 77M is composed in the same way although without automatic follow-up function. 2.2. Mechanical Load Limiter (77M) : The 77M can be operated by either of the following ways :• 7 – 77M (Raise/Lower) PB in the central control room • Hand operated device in local 3. SWITCH OVER DURING LOAD OPERATION : 3.1. EHG To MHG :

3.2. MHG To EHG :

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4. SWITCH OVER DURING OFF LOAD OPERATION : 4.1. EHG To MHG :

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4.2. MHG To EHG

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5. SWITCH OVER DURING TURNING OPERATION : 5.1. EHG To MHG :

5.2. MHG To EHG

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(E) TURBINE PROTECTION DEVICES The turbine is equipped with following protection devices in order to stop the turbine immediately when it is subjected to a failure. The following protection devices can be tested when the turbine is on – loading operation. (Refer to the “Turbine hydraulic governing diagram”). 1. EMERGENCY TRIP DEVICE : The emergency trip device (2.1) is automatically actuated in an emergency by the operation of releasing device for emergency governor (1.3.1) and the thrust failure protection device (1.5), and can be manually actuated by operating of the emergency trip lever (2.2). As a result, the main stop valves (5.1), the main steam control valves (6.1), the reheat stop valves (7.1) and the intercept valves (8.1) are closed immediately and the turbine is stopped. The control oil from the main oil pump (1.1) is supplied as trip oil for stop valves and secondary oil for the control (intercept) valves through the emergency trip device (2.1). The emergency trip device cuts off the trip oil circuit in an emergency and the trip oil drains into the oil tank. Then, the main stop valves (5.1), the main steam control valves (6.1), the reheat stop valves (7.1) and the intercept valves (8.1) are closed immediately and shut off the steam supply into the turbine. The changeover valve of the emergency trip device (2.1) is of the differential piston type in which its position is determined to balance the spring force and predetermined aux. trip oil pressure. When the aux. trip oil pressure is lowered by operation of protection devices that are connected to aux. trip oil circuit, the emergency trip device is actuated automatically. 2. SOLENOID TRIP DEVICE : Two solenoid trip devices (43.1.1 & 43.1.2) are provided for the turbine auto stop or manually from control center, and are installed on the control oil circuit to the emergency trip device (2.1) and cut off the control oil circuit. 3. EMERGENCY GOVERNOR : Two emergency governors (1.3) actuate the emergency trip device (2.1) via the releasing device (1.3.1). The operation test of the emergency governor can be performed by mans of the oil trip test device (1.6) even when the turbine is on – loading operation. This turbine has two emergency governors to protect the turbine from over – speeding. 4. THRUST FAILURE PROTECTION DEVICE : The thrust failure protection device (1.4) is actuated when the turbine rotor has been displaced axially beyond the allowable limit. Operation of thrust failure protection device actuates the emergency trip device (2.1) via the releasing device (1.5). 5. VACUUM TRIPPING DEVICE : The vacuum tripping device (2.3) is actuated when the pressure in condenser exceed its allowable limit. Operation of vacuum tripping device actuates the solenoid trip devices (41.3). STOP VALVES’ ACUTATORS: (fig-5) The stop valves’ are opened hydraulically and closed by spring force. The mechanism consists of a plunger (44), springs (45, 46), spring seat (42), and piston (38), which is contained within the cylinder (43). The piston (38) is mounted on the connecting rod (37) that is connected to the valve stem (8). To open the valve, pressure oil from the trip oil circuit is admitted through connection ‘W” to the space above plunger (44). The plunger (44) is forced against the piston (38), compressing the springs (45, 46). The contained in the plunger can now escape through connections ‘X’ & ‘C’. By reversing the oil flow, trip oil is admitted through connection ‘X’ to the space below the piston (38) against which the plunger (44) is bearing. The plunger and piston are then lifted together and the valve is moved to its open position. When the trip oil pressure drops below a predetermined value for any reason (such as tripping the turbine) the spring force separates the piston from the plunger. As the area below the piston (38) is depressurised, the springs (45, 46) cause the valve to close rapidly. Any oil under the piston that does not escape through connection ‘X’ flows into the open area occupied by the springs. During this action the plunger (44) remains in the upper end position. Actuator arrangements for all the stop valves are almost same. From the above discussion it is clear that the ultimate target to trip the Turbine is to drain trip. TURBINE RESETTING, START UP AND LOADING:

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Going back to the fig (1), the assembly at the left hand side of the speeder gear is called the Starting and Load Limiting Device. C8 is the pilot valve responsible for different ports opening. And closing. The lever connected in between the starting device and the bottom of the speeder gear bellow C1 causes load limiting action. The pilot valve can be moved upward and downward by operating the manual wheel at the top of the starting device or by the electric motor mounted there. Turbine resetting: First, the speed setter (Speeder Gear) is positioned at the lowest position. Turbine is already in tripped conditions, i.e. trip oil pressure is zero, and main stop valves and control valves are in closed position. Now, by rotating the control wheel at the top of the starting device clockwise (or the motor is operated in the ‘Closed ‘ direction) moves the pilot valve (C8) downward causing the lower most horizontal lever movement downward at the starting device end and upward at the speeder gear end. So the lever pushes the bellow of the speeder gear upwards, causing an upward movement of the lever (C3). So, the sleeves of the aux. follow-up piston move upward, causing loosing the force of the follow-up pistons. By this operation, any pressure can not be produced in the aux. secondary oil circuit (as drains of aux. follow-up pistons are full open), thus, Electro-hydraulic Converter with follow-up pistons is set at the closed position of the control valves, that is, even if ETD is reset, any pressure can not be produced in the secondary oil circuit. Further downward movement of the pilot of the starting device allows control oil through the port ‘a’. Control oil then goes into the start-up oil circuit and into the aux. start-up oil circuit through port u and u1 respectively. Aux. start-up oil goes to the ETD and lifts the pilot which closes the drain port, opens the control oil port and connects it to trip oil and aux. trip oil lines. Thus trip oil and aux. trip oil is generated. This is called turbine resetting. Aux. start-up oil goes to the thrust failure trip device and to the emergency governor also and closes the drain ports via their plunger movements (if the tripping was caused by them). Start-up oil is used to reset the stop valves. It goes to the test valves fig (3) of the stop valves. Through test valves, trip oil can go to the top of the stop valves, plunger or at the bottom of the stop valve piston. Through the ports ‘a’ and ‘v’ trip oil enters the test valve, port ‘w’ is connected to the top of the plunger of stop valve and port ‘x’ is connected to the bottom of the piston of the stop valve. Start up oil pushes the change over valve (test valve) downwards and connects trip oil path to ‘w’. Meanwhile, aux. trip oil reset the ETD and generates trip oil pressure. So, trip oil goes to the upper portion of the plunger of the stop valve and pushes it to compress the spring until the plunger reaches the piston. Now, stop valves are closed but go ready for fast closing. So valves are rest. Now, Turbine is ready for start-up. TURBINE STARTUP: After resetting turbine with both the speeder gear and starting device positions at the minimum, now starting device is started operating in the ‘open’ direction. The piston of the starting device moves upward resulting in draining of control oil from the aux. Start-up oil circuit and from start-up oil circuit. Pistons of the test valves of the stop valves started moving upward by the spring force as the start up oil pressure from the top is released. This incident causes trip oil connection to ‘X’ port of the test valve, i.e. trip oil goes to the space below the pistons of the stop valves and simultaneously trip oil from the top plungers begin to drain off slowly. So the pressure difference moves the piston and the plunger (in contact with each other) to the upper limit position. This operation makes all main and reheat stop valves be opened fully. Now, further upward movement of the starting device piston, the horizontal lever at its bottom lowers the lever C3 followed by lowering of the sleeves of the aux. Follow up pistons, minimization of drainage there and building up aux. Secondary oil pressure. The aux. Secondary oil then generates secondary oil via Electrohydraulic converter. Secondary oils open respective control valves, steam flows into the turbine and turbine speeds up. After the turbine speed reaches up to 94% of the rated speed, the hydraulic speed governor (by primary oil) is in working order and keeps turbine speed constant.

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Starting device is kept at ‘fully opened’ condition. Then the speed is raised by increasing speeder gear position. After synchronization, increasing speeder gear position will increase steam flow to turbine, but instead of speed raising load is raised. LOAD LIMITING: Starting device has other features of load limiting. If it is not opened fully during on-load operation of TurboGenerator set, then the horizontal connecting lever (connected to the bottom of it) will give a pretended force to move C3 lever in upward direction, which will restrict the drainage through the aux. follow-up piston drain even if the speeder gear position insists full load by minimum drainage. Thus the load can be limited by starting device. Hence it is called starting and load limiting device. LOAD – FREQUENCY RELATIONSHIP AND GOVERNING SYSTEM: All the synchronous machines connected to the GRID operate at synchronous speed i.e. at the grid frequency. Grid frequency interprets the mismatch (if any) in between energy input to it and energy output from it (i.e. connected load). When the demand (output) is lower than the total generation (input), that excess energy is converted to kinetic energy added to all rotating machines (generator or motor) by increasing their speed. Thus the grid frequency increases. On the other hand, if the demand is greater than the total supply, kinetic energy of all machines reduces to convert a portion of the kinetic energy to supply the additional power demand. If the mismatch started increasing, the GRID may collapse. Moreover, high frequency operation means wastage of power. To minimize this system of automatic load rejection of the Turbo generators with increasing frequency is required. Governing system provides this facility. This is just like the speed control stated earlier. During on load operation, if frequency rises, turbine speed increases, which increases the primary oil pressure which pushes the bellow of speeder gear upward followed by upward movement of C3, increased drainage, decrease in auxiliary secondary oil pressure, secondary oil pressures, control valves positions and thus decrease in load. But, grid frequency may vary within a safe range, which is harmless. This healthy situation too, may cause load fluctuation due to the governing action. So a dead band is introduced so that, within a safe frequency margin, load variation will not occur, but above that load will be reduced linearly with frequency increment. This dead band is introduced by increasing the spring tension of the speeder gear. The additional spring tension insists more primary oil pressure (i.e. more turbine speed) to overcome that pressure to give C3 a net upward movement. Beyond 51 Hz load is started decreasing linearly with frequency increase and the machine is completely unloaded at 53.5 Hz. 50 Hz - 51 Hz is the dead band. So the droop of the Governor = (53.5 – 51) / (50) x 100% = 5%. LOAD SHEDDING: Sometimes it may happen that Generator circuit breaker opens due to some fault in the downstream of Generator, but steam enters turbine. This will cause high acceleration of the rotor. Though speed governor will start acting, but, the process is slow (as designed for taking up of little bit fluctuation). Hence during this type of situation, turbine may go for over-speed, which is very much dangerous. To avoid this, instant unloading of turbine is required. To make the problem more generalized, whenever there is huge mismatch in between steam flow and generated MW, this type of instant unloading is required. To do this load shedding is done. The relay, called load-shedding relay detects the high rate of load changing and operates and transmits signal to solenoid valves kept in the governing oil line. Two numbers of such solenoid valves are there, one is placed at the auxiliary secondary oil line and the other is provided at the secondary oil lines going to control valves of IP Turbine. Whenever they get signal from load shedding relay, they open the drains, and auxiliary secondary oil and secondary oil to IPCV drain immediately. As a result IP turbine control valves closes immediately and other control valves closes at small delay. Thus rapid unloading of turbine happens (no steam flow for instance). At the same time, reheat check valve, extraction check valves are also closed by solenoid valves through pressure switches operated by secondary oil pressure. In an adjustable short time, solenoid valves for load shedding relay close and secondary oil pressure are produced again corresponding to the new load. FREE GOVERNOR MODE OF OPERATION ****************************************** 1. Introduction :

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The Regional Grid Operation is a very complicated exercises where different players namely Generating Company, Transmitting Company and Distribution Company work in synchronism along with each other to maintain different operating conditions and parameters namely frequency, voltage etc. In this operation, even the smallest entity has a definite role to play. Different exercises have been carried out to identify the role of individual player in Grid Operation. Indian Electricity Grid Code (IEGC), draft legislation on Electricity (Electricity Bill 2001) etc. are the recent forms of this exercises. Most of these documents identify the procedures and parameters at the macro level which have to be essentially maintained by individual player to operate the healthy grid. However, at the macro level where each individual entity is connected with the grid, exception of either side is not very clear and most of the operations are done on the basis of individual interpretation of different macro guidelines. Thermal Power Plants have got a distinct role in the Grid, as envisaged during their inception. The Free Governing Operation has been made compulsory for all the generating units in Section 6.2 (e) of IEGC. As envisaged all the machines shall operate with no predetermined mechanism to block the governor response to frequency change as per droop characteristic of the particular machines. It implies that in case of any drop in frequency, say by 0.1 Hz, free governor action shall open the control valves, all the machines as per individual droop characteristic till the normal frequency is achieved. Similarly in case of rise in frequency, control valves will continue to close till the normal frequency is achieved. Free Governor Operation is basically envisaged for modulating the frequency with minor correction of frequency on real time of operation and also to take care of any major frequency fluctuations due to sudden outage in load of Generator. Free Governor system is not designed to control the frequency of the whole region. In case of Eastern Region, Power No. is 200 MW approximately i.e. for sudden increase or decrease of 200 MW load , grid frequency shall change by 1.0 Hz. A rough calculation shows that with all the machines of free governor a change of 1.0 Hz in ER Grid frequency, the effect on 210 MW machine is around 5.0 MW. However, in real time operation, frequency is not a steady phenomenon and it consists of continuous undulation. Band of maximum and minimum of which varies from Region to Region. Accordingly, the governor system shall continue to operate the control valves. As envisaged in unit load dispatch guidelines, every time the governor changes the MW output of the machines which the machine is supposed to deliver on sustainable basis. The machine must return to the specified value after participating in frequency response. Such operation is also permitted within a very narrow frequency range. In case of high frequency (say > 50.2 Hz), restoration to prior value is not permitted. Keeping in view o all the above factors, the secondary control mechanism plays a very important role in the free governing operation. 2. The Objective Of Free Governor Mode Of Operation : The main objective of Free Governor Mode of Operation are as follows : To arrest the transient swing in grid frequency. To maintain National Grid frequency within IEGC declared band o 49 to 50.5 Hz. Free Governor operation allows the machine to load or unload depending upon whether frequency is lower than 50 Hz or more than 50 Hz respectively. Variation in Grid Frequency can be minimized by putting all the Generating Stations on Free Governor Mode of Operation. The Free Governor Mode of Operation is free to governor as per its regulation droop characteristic. There is no constraints imposed on it like – i) Valve kept wide open. ii) Frequency influence switched off. iii) Dead band of frequency influence. iv) Time delays. v) Lower and upper set point on load limiter is hand up used. Droop Characteristic : It is defined as the change in steady state speed expressed in percentage of rated speed when the output of the turbine is gradually reduced from rated power down to zero power with identical settings of all elements of the speed governing system. In hydraulic control mode (MHG) these are inherent in the Governing system as the system acts to control speed. In Electrical Controller (EHG), these are built up through frequency influence on load set point as the system acts to control load. When most of the machines in the Grid are in FGMO, changes in frequency are not expected to go beyond 0.25 Hz (with 10% peak load storage). This will call for load changes of maximum 10% only. Theoretically, 10% load changes (up to VWO load) can be undertaken by the

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turbine without any undue stresses, when it is under steady state operation. However, the TSC data is to be collected when the machine is on FGMO mode to evaluate the effected of such load cycling on machine life.

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Fig-5 STOP VALVE ACTUATOR 357


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TOTAL GOVERNING SYSTEM COLOUR DIAGRAM IS GIVEN AT SEPARATE PAGE Ref. No. 1.1 1.2 1.3.1 1.3.2 1.3.4 1.4 1.5 1.6 1.6.2 1.6.3 1.7 1.9 1.18 2.1 2.2 2.3 2.5 3.1 3.2 3.3 3.4 3.5 3.6 3.7 3.8

Description : Main Oil Pump : Governor Impeller Emergency Governor (1) : Emergency Governor (2) : Releasing Device for 1.3 : Thrust Failure Protection Device : Releasing Device for 1.4 : Oil Trip Test Device : Reset Device : Lock out Device : Control Oil : Electrical Speed Transmitter : Control Oil Filter : Emergency Trip device : Emergency Trip Lever : Vacuum Trip Device : Change over valve for ATT : Speed Governor : Governor Bellows : Speeder Spring : Lever : Sleeve : Piston : Spring : Speed Setter

Ref. No. 6.1.1 6.1.2 6.1.3 6.1.4 6.2 6.3 6.4 7.1.1 7.1.2 7.2 7.3 7.4 8.1.1 8.1.2 8.2 8.3 8.4 17.1 17.3 18.5 18.10 20.1 40 41 41.1

: : : : : : : : : : : : : : : : : : : : : : : : :

3.9 3.10 3.11

: Changeover Valve : Starting and Load Limiting Device : Over speed Test Device

41.3.1 41.3.2 41.20

: : :

3.20 3.21 3.32 3.25 3.50 3.51 3.52 3.53 5.1.1 5.1.2 5.2 5.3 5.4 5.5

: : : : : : : : : : : : : :

42 43 44 45 50.1 50.4 50.5 50.8

: : : : : : : :

Auxiliary Follow-up Piston Follow-up Piston for MCV Follow-up Piston for ICV Follow-up Piston Electro-hydraulic Converter Moving Coil Differential Transformer Proportional Band adjustment Main Stop Valve –L Main Stop Valve –R Test Valve Plunger Piston Steam Strainer

Description Main Steam Control Valve-1 Main Steam Control Valve-2 Main Steam Control Valve-3 Main Steam Control Valve-4 Servomotor Pilot Valve Piston Reheat Stop Valve- L Reheat Stop Valve- R Test Valve Plunger Piston Intercept Valve- L Intercept Valve- R Servomotor Pilot Valve Piston Reheat Check Valve Air Cylinder Extraction Check Valve Air Cylinder Condenser Pressure Switch Solenoid Valve Solenoid Valve for Control Oil Supply during Test Solenoid Trip Device-1 Solenoid Trip Device-2 Solenoid Valve for Load Shedding Relay Limit Switch Pressure Gauge Electric Position Transmitter Motor Boiler Reheater Turbine Generator

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51 AUTOMATIC TURBINE RUN-UP SYSTEM

INTRODUCTION A successful start-up of the turbine normally requires collection and analysis of wide variety of information pertaining to various parameters like speed, temperature, and pressure and warm-up condition of turbine. Apart from this, it is important to see whether vital auxiliary equipments are in automatic control loop or not. It is an enormous task for the operation-engineer to collect and handle so many information correctly and swiftly. ATRS performs this task swiftly, accurately and at the appropriate time reducing chances of mal-operation due to error and improper judgment.

MODE OF OPERATION ATRS is based on ‘Sequential Group Control’ philosophy, which means the entire logical steps are arranged in a proper sequence. Prior to the commencement of any step, it is necessary that certain conditions regarding status of plant get fulfilled and the relevant parameters acquire the desired value. All these preconditions are meticulously planned for each next step and demanded from the system to move ahead stepwise. The entire run up can be handled in basic 3 modes, namely manual, semi-auto and auto mode. As the name suggests in manual mode each step is advanced only when the operator wants and issues a command for it. In the semi auto mode the sequential logic runs automatically when the start command is issued, however in between the steps operator intervention is required when speed is to be raised, unit to be synchronized and load to be raised. Because the system runs with little help from operation desk it is called semi-auto mode. In auto mode no external help is required and the turbine can be rolled, synchronized and load of 40 MW can be raised automatically. However the system being in auto or semi-auto mode if there happens to be any problem and the operator decides to hold on the rolling procedure there is provision for ATRS LOCK. If ATRS LOCK is selected then the rolling stops at the sequence in operation and advances further only if lock is removed. Listed below are the pre requisite for the start up and the stepwise procedure for ATRS

PERMISSIVES REQUIRED FOR START UP • • • • • • • • • •

No EHG heavy fault MHG mode not selected MFT (86u) not operated AVR not in manual Lub oil pressure not <1.1ksc No RUN DOWN operation No fire alarm Lub oil temp. after cooler ok & MS line drain (L/R) open. (MS-105/106) & HRH drain (L/R) open. (HRH-101/102)

Steps: 77M=0%, 65M=100%, 65F=0%, 65P=0% Speed setter on turning Drain valve master on auto Condenser vacuum not low.

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CW p/p running Gen. f/b open Turbine reset o Emergency trip dev. not operated. o Thrust bearing protection not operated. o Emergency gov-1 trip not operated o Emergency gov-2 trip not operated. o Turbine not tripped o 86T not lockout Drain valve open All stop valves (MSV, RSV) closed. All control valves ( MCV, ICV ) closed All extraction & reheat check valves closed All extraction valves closed

Wait CRH line/NRV drain CRH101 open Trip oil press. >5ksc Vacuum not low Turbine speed >60 rpm CEP running & hdr. press. Ok. HRH drain (L/R) open MS line drain (L/R) closed Cond. for MSV open(X1) temp. Cond. for MSV open (X2) press. T/G parameter not abnormal

77M > 42% o MSV (R) open o MSV (L) open o RSV (R) open o RSV (L) open o 77M > 42% MSV/MCV warming drain valve (R/L) open Condition for HPT stm. admission (X3). HP inlet stm. temp. superheat >50 deg. HP inlet stm. press. >68 ksc Cond. for IPT stm. admission (X4) Gen. condition normal Cw p/p discharge hdr press. not low. Turbine speed >60 rpm MSV metal diff. temp. normal HPT rotor differential temp. normal HPT metal differential temp. normal IPT rotor differential temp. normal T/G parameter not abnormal MSV warming drain v/v ( R/L) =25% 77M=100% MSV warm drain v/v R/L= 25%

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Speed raise permission Speed raise on Speed change rate selected ATS temp mode selected. Speed raise-1 ( heat soak)

Speed setter heat soak ATS waiting at 1080 rpm

Cond. for speed up (X5)

Speed raise-2 (rated) Turbine speed > 2950 rpm Speed setter rated

Wait ATS waiting at 3000 rpm over AC AOP off Gen. condition normal

Exciter field breaker ON Gen. voltage >90% T/G parameter not abnormal

Syncronisation permission Yes Syncronising on.

GCB closed.

Electro- Hydraulic Governing The function of the Electro-hydraulic governor is to maintain the synchronous speed under changing load/grid or steam conditions. The E-H governor is fully backed up by a hydraulic governor. However the electrohydraulic governor through measuring and processing of electrical signals offer advantages such as flexibility, dynamic stability & high sensitive exact load-frequency droop characteristics. The parameters to be controlled include speed, load and turbine throttle pressure. These parameters are fed to various control loops. The control signals so generated are fed to E-H converter to convert to hydraulic signals to operate the final control element i.e. the control valves. In true sense the speed, load, throttle pressure & frequency influence are superimposed in one control loop (valve position controller). At Bakreshwar, the EHG system is a PLC based system and works on the HDC 500 PLC System of FUJI Electric, Japan. The governing logics are programmed on “FAISES” software. This forms the main controller for turbine governing. EHG System is basically consists of following three controllers: 1) Speed control 2) Load / Power control 3) Pressure control Speed Control Operation

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The speed control of turbine is active whenever the generator circuit breaker (GCB) is open. It ensures smooth rolling and synchronization of turbine. Basically speed control maintains constant speed of the turbine according to the set point. During rolling the set point is generated automatically and the rate of speed change is selected in depending on the condition of the turbine. If turbine rolling takes place in Very Hot Mode, Hot Mode or Warm mode the speed change rate will be fast at 500 rpm/min while in cold mode the speed change rate will be slow at 200rpm/min. There are three selections available at the control desk 1) Turning 2) Soaking 3) Rated Turning In turning the speed set point is 0 rpm so no command goes to the E/H converter and all MCVs and stop valves are closed. Turning of turbine take place by the oil supplied by AOP through turning oil valves with necessary lifting by jacking oil provided by JOP. Soaking Soaking can only be selected if turbine is in reset condition. Resetting of turbine is possible only when all trip conditions for turbine are removed. Turbine resets means that all mechanical trip devices and stop valves are reset and sufficient trip oil pressure is generated. Once this condition is achieved selecting “HEAT SOAK” from the desk does soaking of turbine. In ATS mode ‘Heat soak’ is automatically selected. This raises the set point to 1080 rpm at a rate depending on the mode of operation. If under certain conditions metal matching conditions are not satisfied a hold signal will be generated which will not allow the turbine to increase the speed. There is another feature called the ‘Run Down Operation’ .It takes care of the fact that turbine speed increases above a certain rate to avoid unnecessary vibrations during critical speeds. If the rate of actual increase of speed falls below 100 rpm/min during rolling from 400 rpm to 1080 rpm this action will be triggered and the turbine will be brought down to turning speed. The turbine is kept at soaking speed depending on the mode of rolling. Rated After necessary soaking “RATED” is selected from the desk, which brings the turbine at rated speed i.e. 3000 rpm. There are three critical speed zones 1) Range-1: 1260-1610 rpm 2) Range-2: 1710-2185 rpm 3) Range-3: 2295-2800 rpm If rate of increase falls below 100rpm/min during these speeds Run down becomes active and turbine is brought down to soaking speed.

Speed setter generates required set points, which are fed to speed 2ndry setter, which determines the rate of change of the speed set points according to the selected rate of change of speed. Interfacing of Governing with auto synchroniser

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The EHG system is interfaced with the auto synchroniser. The auto synchroniser gives speed raise or lower command to the speed setter according to the grid frequency sensed by the auto synchroniser. The speed of the turbine increases or decreases according to the command. Power Control As in case of speed controller there are three power transducers, mean value of which is compared with that of load demand to generate the error for load controller. Load demand is created through the load setter and secondary setter, which determine the rate of change of load. The Power controller ensures smooth loading of the turbine. It is active when the Generator circuit breaker (GCB) closes. It is very difficult to describe the Power controller in totality; however various features incorporated in this controller includes 1) Initial Load or block load Concept 2) Governor free operation 3) Limiting Pressure Operation 4) Frequency Influence 5) Interfacing with Coordinated Master control (CMC) Initial Load When Generator is synchronized the power set point automatically becomes 5% of rated load i.e. 10.5 MW. Since the turbine goes on power control with an initial load of 10.5 MW, this ensures that generator never goes on motoring. It should be noted that this set point goes directly to secondary setter; hence no influence of rate is present. Governor Free Operation In the Governor Free Operation, turbine responds directly with speed even though the turbine is on power controller. In Bakreswar, the Governor Free Operation has a droop of 4.5% .The present dead band of this circuit is 0.5Hz. i.e. loading and unloading of machine starts just as it crosses 50.5/49.5 Hz. Presently the maximum load change from Governor free operation is 50% i.e. 105 MW.

In normal generating conditions it is very difficult to have governor free operation owing to the large variations in grid frequency, which leads to large load changes resulting in fluctuations of other important parameters in the system. Limiting Pressure Control (LPC)

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If due to certain abnormal condition the pressure of the system falls, this control reduces the load to a certain extent to control the pressure. This type of pressure control within the power control is known as Limiting Pressure Control. Here it should be mentioned that LPC could be switched on only if the turbine is on Power Control mode. In BKTPP Load rejection starts if pressure falls below 10% of the limiting pressure setting. 21 MW load rejection take place when pressure deviation becomes more than 20% of the set point.

A=+10 %( 15 Kg/cm2) B=+20 %( 30 Kg/cm2) C=-10 %( 21MW) Frequency Influence There is a proportional Controller whose value depends on the speed deviation and which directly influences the power controller. The purpose of this controller is to decrease the load at high frequency. The Frequency Influence circuit within the power controller restricts turbine loading at high frequency. Unlike the governor free operation this circuit always remain active when power controller is ON. The dead band for the frequency influence to become active is 3.5 Hz. Load Shedding Relays and House Load Operation During House Load Operation the GCB is opened and the turbine goes to speed control. The turbine at a constant frequency of 50 Hz supplies the auxiliary power for the plant. There are two Load Shedding Relays, which are activated if load rejection rate goes above a certain limit. These relays operate to protect the turbine from over speeding at that instant. Load shedding relays activate two solenoid valves. They drain the auxiliary secondary oil and secondary oil for ICVs so that all control valves closes. The relays deactivate as soon as the rejection rate falls below the set limit, and thereafter maintains load according to the given command. Interfacing with the Coordinated Master Control (CMC) Under CMC mode of operation the power controller becomes active and load set point is given by the unit load set point of the CMC circuit. The secondary power setter tracks the unit load demand set point. In this mode of operation the rate of load change is determined from the CMC circuit and secondary power setter has no influence under CMC. Thus the turbine maintains load according to the demand from the CMC. Pressure Control There is a pressure controller within the EHG system, which maintains constant pressure at HP turbine inlet. The pressure setting value is given from the CMC desk. This controller becomes active only in the turbine follow mode (TFM). In this mode, the EHG is in auto and no set point for load can be given. The power controller tracks at 5% higher value i.e. 10.5 MW higher than the original load. If due to certain reason the pressure controller output reaches a value below 50% then the output is limited to 50% .In this condition the pressure controller will not work properly. This is done to ensure that boiler has sufficient energy to give desired load.

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Electrical Load Limiter (77E) and ALFC Electrical Load limiter can be used for sudden decrease of load during emergency conditions. Electrical Load limiter works in association with Automatic Load Limiter Follow up control or ALFC, which is activated above 82 MW. If ALFC is “ON” then the Electrical Load Limiter (77E) tracks the controller outputs (valve position) with a 10% higher value. This tracking is done at a certain rate controlled by the Load Limit 2nd Setter. During ALFC this rate is 33% per minute. Thus this also ensures that no sudden increase or decrease of load changes take place under any abnormal conditions. Valve Position Controller All controller output is finally fed into the valve position controller which controls the opening of the control valves. This is a PI Controller. Selection Of the various controllers If Generator Circuit breaker is opened then speed controller is always active. The output of the speed and power controller is fed to an added circuit. When GCB is closed output of speed controller becomes zero and power controller becomes active. The output of speed controller and pressure controller are fed to a low value selector. When pressure control is not selected the output of this controller is 100%, thus the power controller becomes active. If we select the pressure control then the power control output tracks the load at a value 5% higher than the actual load thus pressure controller output is selected for the control. A logical diagram below describes the operation: -

The E/H Converter is the connecting link b/w electrical and hydraulic parts. It consists mainly of a moving coil system, sleeve and pilot valve assembly. The sleeve slides up and down on spool, changing the relative overlap b/w them. The conversion is achieved by electro-magnetically operating the plunger valve because of current flowing through the coil. Movements of plunger valve cause change in the control oil pressure either on the top or bottom of amplifier piston. The motion of the amplifier piston actuates the sleeves of follow up piston valves, causing secondary oil pressure to change. Actually the valve position controller gives command to the E/H converter in voltage. The output card generates a voltage of 0 to -10V, which is used for lifting the pistons within the E/H converter. If 0V is applied to the E/H converter the piston is lifted and the auxiliary secondary oil pressure is maximum leading to opening

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of control valves. At a voltage of around –5.5V the lift is 0% and the auxiliary secondary oil pressure is negligible leading to closing of control valves.

TURBINE STRESS EVALUATOR SIGNIFICANCE It is important to know how quickly the turbine can be started up and what changes in load can be made without over stressing the turbine components, which may result in excessive fatigue. Whenever the turbine inlet steam temperature changes, the metal temperatures follow the steam temperature with certain delay. This causes differential thermal expansion within the turbine casing and shaft & corresponding stress in the metal. Thermal over-stressing reduces the useful operation life of the turbine and its components. TSE measures and calculates relevant temperature values and determines the allowable conditions of operation limiting stresses within permissible limits.

IMPORTANCE OF MARGINS The margins are a measure of the degree of thermal stresses which turbo set can be subjected to. If the margin is consumed, this means that the component is being stressed to its permissible limit. DATA ACQUISITION AND PROCESSING The input parameters for TSC are provided by wall temperature sensors (T/C). This can measure temperature of the surface, which is in contact with steam, and mean wall temperature in the middle section of component. The wall temperature sensors have two legs and a screwed sleeve containing a measuring insert. The screwed sleeve is inserted through the wall of casing and wielded outside. The material is similar to that of casing to have good thermal contact and have similar thermal gradient. At Bk.T.P.P. the use of TSE is optional to the operation-engineer. TSC generates a hold function i.e. doesn’t allow increase or decrease of load or speed during synchronization if metal matching conditions are not satisfied. If margins fall below 10% it generates a trigger to EHG and blocks any further changes in load. Hold function is active/generated only if TSE influence is active. During start up the following parameters need to be satisfied: Metal matching conditions for parameters in calculation 1. MSV open-1 (temp) 2. MSV open-2 (press.) 3.Stm. admission . HPT 4.Stm. admission IPT 5. Speed up 6.Load raise

temp. MSV-50%, boiler outlet temp. press. MSV-50% [f (temp.)], boiler outlet pressure. temp. HPC-50%, HPT inlet stm. temp. temp. IPS-50%, HRH stm. temp. temp. HPC-50%, HPT inlet stm. temp temp. IPS-50%, HRH stm. temp.

The metal matching conditions changes with different types of start-ups and the mid wall temps are also processed for different mode of start-ups. The temperature margins that are monitored include MSV, HPC, and HPS & IPS. For this calculation purpose the surface temperatures and the midwall temperatures need to measure. However the midwall temp. for the shafts cannot be measured directly. They are derived from the surface temperatures.

CAUTIONS TO AVOID ANY TEMPERATURE DIFFERENCES 1. The drainage must be done perfectly until all turbine casing metals are heated enough. 2. At the same time drainage should be achieved in the main steam pipings, reheat steam pipings, main steam stop and control valves, intercept valves and extraction valves.

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3. The steam should be at least 50 deg superheat. 4. An extraction check valve should maintain a normal function so as to prevent any reverse flow from any feed water heater or deaerator to the turbine casing. 5. It must not be permitted to cool fast a lower part of a casing. *** *** ***

52 TURBINE PROTECTION & INTERLOCK M/s FUJI ELECTRIC, Japan has supplied the Turbine at BkTPP. It is like KWU turbine and designed by SIEMENS. . All KtPS Turbines & BTPS 210 MW Turbine are of LMW design. “Turbine Interlock & Protections “ are provided to run the turbine safely. General description: The turbine consists of three parts HP, IP, and LP. The steam supplied to the HP (high pressure) turbine through 2 nos. of stop valves (one from left & the other from right side) & 4 nos. of control valves (two from left &two from right side). The steam to the IP Turbine is through two nos. RSV (reheat stop valves, one from left & other from right side) & then through two nos. of ICV (intermediate control valves, one from left & other from right side). The exhaust from the IP Turbine is directly fed to LP Turbine. The exhaust of the LP Turbine is feed to condenser, which is physically located below the LP Turbine. The functions of the stop valves are to cut of the steam supply to turbine as quickly as possible. The control valves are primarily used for controlling action (by EHG or by MHG) of the turbine. To change the load (MW) we have to change the position of control valves thus allowing change in the steam flow. OIL CIRCUIT: Here, the philosophy is to run the turbine in normal condition by keeping a protection oil line (named TRIP OIL) in pressurised condition (>6 kg/cm2). If by any mean this oil line pressure drops down (< 2 kg/cm2) the turbine will trip. Some protection devices are directly fed with this oil & the electrical tripping through TLR (i.e. from outside) is directly connected to this line. This TRIP OIL inside the valves keeps the stop valves open against pressing a spring. As soon as the pressure drops the spring force comes pushes back the piston, thus closing of stop valves. The CONTROL OIL is produced by the turbine main oil pump (MOP) during running at speed > 2800 rpm. Before that it is produced by running AOP (aux oil pump). The resetting of turbine generates the TRIP OIL. As soon as the TURBINE RESET PB is pressed, it moves the starting & load-limiting device (77M) to 0 (minimum) positions. At this position, of 77M, the START UP OIL & the AUX START UP OIL is generated. The START UP OIL is used for resetting of all the STOP VALVES. The AUX START UP OIL is used for resetting of all trip devices. The CONTROL OIL is send through SV1 & SV2 (turbine trip solenoids, reset by electrical signal) & the ETD (emergency trip device, reset by AUX START UP OIL) to generate the TRIP OIL provided all these devices are in reset condition.

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OIL CIRCUIT

TRIPPING OF TURBINE: It can be classified into two major categories, viz a) Tripping from inside the turbine & b) tripping by TLR (TURBINE LOCKOUT RELAY), i. e. from outside of turbine i.e. electrical tripping. a) Tripping from inside the turbine:

1. Operation of Solenoid valve (TLR SOLENOID): - TLR (Turbine Lockout Relay) is the electrical

command to trip the turbine from TPR (turbine protection panel). There are two nos. of solenoids for the tripping; if at least one will operate it will trip the turbine by draining the trip oil. Two nos. are provided for better reliability of protection.

2. Tripping by ETD: - The function of the emergency trip device is to open the trip oil line in the event of abnormal condition, thereby closing the stop valves & control valves and thus shutting off the steam admission to the turbine. A hand trip device is also fitted in ETD for manual hand tripping. 3. Tripping by EMERGENCY GOVERNOR: - The emergency governor is provided to trip the turbine when its speed exceeds the allowable limit (setting 111%). By centrifugal principle, if the speed exceeds the set speed the centrifugal bolt came out overcoming a spring tension & push a projected lever which in turn drains the aux trip oil. The setting value can be changed by the adjusting bolt. 4. Tripping by Vacuum Trip Device: - A vacuum line is connected in oil ckt. When condenser vacuum drops to very low level, it drains aux. trip oil and thereby trips the turbine. b) Tripping by TLR (TURBINE LOCKOUT RELAY), i.e. electrical tripping: Electrical panel (TPR panel) Normally most of the time turbine is tripped through this panel. As mentioned above, in the field there are two solenoid valves SV1 & SV2. Normally the trip solenoids are kept without power (220V DC). To trip the turbine, we have to power the coil. As turbine trip is very vital, so here all the inputs are multiplexed into three signals (or three inputs are taken from field, where possible) for processing in three different CPU. The output is taken in duplex mode, and if at least one output mode is active it trips the turbine. The power source to this panel is also dual. One is taken from the Unit UPS & the other from Unit 220v DC. In power stations, both sources are considered extremely stable. However, in extreme emergency case, if both sources are down, one capacitor bank is entrusted to supply energy to trip solenoid to trip the turbine to ensure positive tripping.

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Electrical trip can be categorised into three major types : • Turbine itself protection tripping (turbine supervisory) • Tripping from unstable process parameters • Tripping from other sources. Turbine Supervisory 1a. Control oil pr. Very low: Taken from three nos. pr switches mounted in the control oil line. Normally in running condition the oil pr => 8 kg/cm2. If this pr drops down to < 2 kg/cm2, it is processed & trip signal is send to SVs through TLR. 1b. Trip oil pr very low: - Taken from three nos. pr switches mounted in the control oil line. Normally in running condition the oil pr => 6 kg/cm2. If this pr drops down to < 2 kg/cm2, it is processed & trip signal is send to SVs through TLR. 1c. Lub oil pr very low: - Taken from three nos. pr switches mounted in the control oil line. Normally in running condition the oil pr => 3 kg/cm2. If this pr drops down to < 0.8 kg/cm2, it is processed for 2/3 logic directly & trip signal is send to SVs through TLR. 1d. Turbine over speed: - Mechanical arrangement is illustrated before in the emergency governor caption (setting 111%). Electrical part is done by sensing the actual rpm in rpm monitor. For this two nos. of sensors are mounted in the non-rotating part of turbine & one slotted disk is rotated with the turbine rotor. The pulses from the sensors are fed to two nos. of overspeed monitors for monitoring of the speed by counting the pulses. Each monitor displays the actual rpm. If any monitor detects turbine overspeed (here setting 112%) it operates a relay, which in turn trips the TLR. A third sensor is also provided which is used to display the actual speed of turbine in control room & in screen (VPC). 1e. Axial Shift (Thrust Failure): - Done in TFPD (mechanically, by draining the AUX TRIP OIL) as described earlier. There is one thrust collar meant for measuring the axial thrust of the total turbine at brig no. 2 near the thrust bearing. The measurement represents the position of the thrust collar relative to the thrust bearing clearance. Two nos. of probes are mounted on the bearing cover looking for the gap between the collar & the stationary parts. Each probe is sensing the gap (in mm) & convert it in electrical signal (dc, varying voltage) by the proximitor (transducer) fixed at the outside of turbine. This electrical signal is processed in the AXIAL SHIFT monitor situated at the control room. The alarm values are +0.50 mm & -0.50 mm. and the trip values are +1.00 mm & -1.00 mm. The value indicates the axial shaft position relative to the axial clearance within the turbine. 1f. Shaft Vibration:This is measured in both horizontal & vertical axis. The value is 125 micron for ALARM & 250 micron for TRIP. The logic for tripping is one value should be very high ( 250 micron) & any adjacent channel to this brg. Must be high (> 125 micron). 1g. Differential Expansion:- By differential expansion of turbine means the relative movement of stator part & rotor part in running condition. It is measured in HP, IP & LP turbine differently. The trip values HP Turbine :- +5.69 mm, -3.02 mm.

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:- +8.4 mm, -2.9 mm. :- +19.2 mm, -3.8 mm.

1h. TPR system Heavy Fault:- This is mainly the health of CPU & power supply of TPR system checked. If any major deviation found, it trips the turbine (hardware logic).

2 TRIPPING FROM UNSTABLE PROCESS PARAMETERS The turbine is used to generate the rated parameter (210 MW) with steam parameter 149Kg/cm2 & Temp 537 C. But in the start up, or due to some process error, the steam parameters may not match the pressure/ temp bands. For this during start up steam parameters are checked & if is in the safe zone, the permission have to be obtained from ATRS to allow the steam entry to turbine. In running condition the following parameters have to be checked:-

TRIPPING FROM ANALOG PROCESS PARAMETERSFor a single parameter three field signals are taken to all three TPR processors. Processor selects the middle value input for processing. It compares this with a set point and gives a binary output for alarm or trip. One binary output (high/low) from each processor is sent to two SECONDARY CPU cards. This card processes 2/3logic for processors output and energises two pair of relays (r1, r2 and s1, s2) for a single signal. These two pairs of relays energise 94Tx1 and 94Tx2.

2a. STEAM TEMP VERY HIGH/ VERY LOW: - The value of steam temp is measured in the before the steam entry to the STOP valves for processing. Three thermocouple probes are fitted for measuring & each input is multiplexed to 3 times for processing in three nos. of CPU of TPR panel. In each CPU, three inputs are processed for checking the validity, and the average values of the valid signal are taken as reference signal. It is then compared with the very high value (564 c) & very low value (428 c) and initiates the corresponding trip signal. The very low value signal is again checked for passing whether the MW load is passed more than 40% (i.e. 82 MW) once. If that is true, then the trip signal is passed. 2b. STEAM PRESS. VERY LOW:- The value of steam press is measured by press transmitters before the steam entry to the STOP valves for processing. Three transmitters (left- one no., right two nos.) are fitted for measuring & each input is multiplexed to 3 times for processing in three nos. of CPU of TPR panel.

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In each CPU, three inputs are processed for checking the validity, and the average values of the valid signal are taken as reference signal. It is then compared with the very low value (< 60 Kg/cm2) and initiates the corresponding trip signal .The signal is passed if the MW load is passed more than 40% (i.e. 84 MW) once. If that is true, then the trip signal is passed and operates the TLR. In each CPU, three inputs are processed for checking the validity, and the average values of the valid signal are taken as reference signal. It is then compared with the very high value (564 c) & very low value (428 c) and initiates the corresponding trip signal. The very low value signal is again checked for passing whether the MW load is passed more than 40% (i.e. 82 MW) once. If that is true, then the trip signal is passed. 2c. LPT Exhaust Steam Temp Very High: - The temp of the exhaust steam of turbine entering to condenser is very vital. As in the condenser, the steam is cooled by CW water. If the temp is more, chance is there the proper cooling could not be done. Some steam may remain in steam condition, which is not desirable as the pressure inside the condenser rises from vacuum. The alarm value for the temp is 90 C & turbine trip value is 110 C. 3 TRIPPING FROM OTHER SOURCES 3a. TRIP COMMAND from control desk/from VPC: - If we manually trip the turbine. This is interlock (not protection). 3b. TRIP COMMAND from ASD: - ASD stands for Automatic Shut Down of turbine. Logically if ASD command is given to turbine, if gradually reduce the load & then issues the generator circuit breaker open command & then turbine trip command. Again this is an interlock, not protection. 3c. Boiler Trip: - MFT stands for master fuel relay. If MFR operates in Boiler, it means all the fuel input to the boiler is closed. In other terms it signifies that boiler is not generating any new steam. It directly gives a trip commend to trip the turbine with a small delay (approx 5 sec.). 3d. Generator Trip: - If the generator trips in class A mode or in Class B mode, it issues a direct trip command to turbine. But in case of generator tripping in class C mode, no commend is issued to trip the turbine. In this case turbine will continue to run in spite of generator CB open (in class C mode). 3e. Liquid in terminal bushing of generator:- If there is a leakage in the bushing, oil may came out from the bushing, it is collected in pot & if there is a certain level it operates a LLD (liquid level switch). If two nos. of this type switch operates it generates the trip command. 3f. Cold Gas Temp Very High (after hydrogen cooler of generator);- 550 C. 3g. Air temp high after main exciter;- Trip value = 900 C. 3h. Seal oil temp very high: - If the temp of seal oil increases beyond normal value, it indicates there may be some rub inside the generator. For detail checking, we have to stop both the generator & turbine. (Trip value setting = 550 C) 3i. Condenser vacuum very low: - The residual steam, after work done in the turbine is extracted into the condenser by keeping the condenser at vacuum. If, by chance, the vacuum is not properly maintained, the extraction process hampers, creating disturbance in the steam circuitry. Chances are there, that water in the hotwell enters into turbine (LP) & damages the blades. The alarm value =600 mm of Hg & trip value = 530 mm of Hg. TURBINE AUXILIARY EQUIPMENTS Auxiliary Oil Pump (AOP):- This pump is stared for generation of control oil during starting of the turbine. The MOP (main oil pump) is coupled with the turbine rotor & is designed to produce sufficient oil pressure after the rotor is rotated to a certain value. Takes AUTO START if DG in operation, or control pressure < 5 Kg/cm2. AUTO STOP if control oil press. > 8 Kg/cm2 and turbine speed > 2950 rpm. Manual START / STOP possible. Emergency Oil Pump (EOP), AC :- This is functional for emergency supply of lubrication oil to all the bearings. AUTO START if the lub oil press < 1.1 Kg/cm2 or AOP trips. Stop is by manual only. Manual start possible.

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Emergency Oil Pump (EOP), DC:- This is functional for emergency supply of lubrication oil to all the bearings in case AC power is not available in case of major power failure. AUTO START if the lub oil press < 1.1 Kg/cm2 or AOP trips. Stop is by manual only. Manual start possible. Jacking Oil Pump (JOP), AC:- Jacking oil is used when then the turbine is on turning gear for lifting the rotor by this oil press, So that rotor floats on this high press oil. The normal discharge press is 150 Kg/cm2. AUTO START at turbine speed < 400 rpm. AUTO STOP at turbine speed > 500 rpm. Manual START/STOP also possible. Jacking Oil Pump (JOP), DC:- The pump is the same type as stated above but DC driven. AUTO START if ac driven JOP trips or ac power failure of JOP (ac) or Jacking oil press < 150 Kg/cm2 and turbine speed < 400 rpm. Manual START/STOP also possible. Turning oil supply valve :- For slow speed rolling of turbine, here oil pressure is used to pressurise the turning gear. The oil supplied is taken from the AOP discharge press & fed to turning gear through a valve (on/off type), named turning oil supply valve.

AUTO CLOSE by turbine speed > 400 rpm. Manual START/STOP also possible. Drain valves:- There are a no. of drain valves in the turbine, the stop valves & the steam carrying pipes. The general logic is to keep the drains open during start up, and after synchronizing gradually close them in a grouped manner. Extraction check valves:- The extracted steam from turbine is used as heat source in the heaters for heating the condensate flowing from CEP to boiler DRUM. There are total 6 nos. of extractions going to HPH (2 nos.), Dearator (1 no.) & LPH (3 nos.). In each of the extraction lines one check valve is provided to pass the steam in the heaters in normal running condition. But in abnormal condition, it prevents the steam/water ingress into the turbine. When the steam press is adequate inside the turbine or lift of the control valves (i.e. secondary oil press) is adequate & corresponding heater level is adequate the check valves are open to supply the steam to the corresponding heater. If the conditions are not true & in case of turbine trip all the extraction lines are closed. SPECIAL FEATURE OF THE TURBINE Load shedding relay (LSR) ;- The LSR is a control device to prevent the acceleration of the turbine speed by the sudden load rejection (load shedding). In case of sudden load rejection from near about full load, turbine speed may reach high value, which is dangerous for the machine. The mechanical speed governor takes some time to adjust with the new speed feedback & lower the speed by lowering the oil press. To prevent this one device, named LSR is fitted inside TPR panel. It senses the load change rate & if the rate is higher than a pre-defined value it operates a relay (LSR). The relay in turn power two nos. of solenoid valves, the first of which drains the oil from the aux secondary oil, thus closing the HP control valves through secondary oil to HP CV. The second one drains the secondary oil from the IP control valve, thus closing the IP control valve. The action stands for a max of 1 second, after which the normal action through oil lines as per requirement takes place. In total the transient speed rise (due to load shedding) is kept in a small range by momentary closing the control valves thus reducing the steam intake.

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AUTOMATIC TURBINE TESTING (ATT) :- The unique feature of this type of turbine that in turbine running condition, the oil path of the trip lines can be tested for their healthiness & readiness. The load should be < 80% (i.e. 164 MW) for the testing. The following tests can be done 1 Emergency Governor Test 2 Solenoid trip devices test 3 Thrust failure protection device test 4 Vacuum tripping test AUTOMATIC VALVE TESTING (AVT): - As described earlier, the stop valves & the control valves can also be tested on load in a phased manner for their healthiness & readiness. The stop valves & the control valves are grouped into four categories as under & testing can be done one group at a time. First the control valves are closed & then the stop valves. The load should be within 40% to 80% (i.e. within 84 MW to 168 MW) for the testing. Test of MSV (Left) & MCV 1, MCV 3. Test of MSV (Right) & MCV 2, MCV 4. Test of RSV (Left) & ICV (Left). Test of RSV (Right) & ICV (Right).

a1 & a2

: Same logic processed & output by CPU – 1.

B1 & b2

: Same logic processed & output by CPU – 2.

( i.e if CPU – 1 malfunctions CPU-2 ensures the trip & vice-versa. a1 & a2 ( two nos. are used if a1 or a2 relay malfunctions . same true for b1 & b2. )

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53 CYCLE EFFICIENCY Definition of cycle: The object of all heat engines is to convert heat into mechanical work. In all such engines we use some substance, termed the ‘working substance’ or ‘working fluid’ to which we supply heat, so causing the working substance to expand, and in overcoming some external resistance to perform a certain amount of mechanical work. After the expansion process , we have some cold ‘body’ or receiver of heat to which the working substance rejects heat before taking in a new supply of heat from the hot body or source of heat. The working substance is said to have undergone a cycle of changes of state when, after starting from some definite initial condition receiving a supply of heat, expanding and performing mechanical work and finally rejecting that quantity of heat which can not be converted into work, it is brought back to its initial state or condition. A single cycle is shown below how it works:

State change from 4 to 1 ( in Boiler)

State change from 1 to 2 ( in Turbine)

State change from 2 to 3 (in condenser).

State change from 3 to 4 (in pump)

In the above cycle the working fluid is water. The burning of fuel is transferred to water in the Boiler (B) to generate steam at a high pressure and temperature, which then expand s in the turbine (T) to a low pressure to produce shaft work. The steam leaving the turbine is condensed into water in the condenser (C) where cooling water takes the heat released during condensation. The water is then fed back to the boiler by the pump (P) and the cycle goes on repeating itself. The working substance water thus follows along the B-T-C-P path. Since the fluid is undergoing a cyclic process, there will be no net change in its internal energy over the cycle (Ф d E = O) and subsequently the net energy transfer to work from the fluid. ∑ Cycle Ø net = ∑ Cycle W net or Q1-Q2 = Wt – Wp Where Q1 = heat transferred to the working fluid , KJ/kg. Wt = Work transferred from the working fluid KJ/Kg Wp = Work transferred into the working fluid KJ/Kg. The efficiency of the vapour power cycle would thus be η Cycle = (W net / Q1) = (Wt – Wp)/ (Q1-Q2) / (Q1) = 1- (Q2 ) / ( Q1) The ideal rankine Cycle : Fig.-1 shows the simplified flow diagram of a Rankine cycle. Fig. -2 & Fig. – 3 show ideal Rankine cycles on the PV & T-S diagrams respectively. The curved lines to the left of the critical point (CP) on both diagrams are loci of all saturated liquid lines. The regions to the left of these are the sub-cooled liquid regions. The curved

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lines to the right of CP are the loci of all saturated vapour points and are the saturated vapour lines . The regions to the right of these lines are the superheat regions. The regions under the dome represent the two phase (liquid)/vapour) mixure region, sometimes called wet region . Cycle 1-2-3-4-B-1 (Fig.2) is a saturated Rankine cycle , meaning that saturated vapour enters the turbine. Cycle 1´ -2´ -3-4-B-1´ , Fig.3 is a superheat Rankine cycle, meaning that superheated vapour enters the turbine. The cycle consist of the following four processes . 1-2 OR 1´ -2´ : Adiabatic reversible expansion through the turbine. The exhaust vapour at 2 or 2´ is usually in the two phase region. 2-3 or 2´ -3 : Constant temperature and being a two phase mixture process constant pressure heat rejection at condenser. 3-4 : Adiabatic reversible compression of saturated liquid by the pump. Line 3-4 will be almost vertical line on the PV & T-3 diagram because the liquid is essentially incompressible and the pump is adiabatic reversible. 4-1 or 4-1´ : Constant pressure heat addition in the boiler. The portion4-B represents bringing the sub-cooled liquid, 4 to saturated vapour at constant pressure and temperature . This occurs in the water wall portion of boiler). Portion 1-1´ in the superheat cycle represent heating the saturated vapour at 1 to 1´ (This occurs at superheater section)

Cycle analysis : Consider unit mass of working fluid Heat added (from SFEE of Boiler Q1 = h1 -h4 Turbine work – Wt = h1 – h2 Heat rejected Q2 = h2-h3 Pump work Wp = h4-h3 Q1 - Q2 Wnet Efficiency = η Rankine = = Q1 Q1 = (Wt –Wp) / Q1 = (h1-h2) (h4-h3)/(h1-h4) ………….. (A) Now consider pump work : Since , pump handles incompressible fluid, its specific volume undergoes little change with an increase in pre. For reversible adiabatic compression, if we combine first and second law of thermo dynamics, we will get following result From first law,

dQ = du +pdv ……… (1) dQ = Heat transfer dv= Change in volume du= Change in internal energy P= Pressure From second law, we can define entropy and change in entropy is given by. dQ rev. = Tds ………. (2) T = Temperature Ds = Change in entropy

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Hence, Tds =du+pdv …… (3) From (1) & (2) again h=u + PV (H= Enthalpy constant ) Dh=du+pdv + vdp ……. (4) Hence, from (3) & (4) Tds = dh-pdv-vdp+pdv=dh-vdp So Tds-dh-vdp ….. (5) Now, for adiabatic compression (reversible) work, ds = O Hence dh =vdp Now for our case (i.e. for unit mass of working fluid). Dh4 =vdp4=ƒ + vdp (for 3-4 process) h4-h3 =V(P4-P3) h4-h3 = V(P1-P2) (Since specific volume is constant for incompressible fluid. P4=P1 & P3=P2 from TS diagram Fog.3 Again from Fig.3 Pump work = (h4-h3 ) = V(P1-P2) usually pump work is very very small compared to turbine work sometimes neglected . Without pump work equation ‘A; reduced to η Rankine = (h1-h2) / (h1-h4) While portion (unshaded area) = W net shaded area = Q2 . Fig.-A Q2 + W net = Q1 Various losses discussed on T-S plot (a) Piping loss: Pressure loss due to friction and heat loss to the surroundings are the most important piping losses. (b) Turbine losses : SFEE of turbine will give h1=h2 +Wt + Q loss Wt h1-h2 Q loss

For reversible expansion process, the path will be 1-2s. For an ordinary, Turbine the heat loss is small and actual turbine work is less than the reversible work out put and in that case h2> h2s, that means steam leveling the turbine will have more enthalpy than the ideal case. If heat loss is more, then the end state of steam from the turbine will be h2 . Isentropic efficiency of a turbine is given by ηT = (h1-h2) (h1-h2s) (c ) Condenser loss : CARNOT CYCLE The carnot cycle is an ideal but non-practical cycle giving the maximum possible thermal efficiency for a cycle operating on selected maximum and minimum.

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Temperature ranges. For the Carnot cycle 1-2-3-4 in Fig.B compressing a very wet steam at state 3 would require a compressor of size and cost comparable with the turbine, it would absorb work comparable to that developed by the turbine and its life would be short because of blade erosion and cavitations problems due to excessive moisture. For the cycle 1-2-5-6-1, the pump work (h6-h5) is again very high and it is impossible to supply heat at infinite pressures and at constant temperature from state – 6 to state -4. So the Carnot cycle can not be realized in practice, but sets the upper limit to which the cycle efficiency of any thermal plant can be raised. For both the cycles 1-2-3-4-5-6, the cycle efficiency is given by ηmax = 1 –(T2)/(T1) = η carnot MEAN TEMPERATURE OF HEAT ADDITION. If we draw a rectangle which has the base equal to line 2-3 (Heat rejected to condenser) and its area bounded by the Rankine cycle process then height of the rectangle 3-5 defined as the mean temperature of heat addition ™. Q1 = h1 - h4 = Tm (S1-S4) Tm=( h1 - h4) / (S1-S4) ; Q2 = h2-h3 = T2(S1-S4) = 1-(T2)/ ( Tm). Where T2 is the temperature of heat rejection. The lower is the T2 for given Tm i.e. lower is the condenser pressure the higher will be the efficiency of the Rankine cycle . But the lowest practicable temperature of heat rejection is the temperature of surroundings. The saturation pressure corresponding to this temperature is the minimum pressure to which steam can be expanded in the Turbine. Effect of main steam pressure (Ref. Fig.5) If the operating steam pressure at which heat is added in the boiler increases from P1 to P2 when the max temp. (T1) and exhaust pressure (Po) are fixed, the mean temperature Tm of heat addition will increase, since Tm between 7 & 5 is higher than between 4 & 1 η = 1 – (T2) / ™ from this equation it is clear efficiency will increase.

But at the same time , if inlet pressure increases from P1 P2, the ideal expansion line shifts to the left and the moisture content at the turbine exhausts increases because (X6< X2 ). If moisture content of steam in the later stages of turbine is high, the water particles along with the vapour coming out with high velocity strike the blade and erode their surfaces as a result of which the longevity of the blade decreases. From this consideration, the moisture content at the turbine exhaust is not allowed to exceed 12%; from this limitation we can get maximum operating steam pressure. Rated pressure at Bk.TPP is 149 KSC. Effect of superheat: If the initial temperature T1 increases (Fig.6) to T1 mean temperature of heat addition Tm will increase. If steam expansion is finished in the two phase region, an increase of the initial steam; temperature will diminish the wetness fraction of the steam in the last stages of turbine. Normal initial temperature, maintained at 540°C in thermal power plants. A further increase of the temperature of superheating is restricted by the possibility of modern metallurgy and requires substantially higher expanses on power station construction.

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Effect of Exhaust pressure on Rankine Cycle: Exhaust pressure of turbine is commonly known as back pressure and it is equal to vacuum value maintained in condenser of Thermal Power Plant. A decrease of the pressure of exhaust steam Po at the same initial steam parameters, lower the temperature of heat rejection. A decrease of final pressure results in a higher average temperature difference between the supplied and removed heat, therefore, a higher available heat drop and hence a higher thermal efficiency of the cycle. The theoretical limit of pressure reduction in a cycle is determined by the saturation temperature at the final pressure (Po) which must not be less than the temperature of surroundings otherwise, it would not be possible to transfer heat during condensation, the surroundings. At lower value of pressure , specific volume of steam increases, for that reason to get lower value of exhaust pressure (means higher value of vacuum) in condenser, a greater cross section and dimensions of the last stages of the turbine ,(which makes the turbine more expensive), to accommodate large volume of steam flow . Again maintenance of high vacuum in the condenser is trouble some due to air ingress from outside and noncondensable gasses in feed water. An increase in the exhaust pressure increases the temperature of heat rejection. Here change in mean temperature of heat addition is negligible. From the equation of Rankine Cycle efficiency η Rankine = (1(To/Tm), it can be easily decided that η Rankine will be less for higher value of exhaust pressure of Turbine (lower value of vacuum). So, efficiency of Rankine cycle will be less for low vacuum of condenser. Practically, it is seen that, lower value of vacuum, increases exhaust temperature. Lower value of vacuum reduces the driving force of steam, which is required for driving out the steam from turbine into condenser. For this reason, steam delays to be driven out from the turbine and last stages of LP turbine are subjected to charning effect. As a result LP turbine blades and glands are subjected to higher temperature than the designed temperature. Effect of Reheat: It has been already seen that initial temperature of Rankine cycle is restricted because of limitation of high temperature metallurgy and related expanses. If very high pressure is used in power plant, keeping initial temperature constant (540°C ), then dryness fraction at the turbine exhaust reduces and for that reason to limit the dryness fraction at the LP turbine exhaust to 0.88, reheat has to be adopted. In that case all the steam after partial expansion in the HP turbine is brought back to the boiler, reheated by combustion gases and then fed back to the turbine for further expansions in IP/LP turbine. The flow, T-S & h-s diagrams for the ideal Rankine cycle with reheat are shown in the figure . In the first step, steam expands in the higher pressure (H.P) turbine from initial state to some intermediate pressure (1-2). The steam is reheated at constant pressure in the Boiler (2-3) and the remaining expansion (process-3-4) of steam is carried out in the low pressure (L.P) turbine . For 1Kg of steam . Q1= h1-h6s +h3 -h2s Q2= h4s -hs Q2 = Wt = h1-h2s+h3-h4s, Wp=h6s-h5 η = (WT – Wp) / Q1= (h1-h2s+h3-h4s) Steam rate =3600 / Wnet kg/kwh Heat rate =3600/ η kg/KWH If higher pressure (P1) is used without reheat, the ideal Rankine cycle would have been 1-4-5-6 with the use of reheat , the area 2-3-4-4´ has been added to the basic cycle. It is obvious that net work out of plant increases with reheat, because (h3-h4) is greater than (h2-h4 ) and hence the steam rate decreases whether the cycle efficiency improves with reheat depends upon whether the mean temperature of heat addition of reheat cycle is higher than the basic cycle. In practice , reheat gives a marginal increase in cycle efficiency by in increases net work out of the cycle as it makes possible the use of higher pressure, keeping the quality of steam at turbine exhaust within permissible limit. The quality improves from (X´- X4 ) by use of reheat. A low reheat pressure may bring down mean temperature of heat addition and hence cycle efficiency. A high reheat pressure increases the moisture content at LP turbine exhaust. Thus the reheat pressure is optimized, and the optimum reheat pressure for most of the power plant is about 0.2 to 2.5 of initial steam pressure. Effect of Regeneration: In order to increase the mean temperature of head addition ™ , attention was so far confined to increasing the amount of heat supplied at high temperatures such as increasing super-heat , using higher pressure and

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temperature of steam and using reheat . The mean temperature of heat addition can also be increased by decreasing the amount of heat added at low temperature in Boiler. Let us calculate the mean temperature of heat addition at regenerative feed heating system and without regenerative system. In first case Tm® = (h1-h10)/(S1-S10) And in second case Tm = (h1-h6) / (S1-S6) It is clear from the T-S diagram that (h1-h6) > (h1-h10) So Tm® > Tm from this relation it can be said that the cycle efficiency with regenerative feed heating is greater than without regeneration.

Efficiencies in a Steam Power Plant: Boiler efficiency = η boiler (rate of energy absorption by water to form steam) rate of energy release by the combustion of fuel). Ws(h1-h4) / (Wf x C.V.). Where Ws = Steam generation rate Wf = Fuel burning rate C.V. = Calorific Value. η generator = (Electrical output at generator terminal)/(brake output of the turbine). η Aux. = (Net power transmitted by generator) / (gross power produced by the plant). So, η boiler x η cycle x η turbine (mech.) X η generator X η Aux. = η overall For modern power plants typical values are: η boiler = 0.92; η cycle = 0.44; η turbine = 0.95; η generator = 0.93; η Aux. = 0.95 So η overall = 0.92 x 0.44 x 0.95 x 0.93 x 0.95 = 0.34 = 34% TURBINE EFFICIENCY For the steady flow operation of a turbine, neglecting changes in K.E. and P.E. Maximum or ideal work output per unit mass of steam (WT) max = (WT) Ideal = (h1-h2s ) = Reversible and adiabatic enthalpy drop in turbine. This work is however, not obtainable, since no real process is reversible. The expansion process is accompanied by irreversibilities. The actual final state ‘2’ can be defined, since the temperature, pressure and quality can be found by actual measurement. The actual path 1-2 is not known and its nature is immaterial, since the work output is here being expressed in terms of change of a property, enthalpy. Accordingly, the work done by the turbine in irreversible adiabatic expansion from 1 to 2 is (WT ) actual = h1-h2 This work is known as internal work, since only the irreversibilities within the flow passages of turbine are affecting the state of steam at the turbine exhaust. So, Internal output = Ideal output –Friction and other losses within the turbine casing. If Ws is steam flow rate in kg/h. Internal output =Ws (h1-h2) KJ/h. The internal efficiency of turbine is defined as

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η internal = (Internal output) / Ideal output) = (h1-h2) / (h1-h2s) . Work output available at the shaft is less than the internal output because of the external losses in the bearings etc. So, break output or shaft output. = Internal output – Internal and external losses. The brake efficiency of turbine is defined as η mech = (brake output)/ (Internal output) = (KW x 3600) / Ws (h1-h2s). The mechanical efficiency of turbine is defined as η mech = (brake output)/ (Internal output) = (KW x 3600) / Ws (h1-h2). Work output available at the shaft is less than the internal output because of the external losses in the bearings etc. So, Brake output or shaft output. = Internal output – External losses. = Ideal output – Internal and External losses. The brake efficiency of turbine is refined as η brake = (brake output)/ (Ideal output) = (KW x 3600) / Ws (h1-h2s). The Mechanical efficiency of turbine is defined as η mech = (brake output)/ (Internal output) = (KW x 3600) / Ws (h1-h2). So, brake = η internal X η mech

TURBINE HEAT RATE CALCULATION What is heat rate? – The heat rate is defined as the amount of heat required to generate unit power, i.e. heat required to produce 1 KWH. Turbine heat rate is defined as the heat required i.e. supplied through main steam to generate one (1) KWH electricity.

Calculation formula for the heat rate Heat Rate =

Main steam Enthalpy) - (Final Feed water flow x final feed water Enthalpy) + (Hot Reheat Steam Flow X Hot Reheat Steam Enthalpy) – Cold Reheat Steam Flow X Cold Reheat Steam Enthalpy)

Parameter M.S. Flow M.S. Enthalpy F.F. Flow HRH Steam Flow FF flow Enthalpy HRH Steam Flow Enthalpy CRH Steam Flow CRH Steam Enthalpy

Generator output

Unit T/H K Cal/Kg. T/H T/H K Cal/Kg. K Cal/Kg. T/H K Cal/Kg.

380

POWER PLANT SIMULATOR TRAINING INSTITUTE Bakreswar Thermal Power Project : Generator output Turbine Heat Rate

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MW K Cal/Kg.

Turbine Heat Rate at Test Load HR TG= (QMS X HMs – Qfw x hfw + QHRS x HHRS-QCRS x HCRS – QRSP X HRSP/ LG Where HRT/G Turbine heat Rate at test load :

QMS HMS QFW HFW QHRS HHRS QCRS HCRS QRSP HRSP

: : : : : : : : : :

MS flow Enthalpy of MS Final feed water flow Enthalpy of final feed water HRH steam flow Enthalpy of HRH flow CRH steam flow Enthalpy of CRH flow Reheat Attemperation spray flow

Correction for Turbine Heat Rate When the actual operating conditions are deviated from those specified for the guarantee values or expected values at the tests, the measured turbine heat rate shall be corrected according to the following formula. HRT/GM x (1-∆1 + ∆2+ ∆3 + ∆4+ ∆5+ ∆6+ ∆7+ ∆8+ ∆9+ ∆10) HRT/GC= 100 Where , HRT /GC HRT/GM Correction factor

: : :

Corrected Turbine heat rate at test load Measured turbine heat rate at test load

∆1 : MS pressure (%) ∆2 : MS temperature( % ) ∆3 : HRH Temperature (%) ∆4 : Condenser Vacuum (%) ∆5 : Reheater Pressure drop (%) ∆6 : Make up water flow (%) ∆7 : Power factor (%) ∆8 : Auxiliary Steam flow (%) ∆9 : Reheater spray water flow (%) ∆10 : Final feed water Temperature (%) All the above calculations are done according to the test code ASME PTC – 6 –Steam turbine HP turbine efficiency

:

84.71%

: : : :

92% 88.8% 2551 K cal/KWH 2289 K cal/KWH

IP turbine efficiency LP turbine efficiency Unit Heat rate Net turbine heat rate

ONE LINE VALVES OF UNIT # 1 AT 210MW.

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TABLE – 1 OFF DESIGN CONDITIONS: APPROXIMATE EFFECT ON ACTUAL HEAT RATE

Parameter

Deviation

Effect on Heat Rate

Main Steam Temp. Main Steam Pr. Reheat Temp. Reheat Spray Back Pressure Excess O2 Flue Gas Temp. Excess Make up Auxiliary Power

-5°C -1Kg/cm² -5°C + 1% (Throttle flow) + 1mm HgA +1% O2 +5°C + 1% + 1%

+2.3 k cal /KWH +1 k cal /KWH +2.3 k cal /KWH 2.4 to 3.6 k cal /KWH +2.0 k cal /KWH +7.2 k cal /KWH +4.6 k cal /KWH + 6 k cal /KWH +20 k cal /KWH

TABLE - 2 VALUE OF TURBINE EFFICIENCY LEVEL IMPROVEMENT ON A UNIT HEAT RATE OR 2500 K CAL/KWH One % improvement in Effect on Turbine cycle heat Effect on Heat Rate efficiency On rate HP turbine 0.2% Heat Rate 5 kcal KWH IP turbine 0.2% Heat Rate 5 kcal KWH LP turbine 0.5% Heat Rate 12.55 kcal KWH Calculation formula for the heat Rate (Heat Rate = (( Main Steam flow X Main steam enthalpy ) -(Final feedwater flow X final feedwater enthalpy) + (Hot heat steam flow x hot reheat steam enthalpy) - (Cold reheat steam flow x cold reheat steam enthalpy)) / Generator output Ex. 100% load no.FE –GN-179-100-001-1/50 PARAMETER Unit MAIN STEAM FLOW T/H MAIN STEAM ENTHALPY K cal /Kg FINAL FEED WATER FLOW T/H FINAL FEED WATER ENTHALPY K cal /Kg HRH STM FLOW T/H HRH STM ENTHALPY K cal /Kg CRH STM FLOW T/H CRH STM ENTHALPY K cal /Kg GENERATOR OUTPUT LW TURBINE HEAT RATE K CAL/kwh

Data 623.798 816.03 623.798 253.82 559.367 844.25 559.367 735.73 210 1959.1

Calculation procedure of turbine heat rate A. CLACULATION FLOW: Measured flow Deaerator inlet condensate water flow (QDEA) Deaerator inlet condensate water flow is measured by the flow element for the test (F540) HP turbine leak off steam flow (QGL1) HP turbine leak off steam flow is measured by the flow orifice for the test (F150)

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Make up water flow is measured by the station instrument (F460) Auxiliary steam attemperator spray water flow (QSPA) Auxiliary steam attemperator spray water flow is measured by the station instrument (F590) Turbine auxiliary steam flow (QTAS) Turbine auxiliary steam flow (total) is measured by the station instrument (F800) Boiler auxiliary steam flow (QBAS) Boiler auxiliary steam flow (total) is measured by the station instrument (F810) Re-heater attemperator spray water flow is measured by the station instrument (850) B. Calculation of flow Main steam flow (QMS) QMS =Qfw -QRSP –QBAS-QCL Where : Qfw : HP Heater No.06 outlet feed water flow (t/h) QRSP: Reheater attemperator spray water flow (t/h) QBAS: Boiler Auxiliary steam flow (t/h) QCL : Cycle loss = MU ± ∆hot ± ∆dia ± ∆ Boiler (t/h) Where QMU = Make up water fbw from condensate storage tank (I/A) ∆hot –storage increase as decrease of hotwell ∆ dia –storage increased as decrease of decreator ∆ Boiler –storage increase or decrease of boiler drum HP heater No.6 outlet feed water flow (Qfw ) GI=1+ +

hHsd(hfw - hfw1 ) HE4 ( HE6 -hH6d ) (Hh6d-Hh5d) (hfwhfw1) (HE5 -hH5d ) (HE-Hh6d)

G2 = QDEA (1Qfw

hDEa HE4

+

hHsd( hfw1 - hfw2 ) Hfw-hfw1 HE4 ( HE5 -hH5d ) HE6 – hH6d Hh5d(hfw-hfw1)(Hh6d – Hh5d)

-

Hfw3 HE4

-

Htw1-htw2 Hh5D

HE4(HE5-Hh5d)(HE6-Hh6d)

)

G2 G1

=

Where : QDEA hfw hfw1 hfw2 Hfw3 HE6 HE5 HE4 hh6d hh5d hDEA

: : : : : : : : : : :

Deaerator I/L condensate water flow HP Heater No.6 O/L (feed water enthalpy) HP Heater No.6 L/L (feed water enthalpy) HP Heater No.5 I/L (feed water enthalpy) Deaerator O/L feed water enthalpy HP Heater No.6 I/L extraction steam enthalpy HP Heater No.5 I/L extraction steam enthalpy Deaerator I/L extraction steam enthalpy HP heater no.6 O/L drain enthalpy HP heater no.5 drain enthalpy Deaerator I/L condensate water enthalpy

Cold reheat steam flow to the boiler (QCRS) QCRS = QMS-QGL-QE6 Where QMS : Main Steam flow QGL: HP turbine leak off steam flow QE6: HP heater no.6 I/L extraction steam flow Hot reheat steam flow (QHRS)

t/h (Kcal/kg) (Kcal/kg) (Kcal/kg) (Kcal/kg) (Kcal/kg) (Kcal/kg) (Kcal/kg) (Kcal/kg) (Kcal/kg) (Kcal/kg)

(t/h) (t/h) (t/h)

383


QHRS = QCRS + QRSP Where; QCRS: Cold reheat steam flow to the boiler QRSP : Reheater attemperator spray water flow

WBPDCL

(t/h) (t/h)

HP heater No. 6 I/L extraction steam flow (QE6) QE6 = Qfw x (hfw-hfw1)/HE6-hH6d) Where : Qfw : HP Heater No.6 O/L feed water flow HP Heater No.6 O/L feed water enthalpy hfw : Hfw1 : HP Heater No.6 O/L feed water enthalpy HE6 : HP Heater No.6 I/L extraction stream enthalpy HP Heater No.6 O/L drain enthalpy hH6d HP Turbine leak off flow (QGL) QGL = QGL1 + QGL2 + QVLL Where : QGL1 : Gland leak off flow measured by test orifice (t/h) QGL2 : Other gland leak off flow (t/h) QVLL : HP turbine control valve leak off flow (t/h)

t/h (Kcal/kg) (Kcal/kg) (Kcal/kg) (Kcal/kg)

HP Turbine other gland leak off flow (QGL2) HP turbine other gland leak of flow (QGL2) HP turbine other gland leak off flow for which the following design value is taken At 100% load : 0.811 (t/h) At 75% load : 0.61 (t/h) HP turbine control valve leak off flow (QVLL) HP turbine control valve leak off flow, for which the following design value is taken At 100% load : 0.53 At 75% load : 0.53

(t/h) (t.h)

C. Calculation of Enthalpy Enthalpy of HP turbine inlet steam (HMS ) (Kcal/kg) This enthalpy is calculated from HP turbine inlet steam pressure (P100, P102) and temperature (T100,T102,T103). Enthalpy HP turbine outlet steam (HCRH ) (Kcal/kg) This enthalpy is calculated from HP turbine outlet steam pressure (P110) and temperature (T110,T111). Enthalpy of Hot reheat turbine inlet steam (HCRH ) (Kcal/kg) This enthalpy is calculated for LP turbine inlet steam pressure (P206,P207) and temperature (T200, T201,T202,T203). Enthalpy final feedwater (hfw) (Kcal/kg) This enthalpy is calculated from HP heater no.5 O/L feed water temp.(T612), HP heater No.6 I/L feed water pressure (P620) and temp. (T610,611). Enthalpy deaerator O/L feedwater (hfw3) Kcal/kg) This enthalpy is calculated from deaerator outlet feed water pressure (P600, P602, P603, P604) and temp. (T600, T601,T602,T604,T605) Enthalpy of deaerator I/L condensate water (hDEA) ( kcal/kg)

384


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This enthalpy is calculated from deaerator inlet condensate water pressure (p540) and temp. (T540,541). Enthalpy of HP Heater No.6 I/L extraction steam (HE6 ) (kcal/kg) This enthalpy is calculated from HPH heater No.6 I/L steam pressure (P660) and temp. (T660,T661). Enthalpy of HP Heater No.5 I/L extraction steam (HE3 ) (kcal/kg) This enthalpy is calculated from HP heater No.5 inlet steam pressure (P650) and temp. (T650,T651). Enthalpy of deaerator I/L extraction steam (HE4 ) (kcal/kg) This enthalpy is calculated from deaerator I/L steam pressure (P580) and temp (T580,T581). Enthalpy of HP heater No.6 drain (hH6d) (kcal/kg) This enthalpy is calculated from HP heater No.6 I/L steam pressure (P660) and temp. (T662, T663). Enthalpy of HP heater no.5 drain (hHsd) (kcal/kg) This enthalpy is calculated from HP heater No.5 I/L

steam pressure (P650) and temperature (T652,T653).

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Turbine Guideline

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