summer training repart at ipgcl

Summer Training Report at IPGCL

SUMMER TRAINING REPORT JUL-AUG-2010

Indraprastha Power Generation Co. Ltd.

Submitted by PrIyanshu dIxIt Roll.No - 0715340073 SkylIne InstItute of EngIneerIng TecHnology, Greater noIda CONTACT No.- 9 7 1 8 2 2 1 7 2 9

&

Submitted by Priyanshu Dixit [email protected]

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Summer Training Report at IPGCL

Indraprastha Power Generation Co. Ltd.

CERTIFICATE This is to certify that Priyanshu Dixit, student of B-Tech Branch Mechanical, Batch 2007-2011 of Skyline Institute of Engineering & Technology , Greater Noida has successfully completed his industrial training at indraprasth power generation corporation Ltd-IGPCL, New Delhi for Six weeks from 12th July to 23rd Aug 2010. He has completed the whole training as per the training report submitted by him.

Date: _____________

Signature: _________________ (

Date: _____________

)

Signature: _________________

Submitted by Priyanshu Dixit [email protected]

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Summer Training Report at IPGCL

(

)

ACKNOWLEDGEMENTS This project involved the collection and analysis of information from a wide variety of sources and the efforts of many people beyond me. Thus it would not have been possible to achieve the results reported in this document without their help, support and encouragement. I will like to express my gratitude to the following people for their help in the work leading to this report:  Supervisors: for their useful comments on the subject matter

and for the knowledge I gained by sharing ideas with them.;  Coordinator: for organizing and coordinating the B. Tech.

Training 2010.

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IntroductIon IPGCL-PPCL 1. 2.

Indraprastha Power Generation Co. Ltd. (IPGCL) Pragati Power Corporation Ltd. (PPCL)

(GOVT. OF NCT OF DELHI UNDERTAKINGS)

BRIEF PROFILE OF THE COMPANY: Indraprastha Power Generation Co. Ltd. (IPGCL) was incorporated on 1st July,2002 and it took over the generation activities w.e.f. 1st July,2002 from erstwhile Delhi Vidyut Board after its unbundling into six successor companies. The main functions of IPGCL is generation of electricity and its total installed capacity is 994.5 MW including of Pragati Power Station. Its associate Company is Pragati Power Corporation Limited which was incorporated on 9th January, 2001. To bridge the gap between demand and supply and to give reliable supply to the capital City a 330 MW combined cycle Gas Turbine Power Project was set up on fast track basis. This plant consists of two gas based Units of 104 MW each and one Waste heat Recovery Unit of 122 MW. Gas supply has been tied up with GAIL through HBJ Pipeline. Due to paucity of water this plant was designed to operate on treated sewage water which is being supplied from Sen nursing Home and Delhi Gate Sewage Treatment plants. Their Vision: “TO MAKE DELHI – POWER SURPLUS” • • • • •

To maximize generation from available capacity To plan & implement new generation capacity in Delhi Competitive pricing of our own generation To set ever so high standards of environment Protection. To develop competent human resources for managing the company with good standards.

The Power demand in the Capital City is increasing with the growth of population as well as living standard and commercialization. The unrestricted power demand in the summer of year 2000 was 3000 MW and increasing every year @ 6 to 7%. In 2005-2006, it is expected to be 4078 MW and by 2009-10 it will reach 5075 MW. Erstwhile DVB's own generation from RPH, I.P. Station and Gas Turbine Power Station had been around 350-400 MW and Badarpur has been Submitted by Priyanshu Dixit [email protected]

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Summer Training Report at IPGCL

supplying 600-700 MW and the balance was met from the Northern Grid and other sources. To bridge the gap between demand and supply and to give reliable supply to the Capital City, Delhi Govt. had set up 330 MW Pragati Power Project on fast track basis. To cut down the project cycle duration, turnkey contract was awarded to M/s BHEL in May 2000 based on similar project executed by BHEL at Kayamkulam (owned by NTPC). To further ensure reliable and smooth operation of the plant, experience of NTPC was utilized by retaining them as engineering consultant and specification of the Kayamkulam Project were adopted.

Indraprastha Power Generation Co. Ltd. (IPGCL) UNDER IPGCL 3 POWER STATIONS ARE IN OPERATION

• • •

Indraprastha Power Station Rajghat Power Station Gas Turbine Power Station

• Gas TurbIne Power atIon

St

Six Gas Turbine Units of 30 MW each were commissioned in 198586 to meet the electricity demand in peak hours and were operating on liquid fuel. In 1990 the Gas Turbines were converted to operate on natural gas. Later due to growing power demand the station was converted into combined cycle gas turbine Power Station by commissioning 3x30 MW Waste Heat Recovery Units, in 1995-96. Figure 1: Gas Turbine Power Station

The total capacity of this Station is 270 MW. The gas supply has been tied up with GAIL through HBJ Pipeline. The APM gas allocation was not sufficient for maximum generation from the power station. Subsequently with the availability of Regassified -LNG an agreement was made with GAIL in Jan. 2004 for supply of R-LNG so that optimum generation could be achieved. The performance of the station has improved from 49 % in 2002-03 to 70.76 % in 2005-06. Submitted by Priyanshu Dixit [email protected]

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Steam

TurbIne

Steam turbines are devices which convert the energy stored in steam into rotational mechanical energy. These machines are widely used for the generation of electricity in a number of different cycles, such as: • • • •

Rankine cycle Reheat cycle Regenerative cycle Combined cycle

The steam turbine may consist of several stages. Each stage can be described by analyzing the expansion of steam from a higher pressure to a lower pressure. The steam may be wet, dry saturated or superheated. Consider the steam turbine shown in the cycle above. The output power of the turbine at steady flow condition is: Power = m (h1 - h2) Where m is the mass flow of the steam through the turbine and h1 and h2 are specific enthalpy of the steam at inlet respective outlet of the turbine.

The efficiency of the steam turbines are often described by the isentropic efficiency for expansion process. The presence of water droplets in the steam will reduce the efficiency of the turbine and cause physical erosion of the blades. Therefore the dryness fraction of the steam at the outlet of the turbine should not be less than 0.9. Figure 2: Steam Turbine Cycle

PrIncIple

of

OperatIon

and

DesIgn

An ideal steam turbine is considered to be an isentropic process, or constant entropy process, in which the entropy of the steam entering the turbine is equal to the entropy of the steam leaving the turbine. No steam turbine is truly “isentropic”, however, with typical isentropic efficiencies ranging from 20%-90% based on the application of the turbine. The interior of a turbine comprises several sets of blades, or “buckets” as they are more commonly referred to. One set of stationary blades is connected Submitted by Priyanshu Dixit [email protected]

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to the casing and one set of rotating blades is connected to the shaft. The sets intermesh with certain minimum clearances, with the size and configuration of sets varying to efficiently exploit the expansion of steam at each stage.

TurbIne

EffIcIency

Schematic diagram outlining the difference between an impulse and a reaction turbine To maximize turbine efficiency, the steam is expanded, generating work, in a number of stages. These stages are characterized by how the energy is extracted from them and are known as impulse or reaction turbines. Most modern steam turbines are a combination of the reaction and impulse design. Typically, higher pressure sections are impulse type and lower pressure stages are reaction type. Figure 3: Impulse & Reaction Turbine Blade Diagram

Impulse

TurbInes

An impulse turbine has fixed nozzles that orient the steam flow into high speed jets. These jets contain significant kinetic energy, which the rotor blades, shaped like buckets, convert into shaft rotation as the steam jet changes direction. A pressure drop occurs across only the stationary blades, with a net increase in steam velocity across the stage. As the steam flows through the nozzle its pressure falls from steam chest pressure to condenser pressure (or atmosphere pressure). Due to this relatively higher ratio of expansion of steam in the nozzle the steam leaves the nozzle with a very high velocity. The steam leaving the moving blades is a large portion of the maximum velocity of the steam when leaving the nozzle. The loss of energy due to Submitted by Priyanshu Dixit [email protected]

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this higher exit velocity is commonly called the "carry over velocity" or "leaving loss". Figure 4:

Impulse Reaction Turbine

ReactIon

TurbInes

In the reaction turbine, the rotor blades themselves are arranged to form convergent nozzles. This type of turbine makes use of the reaction force produced as the steam accelerates through the nozzles formed by the rotor. Steam is directed onto the rotor by the fixed vanes of the stator. It leaves the stator as a jet that fills the entire circumference of the rotor. The steam then changes direction and increases its speed relative to the speed of the blades. A pressure drop occurs across both the stator and the rotor, with steam accelerating through the stator and decelerating through the rotor, with no net change in steam velocity across the stage but with a decrease in both pressure and temperature, reflecting the work performed in the driving the rotor.

NOTE: IN MOST OF THE POWER PLANTS A IMPULSE-REACTION TURBINE IS USED WHICH IS A MIXTURE OF THE TWO ABOVE MENTIONED TURBINES.

OperatIon

and

MaIntenance

When warming up a steam turbine for use, the main steam stop valves (after the boiler) have a bypass line to allow superheated steam to slowly bypass the valve and proceed to heat up the lines in the system along with the steam turbine. Also a turning gear is engaged when there is no steam to the turbine to slowly rotate the turbine to ensure even heating to prevent uneven expansion. After first rotating the turbine by the turning gear, allowing time for the rotor to assume a straight plane (no bowing), then the turning gear is disengaged and steam is admitted to the turbine, first to the astern blades then to the ahead blades slowly rotating the turbine at 10 to 15 RPM to slowly warm the turbine. Problems with turbines are now rare and maintenance requirements are relatively small. Any imbalance of the rotor can lead to vibration, which in extreme cases can lead to a blade letting go and punching straight through the casing. It is, however, essential that the turbine be turned with dry steam. If water gets into the steam and is blasted onto the blades (moisture carryover) then rapid impingement and erosion of the blades can occur, possibly leading to imbalance and catastrophic failure. Also, water entering the blades will likely result in the destruction of the Submitted by Priyanshu Dixit [email protected]

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Summer Training Report at IPGCL

thrust bearing for the turbine shaft. To prevent this, along with controls and baffles in the boilers to ensure high quality steam, condensate drains are installed in the steam piping leading to the turbine. Speed

regulatIon

The control of a turbine with a governor is essential, as turbines need to be run up slowly, to prevent damage while some applications (such as the generation of alternating current electricity) require precise speed control. Uncontrolled acceleration of the turbine rotor can lead to an over-speed trip, which causes the nozzle valves that control the flow of steam to the turbine to close. If this fails then the turbine may continue accelerating until it breaks apart, often spectacularly. Turbines are expensive to make, requiring precision manufacture and special quality materials. Gas

TurbIne

A gas turbine, also called a combustion turbine, is a rotary engine that extracts energy from a flow of combustion gas. It has an upstream compressor coupled to a downstream turbine, and a combustion chamber in-between. (Gas turbine may also refer to just the turbine element.) Energy is added to the gas stream in the combustor, where air is mixed with fuel and ignited. Combustion increases the temperature, velocity and volume of the gas flow. This is directed through a nozzle over the turbine's blades, spinning the turbine and powering the compressor. Energy is extracted in the form of shaft power, compressed air and thrust, in any combination, and used to power aircraft, trains, ships, generators, and even tanks. Gas turbines are described thermodynamically by the Brayton cycle, in which air is compressed isentropically, combustion occurs at constant pressure, and expansion over the turbine occurs isentropically back to the starting pressure. In practice, friction and turbulence cause: 1. Non-isentropic compression: for a given overall pressure ratio, the

compressor delivery temperature is higher than ideal. 2. Non-isentropic expansion: although the turbine temperature drop

necessary to drive the compressor is unaffected, the associated pressure ratio is greater, which decreases the expansion available to provide useful work. 3. Pressure losses in the air intake, combustor and exhaust: reduces the expansion available to provide useful work.

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Figure 5: Idealised Brayton Cycle

As with all cyclic heat engines, higher combustion temperature means greater efficiency. The limiting factor is the ability of the steel, nickel, ceramic, or other materials that make up the engine to withstand heat and pressure. Considerable engineering goes into keeping the turbine parts cool. Most turbines also try to recover exhaust heat, which otherwise is wasted energy. Recuperators are heat exchangers that pass exhaust heat to the compressed air, prior to combustion. Combined cycle designs pass waste heat to steam turbine systems and combined heat and power (co-generation) uses waste heat for hot water/steam production. Mechanically, gas turbines can be considerably less complex than internal combustion piston engines. Simple turbines might have one moving part: the shaft/compressor/turbine/alternative-rotor assembly (see image above), not counting the fuel system. More sophisticated turbines (such as those found in modern jet engines) may have multiple shafts (spools), hundreds of turbine blades, movable stator blades, and a vast system of complex piping, combustors and heat exchangers. As a general rule, the smaller the engine the higher the rotation rate of the shaft(s) needs to be to maintain top speed. Turbine blade top speed determines the maximum pressure that can be gained, this produces the maximum power possible independent of the size of the engine. Jet engines operate around 10,000 rpm and micro turbines around 100,000 rpm. Thrust bearings and journal bearings are a critical part of design. Traditionally, they have been hydrodynamic oil bearings, or oil-cooled ball bearings. These bearings are being surpassed by foil bearings, which have been successfully used in micro turbines and auxiliary power units. CombIned

Cycle

Power

StatIon

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Systems which are designed for maximum efficiency in which the hot exhaust gases from the gas turbine are used to raise steam to power a steam turbine with both turbines being connected to electricity generators. To minimise the size and weight of the turbine for a given output power, the output per pound of airflow should be maximised. This is obtained by maximising the air flow through the turbine which in turn depends on maximising the pressure ratio between the air inlet and exhaust outlet. System Efficiency: Thermal efficiency is important because it directly affects the fuel consumption and operating costs. Combined Cycle Turbines It is however possible to recover energy from the waste heat of simple cycle systems by using the exhaust gases in a hybrid system to raise steam to drive a steam turbine electricity generating set. In such cases the exhaust temperature may be reduced to as low as 140°C enabling efficiencies of up to 60% to be achieved in combined cycle systems. Thus simple cycle efficiency is achieved with high pressure ratios. Combined cycle efficiency is obtained with more modest pressure ratios and greater firing temperatures. Fuels One further advantage of gas turbines is their fuel flexibility. Crude and other heavy oils and can also be used to fuel gas turbines if they are first heated to reduce their viscosity to a level suitable for burning in the turbine combustion chambers. • •

The Open Cycle efficiency of the plant is about 31% The Closed Cycle efficiency is around 49%

MechanIcal Heat

EquIpments:

recovery

steam generator

A heat recovery steam generator or HRSG is an energy recovery heat exchanger that recovers heat from a hot gas stream. It produces steam that can be used in a process or used to drive a steam turbine. This combination produces electricity more efficiently than either the gas turbine or steam turbine alone. The HRSG is also an important component in cogeneration plants. Cogeneration plants typically have a higher overall efficiency in comparison to a combined cycle plant. This is due to the loss of energy associated with the steam turbine

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Figure 6;Heat Recovery Steam Generator at PPCL

Evaporator Section: The most important component would, of course, be the Evaporator Section. So an evaporator section may consist of one or more coils. In these coils, the effluent (water), passing through the tubes is heated to the saturation point for the pressure it is flowing. Superheater Section: The Superheater Section of the HRSG is used to dry the saturated vapour being separated in the steam drum. In some units it may only be heated to little above the saturation point where in other units it may be superheated to a significant temperature for additional energy storage. The Superheater Section is normally located in the hotter gas stream, in front of the evaporator. Economizer Section: The Economizer Section, sometimes called a preheater or preheat coil, is used to preheat the feedwater being introduced to the system to replace the steam (vapour) being removed from the system via the superheater or steam outlet and the water loss through blowdown. It is normally located in the colder gas downstream of the evaporator. Since the evaporator inlet and outlet temperatures are both close to the saturation temperature for the system pressure, the amount of heat that may be removed from the flue gas is limited due to the approach to the evaporator, whereas the economizer inlet temperature is low, allowing the flue gas temperature to be taken lower. The steam turbine-driven generators have auxiliary systems enabling them to work satisfactorily and safely. The steam turbine generator being rotating equipment generally has a heavy, large diameter shaft. The shaft therefore requires not only supports but also has to be kept in position while running. To minimize the frictional resistance to the rotation, the shaft has a number of bearings. The bearing shells, in which the shaft rotates, are lined with a low friction material like Babbitt metal. Oil lubrication is provided to further reduce the friction between shaft and bearing surface and to limit the heat generated.

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Figure 7: Block Diagram of a Power Plant Which Utilizes the HRSG

Condenser The surface condenser is a shell and tube heat exchanger in which cooling water is circulated through the tubes. The exhaust steam from the low pressure turbine enters the shell where it is cooled and converted to condensate (water) by flowing over the tubes. Such condensers use steam ejectors or rotary motor-driven exhausters for continuous removal of air and gases from the steam side to maintain vacuum For best efficiency, the temperature in the condenser must be kept as low as practical in order to achieve the lowest possible pressure in the condensing steam. Since the condenser Submitted by Priyanshu Dixit [email protected]

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temperature can almost always be kept significantly below 100 C where the vapour pressure of water is much less than atmospheric pressure, the condenser generally works under vacuum. Thus leaks of non-condensable air into the closed loop must be prevented. Plants operating in hot climates may have to reduce output if their source of condenser cooling water becomes warmer; unfortunately this usually coincides with periods of high electrical demand for air conditioning. The condenser uses either circulating cooling water from a cooling tower to reject waste heat to the atmosphere, or once-through water from a river. Figure 8: A Typical Water Cooled Condenser

Figure 9: Showing Exclusive Inside View of Tube Type Condenser Installed at IPGCL Gas Turbine Station

Deaerator

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A steam generating boiler requires that the boiler feed water should be devoid of air and other dissolved gases, particularly corrosive ones, in order to avoid corrosion of the metal. Generally, power stations use a deaerator to provide for the removal of air and other dissolved gases from the boiler feedwater. A deaerator typically includes a vertical, domed deaeration section mounted on top of a horizontal cylindrical vessel which serves as the deaerated boiler feedwater storage tank. Figure 10: Deaerator

Practical considerations demand that in a steam boiler/steam turbine/generator unit the circulating steam, condensate, and feed water should be devoid of dissolved gases, particularly corrosive ones, and dissolved or suspended solids. The gases will give rise to corrosion of the metal in contact thereby thinning them and causing rupture. The solids will deposit on the heating surfaces giving rise to localised heating and tube ruptures due to overheating. Under some conditions it may give rise to stress corrosion cracking. CoolIng

Towers

Cooling towers are heat removal devices used to transfer process waste heat to the atmosphere. Cooling towers may either use the evaporation of water to remove process heat and cool the working fluid to near the wet-bulb air temperature or rely solely on air to cool the working fluid to near the dry-bulb air temperature. Common applications include cooling the circulating water used in oil refineries, chemical plants, power stations and building cooling. The towers vary in size from small roof-top units to very large hyperboloid structures (as in Image 1) that can be up to 200 metres tall and 100 metres in diameter, or rectangular structures (as in Image 2) that can be over 40 metres tall and 80 metres long. Smaller towers are normally factory-built, while larger ones are constructed on site. Figure 11: Fan of Induction Type Cooling Tower

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Figure 12: Outside View of Cooling towers

Figure13: Inside Views of Cooling Tower Left Hand and Right Hand Respectively.

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AUXILIARY SYSTEMS All large generators require auxiliary systems to handle such things as lubricating oil for the rotor bearings, hydrogen cooling apparatus, hydrogen sealing oil, de-mineralized water for stator winding cooling, and excitation systems for field-current application. Not all generators require all these systems and the requirement depends on the size and nature of the machine. For instance, air cooled turbo generators do not require hydrogen for cooling and therefore no sealing oil as well. On the other hand, large generators with high outputs, generally above 400 MVA, have water-cooled stator windings, hydrogen for cooling the stator core and rotor, seal oil to contain the hydrogen cooling gas under high pressure, lubricating oil for the bearings, and of course, an excitation system for field current. There are five major auxiliary systems that may be used in a generator. They are given as follows: 1. Lubricating Oil System 2. Hydrogen Cooling System 3. Seal Oil System 4. Stator Cooling Water System 5. Excitation System DIfferentIal

ExpansIon

In TurbInes

Differential Expansion on a turbine is the relative measurement of the rotor's axial thermal growth with respect to the case. Differential expansion is the difference between the thermal growth of the rotor compared to the thermal growth of the case. Differential expansion monitoring is most critical during a turbine "cold" start-up. A common steam turbine has a thick, heavy case, and a lighter, hollow rotor. Due to the mass of the case it will grow slower than the rotor, so the operator must make sure the case has expanded enough to keep it from making contact with the rotor. To monitor, transducers can be placed on a collar or ramp that have been machined onto the turbine.

DIfferentIal ExpansIon rge Steam TurbInes

Measurement

on La

One of the challenges facing instrumentation engineers in the power generation sector is the accurate measurement of shaft growth relative to casing on large steam turbines. The measurement is commonly referred to as differential expansion and applies to various stages of the turbine – the critical areas being the turbine low and intermediate pressure rotor stages (due their large shaft lengths). From barring the turbine through to run up, the shaft can experience axial expansion of up to 50mm due to the operational temperature rise, depending on configuration and power rating. With today’s steam turbine arrangements exceeding the 900MW Submitted by Priyanshu Dixit [email protected]

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Summer Training Report at IPGCL

barrier this measurement is as relevant as ever and a continuing challenge. Common techniques for measuring large differential expansion ranges include extended range proximity probes against standard flat collars; tapered collars, which offer an effective extended range to a standard probe and magnetic follower arrangements. Large range probes require a sufficient target area to be linear (greater than 2x probe diameter) which is not always available, standard collar arrangements also, do not allow for other shaft movement (not in the axial direction) which can result in significant errors in measurement. The tapered collar arrangements overcome the proximity probe target issue by utilising a smaller probe and through the use of a four probe arrangement can effectively eliminate other movements in the turbine structure that can effect the true differential expansion measurement. However, these solutions are mechanically complex, problematic during commissioning and difficult to maintain calibration. For a number of years Sensonics have been providing a differential expansion measurement solution based on a mark – space technique, which overcomes all of the shortcomings of the above methods. The principle operates on detecting movement on a series of plates attached to the turbine shaft. The shaft target pattern consists of a number of pairs of ‘teeth’ and ‘slots’ surrounding and rotating with the shaft. Each pair of teeth are tapered axially such that alternate teeth taper in opposite directions, the narrow parallel slot between the teeth being at an angle to the shaft axis. A wider parallel slot between each pair of teeth is used to allow the measurement system to identify each pair. The figure 14 below illustrates the technique.

Figure 14: Technique for Measuring Differential Expansion

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The technique operates on measuring pulse widths and detecting changes in the patterns to determine the differential expansion of the shaft. A standard speed probe can be utilised for the pulse measurement and with appropriate signal processing, changes in the probe gap across the measuring range have no effect on accuracy, since it is the shaft transitions that are measured. Therefore the measurement provides a true differential expansion reading and requires no further allowances for movement in the non-axial direction. The technique has no real limit on the measurement range, being restricted only by the plate dimensions. During commissioning a normalised range is calculated by moving the probe across the required measurement window - determining the pulse width ratio at each extreme (T2 and T3 with respect to d). The true differential expansion reading can then be determined from the given formula. A turbine shaft with mark-space plates is illustrated below.

Figure 15: Turbine Shaft With Mark-Space Plates

Sensonics produce a specific measurement module as part of the ‘Sentry’ Turbine Supervisory Equipment Series to carry out the necessary signal processing and to assist with the commissioning activity. The MO8612 utilises a self-tracking threshold technique to ensure signal pulses are measured at the optimum position within the pulse height independent of the proximity probe gap. Specific plate patterns can be selected depending on application through the software interface and custom patterns created if required. It is usual to implement a number a plates around the shaft, the module makes multiple measurements per

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revolution and minimises ‘plate wobble’ through the implementation of averaging algorithms.

FIGURE 16: Sentry’ API670 Turbine Supervisory Equipment Series

While it is usual to implement a number of chevron patterns around the shaft, reality is quite different. From experience the quantity can vary from one set of plates to many - depending on the turbine engineer’s preference. If an uneven distribution is selected it is important the overall balance of the rotating shaft is maintained, with the addition of opposing weights if necessary. The plate pattern is fitted at a position on the rotor section close to where the shaft fits in to the bearing pedestal - this location allows straightforward access to the plate pattern through the bearing cover. The turbine casing and pedestal are mechanically joined in most circumstances, where the pedestal and casing movement is catered for with a sliding base arrangement. At the HP, IP and LP3 locations a bracket assembly fitted to the pedestal cover accepts a standard inductive proximity probe to generate the timing waveforms. Steam

TurbIne

SpecIfIcatIons

Capacity : 34 MW No. of stages : 50 Steam flow : 125 Tonne/hr. Inlet temperature : 502°C Inlet pressure : 40 Kg/cm2 Lube oil grade : SP 46 No. of journal bearings : 5 No. of thrust bearing : 1 Coupled Main Oil Pump (MOP) with turbine shaft Exhaust steam pressure : 3.3 ata Exhaust steam flow : 2.16 Tonne/hr. Exhaust pressure : 0.105 Kg/cm2 Lube oil pressure : 9 Kg/cm2 Over speed trip : >3300 rpm Differential expansion : +6 to -4

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\

Gas

TurbIne

SpecIfIcatIons

Capacity : 30 MW Gas pressure : 20 Kg/cm2 Speed : 5135 rpm Generator speed : 3000 rpm Generation at : 11 KV Exhaust temperature : 560°C Air flow : 490 Tonne/hr. Standard

operatIng

procedure

Standard operating procedure for combined cycle plant Pre Start Checkups No PTW'S should be pending on machine. 64 KV breaker to be in closed position (Unit Transformer). Battery voltage and charger should be healthy. DC Lube Oil Pump should be in healthy position. Gas valve before the scrubber should be open. Diesel engine breaker should be 'IN' condition. CCT/6AC AC temperature should be 22* 2 centigrade. Machine to be 'READY TO START' on CRT. No alarm persisting on protection panel & CRT. 10. Ratching must be ON. 11. One no. seal air fan must be in running condition. 12. Lube Oil level should not be less than E. 13. Cooling water level should be normal. 14. All cooling water valves in TAC must be in open position. 15. Vapour extraction fans must be in service. 16. PHE (Plate Type Heat Exchanger) should be charged, related valves should be in Open condition. 17. Puffing must be ON. 18. AC/DC Oil pump breaker must be 'NORMAL' 19. Excitation breaker should be healthy. 20. Availability of ON base, OFF base, TK1, TK2 Base cooling fans should be ensured. 21. CO2 fire system should be healthy. 1. 2. 3. 4. 5. 6. 7. 8. 9.

DIESEL ENGINE Submitted by Priyanshu Dixit [email protected]

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Fuel oil level should be normal Lube Oil level to be normal Cooling water valves should be in "OPEN' condition Air Blower Turbo Charger valve latch should be in NORMAL condition Exhaust temperature should be less than 150* centigrade. In case of higher temperature machine should be kept on cranking. 6. There should be no lube oil? Water leakages. 7. All wooden/unwanted man material should be removed from site to avoid fire. 1. 2. 3. 4. 5.

AFTER GIVING START COMMAND TO OBSERVE FOLLOWING SEQUENCE OF OPERATION. Diesel Engine idle speed around 900 RPM. Check rise in temperature at the temperature gauge cooling water outlet. 3. Diesel Engine speed to accelerate about 1000 RPM 4. At 1000 RPM Turbine speed excitation appears on AVR display. 5. Firing starts, flame scanners S2, S3, S7, S8 APPEARS AT 1200 RPM approx. 6. Base cooling fan starts. 7. Diesel engine speed to accelerate up to 2300 RPM. 8. Field flashing starts 9. Diesel engine isolates at 60% of turbine speed 10. Turbine comes on fire 11. Synchroniser to be on auto, if not on auto select manual mode and increase voltage.11 KV breaker to be closed manually. 12. M/C lube oil pump stops. 13. TK1 & TK2 fans start. 14. Compressor bleed valve closed. 15. IGV fully opens. 16. Diesel engine stops 1. 2.

WATCH FOLLOWING PARAMATERS WHILE MACHINE ON LOAD. 1. Vibration on bearings. 2. Lube oil header temperature. 3. Lube oil header pressure. 4. Hydraulic oil pressure. 5. Hydraulic trip oil pressure. 6. Battery charger should be healthy. 7. Cooling water pressure. 8. Air sealing system. 9. TAD should < 170 mm. 10. GAD should < 150 mm.

Battery voltage should >120V

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PRECAUTIONS DURING SHUT DOWN 1. 2. 3.

Load comes to zero AC lube oil pump starts Flame cuts off at 2400 RPM

NOTE: ABOVE PROCEDURE IS FOR NORMAL RUNNING, IF PROBLEM PERSISTS TAKE ACTION ACCORDING TO SITE SITUATION.

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